-----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, Bm92NPQ8spOZxsURfOKMBLMx+kydhMPrHgMX9MlY6Mat8p8s9PK8K49tR0veIpCh mCODlFFAqDqXWYztrMbi3A== 0000898430-01-500145.txt : 20010418 0000898430-01-500145.hdr.sgml : 20010418 ACCESSION NUMBER: 0000898430-01-500145 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 37 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010417 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFIC GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000075488 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 940742640 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-02348 FILM NUMBER: 1603859 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4152677000 MAIL ADDRESS: STREET 1: 77 BEALE STREET STREET 2: P O BOX 770000 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 10-K 1 d10k.txt FORM 10-K FOR THE PERIOD ENDED 12/31/2000 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, 2000 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to
IRS Employer Commission Exact Name of Registrant State of Identification File Number as specified in its charter Incorporation Number ----------- --------------------------- ------------- -------------- 1-12609 PG&E CORPORATION California 94-3234914 1-2348 PACIFIC GAS AND ELECTRIC COMPANY California 94-0742640
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) 94177 94105 (Zip Code) (Zip Code) (415) 973-7000 (415) 267-7000 (Registrant's telephone number, (Registrant's telephone number, including area code) 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 Preferred Stock Purchase Rights Pacific Exchange Pacific Gas and Electric Company First Preferred Stock, cumulative, American Stock Exchange and par value $25 per share: Pacific Exchange Redeemable: 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36% Mandatorily Redeemable: 6.57%, 6.30% Nonredeemable: 6%, 5.50%, 5% 7.90% Cumulative Quarterly Income Preferred American Stock Exchange and Securities, Series A (liquidation preference Pacific Exchange $25), issued by PG&E Capital I and guaranteed by Pacific Gas and Electric Company
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [_] Aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 9, 2001: PG&E Corporation Common Stock $2,505 million Common Stock outstanding as of April 9, 2001: PG&E Corporation: 387,137,690 (inc Pacific Gas and Electric Company: shares held by sub) Wholly owned by PG&E Corporation The market values of certain series of First Preferred Stock, for which market prices as of a date within 60 days prior to the date of filing were not available, were derived by dividing the annual dividend rate of each such series of stock by the average yield of all of Pacific Gas and Electric Company's Preferred Stock outstanding for which market prices were available. DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. (1) Designated portions of the combined Annual Report to Shareholders for the year ended December 31, 2000..... Part I (Item 1), Part II (Items 5, 6, 7, 7A, and 8), Part IV (Item 14) (2) Designated portions of the Joint Proxy Statement relating to the 2001 Annual Meetings of Shareholders.. Part III (Items 10, 11, 12, and 13)
TABLE OF CONTENTS
Page ---- Glossary of Terms........................................... iv PART I Item 1. Business.................................................... 1 GENERAL..................................................... 1 Corporate Structure and Business............................ 1 Competition and the Changing Regulatory Environment......... 3 The Electric Industry...................................... 3 The Natural Gas Industry................................... 4 Regulation of PG&E Corporation.............................. 5 Regulation of Pacific Gas and Electric Company.............. 6 Federal Regulation......................................... 6 State Regulation........................................... 6 Licenses and Permits....................................... 6 Regulation of PG&E National Energy Group, Inc. Businesses... 7 Federal Regulation......................................... 7 State and Other Regulation................................. 7 UTILITY OPERATIONS.......................................... 9 Ratemaking Mechanisms....................................... 9 General Rate Case........................................ 9 Cost of Capital.......................................... 9 Electric and Gas Distribution Performance-Based Ratemaking (PBR)......................................... 9 Electric Ratemaking........................................ 10 Rate Stabilization Plan Proceeding....................... 10 General Rate Case........................................ 11 2001 Attrition Rate Adjustment Request................... 12 Revenue Adjustment Proceeding............................ 12 Annual Transition Cost Proceeding........................ 12 Electric Industry Restructuring Implementation Costs..... 13 Electric Restructuring Costs Account (ERCA).............. 13 Revenues from Must-Run Contracts......................... 13 FERC Transmission Owner Rate Case........................ 13 AB 1890 Electric Base Revenue Increase................... 14 Electric Transmission Rates.............................. 14 Post-Transition Period Ratemaking Proceeding............. 14 Gas Ratemaking............................................. 15 Gas Accord............................................... 15 General Rate Case........................................ 15 Gas Procurement Costs.................................... 15 The Biennial Cost Allocation Proceeding (BCAP)........... 15 Public Purpose Programs..................................... 16 Electric Utility Operations................................. 16 Electric Industry Restructuring............................ 16 California Power Crisis.................................. 17 FERC Order............................................... 17 The California Independent System Operator and the California Power Exchange................................ 18 New California Legislation............................... 19
i
Page ---- Recovery of Transition Costs, Wholesale Power Purchase Costs, and End of Rate Freeze............................ 20 Retail Direct Access..................................... 21 Electric Operating Statistics............................... 23 Electric Resources.......................................... 24 Generating Capacity......................................... 24 Hydroelectric Generation Assets............................ 25 Diablo Canyon Nuclear Power Plant.......................... 25 Diablo Canyon Ratemaking................................. 26 Nuclear Fuel Supply and Disposal......................... 26 Insurance................................................ 27 Decommissioning.......................................... 27 Other Electric Resources.................................... 28 QF Generation and Other Power Purchase Contracts......... 28 Bilateral Agreements..................................... 30 Electric Transmission and Distribution..................... 30 Gas Utility Operations...................................... 32 Gas Operating Statistics................................... 33 Natural Gas Supplies........................................ 34 Gas Regulatory Framework.................................... 35 Transportation Commitments.................................. 36 PG&E NATIONAL ENERGY GROUP, INC. ........................... 36 Integrated Power Generation, and Energy Trading and Marketing Business.......................................... 37 Ownership and Operation of Generating Facilities........... 37 New Power Plant Development and Construction............... 37 Contractual Control of Generating Capacity................. 38 Energy Marketing and Trading............................... 38 Description of Generating Facilities....................... 41 Competition................................................ 42 Natural Gas Transmission Business........................... 42 PG&E GT-Northwest (PG&E GTN)............................. 42 North Baja Pipeline...................................... 43 Competition.............................................. 43 ENVIRONMENTAL MATTERS....................................... 45 Environmental Matters....................................... 45 Environmental Protection Measures.......................... 45 Air Quality................................................ 45 Water Quality.............................................. 47 Hazardous Waste Compliance and Remediation................. 48 Potential Recovery of Hazardous Waste Compliance and Remediation Costs.......................................... 49 Compressor Station Litigation.............................. 50 Electric and Magnetic Fields............................... 50 Low Emission Vehicle Programs.............................. 51 Item 2. Properties.................................................. 52 Item 3. Legal Proceedings........................................... 52 Pacific Gas and Electric Company Bankruptcy................. 52 Pacific Gas and Electric Company vs. California Public Utilities Commissioners..................................... 52 Wilson vs. PG&E Corporation and Pacific Gas and Electric Company..................................................... 52 Moss Landing Power Plant.................................... 53
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Page ---- Compressor Station Chromium Litigation........................ 54 Texas Franchise Fee Litigation................................ 55 Item 4. Submission of Matters to a Vote of Security Holders........... 55 EXECUTIVE OFFICERS OF THE REGISTRANTS......................... 56 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters........................................... 59 Item 6. Selected Financial Data....................................... 59 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations..................................... 59 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 59 Item 8. Financial Statements and Supplementary Data................... 59 Changes in and Disagreements with Accountants on Accounting Item 9. and Financial Disclosure...................................... 60 PART III Item 10. Directors and Executive Officers of the Registrant............ 60 Item 11. Executive Compensation........................................ 60 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................... 60 Item 13. Certain Relationships and Related Transactions................ 60 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................................... 61 Signatures.................................................... 68 Independent Auditors' Report (Deloitte & Touche LLP).......... 69 Report of Independent Public Accountants (Arthur Andersen LLP).......................................................... 70 Report of Independent Public Accountants (Arthur Andersen LLP).......................................................... 71
iii GLOSSARY OF TERMS AB 1890........................ Assembly Bill 1890, the California electric industry restructuring legislation AEAP........................... Annual Earnings Assessment Proceeding Alstom......................... Alstom Power, Inc. ATCP........................... Annual Transition Cost Proceeding BCAP........................... Biennial Cost Allocation Proceeding bcf............................ billion cubic feet Betz........................... Betz Chemical Company BFM............................ block forward market BRPU........................... Biennial Resource Plan Update BTA............................ best technology available Btu............................ British thermal unit CARE........................... California Alternate Rates for Energy CCAA........................... California Clean Air Act CEC............................ California Energy Commission CEMA........................... Catastrophic Event Memorandum Account Central Coast Board............ Central Coast Regional Water Quality Control Board CEQA........................... California Environmental Quality Act CERCLA......................... Comprehensive Environmental Response, Compensation, and Liability Act CFCA........................... Core Fixed Cost Account CLF............................ Conservation Law Foundation core customers................. residential and smaller commercial gas customers core subscription customers.... noncore customers who choose bundled service CPA............................ California Procurement Adjustment 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 DWR............................ California Department of Water Resources EDRA........................... Electric Deferred Refund Account EIR............................ environmental impact report EMF............................ electric and magnetic fields EPA............................ United States Environmental Protection Agency ERCA........................... Electric Restructuring Costs Account ESP............................ energy service provider EWG............................ exempt wholesale generator FERC........................... Federal Energy Regulatory Commission GABA........................... Generation Asset Balancing Account Gas Accord..................... Gas Accord Settlement GRC............................ General Rate Case PG&E GTN....................... PG&E Gas Transmission, Northwest Corporation, formerly known as Pacific Gas Transmission Company PG&E GTN Expansion............. PG&E Gas Transmission, Northwest Corporation's portion of the Pipeline Expansion Holding Company Act............ Public Utility Holding Company Act of 1935 Humboldt....................... Humboldt Bay Power Plant HWRC........................... hazardous waste remediation costs
iv GLOSSARY OF TERMS--(Continued) ICIP........................... Incremental Cost Incentive Price IPP............................ independent power producer ISO............................ Independent System Operator kV............................. kilovolts kVa............................ kilovolt-amperes kW............................. kilowatts LEV............................ low emission vehicle LIEE........................... Low-Income Energy Efficiency Mcf............................ thousand cubic feet MDt............................ thousand decatherms 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 NOI............................ Notice of Intent noncore customers.............. industrial and larger commercial gas customers NOx............................ oxides of nitrogen NPDES.......................... National Pollutant Discharge Elimination System NRC............................ Nuclear Regulatory Commission NTP&S.......................... non-tariffed products and services Nuclear Waste Act.............. Nuclear Waste Policy Act of 1982 ORA............................ Office of Ratepayer Advocates, a division of the California Public Utilities Commission PBR............................ performance-based ratemaking PECA........................... Purchased Electric Commodity Account PGA............................ Purchased Gas Account PG&E Expansion................. the Pacific Gas and Electric Company portion of the Pipeline Expansion PG&E ET........................ PG&E Corporation's energy commodities activities, PG&E Energy Trading or PG&E ET PG&E ES........................ PG&E Corporation's energy services operations, PG&E Energy Services or PG&E ES PG&E Gen....................... PG&E Generating Company, LLC and its affiliates PG&E GT........................ PG&E Corporation's gas transmission operations, PG&E Gas Transmission or PG&E GT PG&E GTT....................... PG&E Gas Transmission, Texas Corporation PG&E OSC....................... PG&E Operating Services Company Pipeline Expansion............. PG&E GT NW/PG&E Pipeline Expansion PPPs........................... public purpose programs Price Act...................... Price Anderson Act PRP............................ potentially responsible party PTO............................ Participating Transmission Owner PURPA.......................... Public Utility Regulatory Policies Act of 1978 PVC............................ Pacific Venture Capital, LLC PX............................. California Power Exchange PY............................. Program Year QF............................. qualifying facility
v GLOSSARY OF TERMS--(Continued) RAP............................ Revenue Adjustment Proceeding RCRA........................... Resource Conservation and Resource Act RMR............................ reliability must-run ROE............................ return on common equity ROR............................ rate of return RSP............................ Rate Stabilization Plan RTO............................ regional transmission organization SEC............................ Securities and Exchange Commission SCS............................ Scheduled Coordinator Services SO2............................ sulfur dioxide SoCal Gas...................... Southern California Gas Company SPE............................ special purpose entity SRAC........................... short-run avoided costs TAC............................ Transmission Access Charge TCBA........................... Transition Cost Balancing Account throughput..................... the amount of natural gas transported through a pipeline system TRA............................ Transition Revenue Account TRBA........................... Transition Revenue Balancing Account Transwestern................... Transwestern Pipeline Company TURN........................... The Utility Reform Network USGenNE........................ USGen New England, Inc.
vi PART I ITEM 1. Business. GENERAL Corporate Structure and Business PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. Effective January 1, 1997, Pacific Gas and Electric Company (sometimes referred to herein as the "Utility") and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in the business of providing electricity and natural gas distribution and transmission services throughout most of Northern and Central California. The Utility is primarily regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). 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. On April 6, 2001, Pacific Gas and Electric Company filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdiction of the bankruptcy court. The factors causing the Utility to take this action are discussed in "Management's Discussion and Analysis" and in Notes 2 and 3 of the "Notes to the Consolidated Financial Statements," appearing in the PG&E Corporation and Pacific Gas and Electric Company combined 2000 Annual Report to Shareholders, which information is incorporated by reference into this report. 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. The principal executive offices of PG&E Corporation are located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation's subsidiary, PG&E National Energy Group, Inc. (NEG), is an integrated energy company with a strategic focus on power generation, new power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. NEG businesses include its power plant development and generation unit, PG&E Generating Company, LLC and its affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas Transmission Corporation (PG&E GT); and its wholesale energy and marketing trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy Trading--Gas Corporation, and PG&E Energy Trading--Power, L.P. (collectively, PG&E Energy Trading or PG&E ET). During 2000, NEG sold its energy services unit, PG&E Energy Services Corporation. Also, during 2000, NEG sold its Texas natural gas and natural gas liquids business carried on through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries (PG&E GTT). For more information about NEG's businesses, see "PG&E National Energy Group, Inc." below. In December 2000, and in January and February 2001, PG&E Corporation and NEG undertook a corporate restructuring of NEG, known as a "ringfencing" transaction. The ringfencing complied with credit rating agency criteria enabling NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and PG&E ET to receive 1 or retain their own credit ratings based on their own creditworthiness. The ringfencing involved the creation or use of special purpose entities (SPEs) as intermediate owners between PG&E Corporation and its non-CPUC regulated subsidiaries. These SPEs are: PG&E National Energy Group, LLC which owns 100% of the stock of NEG, PG&E GTN Holdings LLC which owns 100% of the stock of PG&E GTN, and PG&E Energy Trading Holdings LLC which owns 100% of the stock of PG&E Energy Trading Holdings Corporation. In addition, in March 2001, NEG's organizational documents were modified to include the same structural elements as the SPEs to meet credit rating agency criteria. Ringfencing is intended to reduce further the likelihood that the assets of the ringfenced companies would be substantively consolidated in a bankruptcy proceeding involving such companies' ultimate parent, and to thereby preserve the value of the "protected" entities as a whole. The SPEs require unanimous approval of their respective boards of directors, including at least one independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not declare or pay dividends unless unanimously approved by the SPE's board of directors and the company meets specified financial requirements. PG&E Corporation has identified four reportable operating segments. The Utility is one reportable operating segment and the other three are part of NEG (PG&E Gen, PG&E GT, and PG&E ET). Financial information about each reportable operating segment is provided in "Management's Discussion and Analysis" in the 2000 Annual Report to Shareholders and in Note 16 of the "Notes to Consolidated Financial Statements" beginning on page 86 of the 2000 Annual Report to Shareholders, which information is incorporated by reference into this report. As of December 31, 2000, PG&E Corporation had $35.3 billion in assets. Of this amount, Pacific Gas and Electric Company had $22 billion in assets. PG&E Corporation generated $26.2 billion in operating revenues for 2000. Of this amount, the Utility generated $9.6 billion in operating revenues for 2000. As of December 31, 2000, PG&E Corporation and its subsidiaries and affiliates had 20,850 employees (including 18,393 employees of the Utility). The following report includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," and other similar expressions. Actual results could differ materially from those contemplated by the forward- looking statements. Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include: . the reorganization plan that is ultimately adopted by the bankruptcy court; . the regulatory, judicial, or legislative actions (including future ballot initiatives) that may be taken to meet future power needs, mitigate the higher wholesale power prices, provide refunds for prior power costs, or address the Utility's financial condition; . the extent to which the Utility's undercollected wholesale power purchase costs may be collected from customers; . any changes in the amount of transition costs the Utility is allowed to collect from its customers, and the timing of the completion of the Utility's transition cost recovery; . future market prices for electricity and future fuel prices which, in part, are influenced by future weather conditions, the availability of hydroelectric power, and the development of competitive markets; . the method and timing of valuation of the Utility's hydroelectric generation assets; . future operating performance at the Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the future ratemaking applicable to Diablo Canyon; 2 . legislative or regulatory changes, including the pace and extent of the ongoing restructuring of the electric and natural gas industries across the United States; . future sales levels and economic conditions; . the extent to which NEG's current or planned generation development projects are completed and the pace and cost of such completion; . generating capacity expansion and retirements by others; . the outcome of the Utility's various regulatory proceedings; . fluctuations in commodity gas, natural gas liquids, and electric prices and the ability to successfully manage such price fluctuations; . the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant; and . the outcome of pending litigation. As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from results or outcomes currently sought or expected. Competition and the Changing Regulatory Environment Historically, energy utilities operated as regulated monopolies within specific service territories where they were essentially the sole suppliers of natural gas and electricity services. Under this model, the energy utilities owned and operated all of the businesses necessary to procure, generate, transport, and distribute energy. These services were priced on a combined (bundled) basis, with rates charged by the energy companies designed to include all of the costs of providing these services. 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. In recent years, energy utilities faced intensifying pressures to "unbundle," or price separately, those activities that are no longer considered natural monopoly services. The most significant of these services are electricity generation and natural gas supply. The driving forces behind these competitive pressures have been customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to those customers and competitors by providing for more competition in the energy industry. Regulators and legislators required utilities to "unbundle" rates (separate their various energy services and the prices of those services) and to sell their electric generation facilities to outside parties. This was intended to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider. The Electric Industry. In 1998, California became one of the first states in the country to implement electric industry restructuring with the goal of establishing a competitive market framework for electric generation. The framework for electric industry restructuring was established in Assembly Bill 1890 (AB 1890) passed by the California Legislature and signed by the Governor in 1996 which turned over operation of the state's transmission system to the California Independent System Operator (ISO) and the pricing of unregulated generation to the California Power Exchange (PX). Californians were given the choice to purchase electricity from generation providers other than the traditional utilities (such as unregulated power generators and unregulated retail electricity suppliers such as marketers, brokers, and aggregators). For those customers who have not chosen an alternative generation provider, investor-owned utilities, such as Pacific Gas and Electric Company, were to continue to purchase electric power on their behalf. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including those customers who choose an alternative generation provider. 3 Beginning in June 2000, the wholesale price of electric power in California has steadily increased, reflecting a dysfunctional wholesale power market. Under AB 1890, the Utility's electric rates were frozen at levels insufficient to recover the Utility's cost of purchasing power for its customers. Further, the Utility was required to buy all the power it needed to serve its customers from the PX. The combination of these factors created a financial crisis for the Utility and its parent, PG&E Corporation. The Utility's undercollected power purchase costs grew to $6.6 billion at December 31, 2000. As the Utility's creditworthiness deteriorated, the Utility was unable to continue financing these purchases. Federal and state legislators and regulators have recognized that the wholesale power market is seriously flawed and have been seeking solutions to the California electricity crisis. On January 19, 2001, the California Legislature passed and the Governor signed Senate Bill 7X which authorized the California Department of Water Resources (DWR) to purchase electric power for the retail end use customers of California's investor-owned utilities through January 31, 2001. On February 1, 2001, the California Governor signed Assembly Bill 1 (AB 1X) which was passed by the California Legislature during a special session to take effect immediately as an urgency statute. AB 1X authorizes the DWR to purchase power and sell that power directly to the utilities' retail end use customers. For more information about California electric industry restructuring, see "Utility Operations-- Electric Utility Operations--California Electric Industry Restructuring" below. As of December 31, 2000, 24 other states had enacted electric industry restructuring legislation or issued comprehensive regulatory orders, including Texas, Illinois, Pennsylvania, New Jersey, Massachusetts, Rhode Island, New York, and Connecticut. In October 1999, the CPUC issued a decision outlining how the CPUC, in cooperation with other regulatory agencies and the California Legislature, plans to address the issues surrounding distributed generation, electric distribution competition, and the role of the utility distribution companies (such as Pacific Gas and Electric Company) in the competitive retail electricity market. Distributed generation enables siting of electric generation technologies in proximity to electric load (load is a measure of electric power consumed over time). The CPUC decision opened a new rulemaking proceeding to examine various issues concerning distributed generation, including interconnection issues, who can own and operate distributed generation, environmental impacts, the role of utility distribution companies, and the rate design and cost allocation issues associated with the deployment of distributed generation facilities. In July 2000, the CPUC's Division of Strategic Planning and the CPUC's Energy Division issued a report on electric retail markets and distribution services as required by the October 1999 decision. The report proposed that if the CPUC chooses to consider expanding or consolidating competition in the electric industry, the CPUC should (a) separately identify utility services and establish cost-based rates for these services, (b) consider allowing providers of billing and metering services to market directly to customers, (c) consider allowing multiple providers of default service, and (d) investigate whether to allow competition in certain aspects of distribution services that utilities currently perform. There is currently no active proceeding on electric distribution and the role of utility distribution companies. The Natural Gas Industry. 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. FERC Order 636 issued in 1992 required interstate pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate gas pipelines must provide transportation service regardless of whether the customer (often a local gas distribution company) buys the gas commodity from the pipeline. In August 1997, the CPUC approved the Gas Accord settlement agreement (Gas Accord) which restructured the Utility's gas services and its role in the gas market. Among other matters, the Gas Accord separated, or "unbundled," the rates for the Utility's gas transmission services from its distribution services. As a result, the Utility's customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from the Utility. Most of the Utility's industrial and larger commercial customers (noncore customers) now purchase their gas from marketers and brokers. Substantially all residential and smaller 4 commercial customers (core customers) buy gas as well as transmission and distribution services from the Utility as a bundled service. For more information about the Gas Accord and regulatory changes affecting the California natural gas industry, see "Utility Operations--Gas Utility Operations--Gas Regulatory Framework" below. Regulation of PG&E Corporation PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding Company Act). 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 the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, the Utility's dividend policy shall continue to be established by the Utility's Board of Directors as though Pacific Gas and Electric Company were a stand-alone utility company, and the capital requirements of the Utility, as determined to be necessary to meet the Utility'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 the Utility shall maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1% or more. The CPUC also has adopted complex and detailed rules governing transactions between California's natural gas local distribution and electric utility companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility's service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates and information exchange among the affiliates. The rules prohibit the utilities from engaging in certain practices that would discriminate against energy service providers that compete with the utility's non-regulated affiliates. The CPUC has also established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations. In connection with the Utility's November 2000 request for an emergency rate increase, the CPUC ordered that an audit be performed. On January 31, 2001, the CPUC released the report of its consultant of the overall financial position of the Utility, PG&E Corporation, its other affiliates, and the flow of funds between these entities and the Utility. The report covers credit and default relationships, power purchases and cash flows, cash conservation activities, accounting mechanisms to track stranded cost recovery, inter- company cash flows, affiliate earnings in the California energy market, and other matters. On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned utilities, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities' transfer of money to their holding companies since deregulation of the electric industry commenced, including times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed; (3) the transfer by the holding companies of assets to unregulated subsidiaries; and (4) the holding companies' actions to "ringfence" their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding 5 companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies (including penalties), prospective rules, or conditions, as appropriate. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. As described above, on April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the Utility believe that to the extent the CPUC seeks to investigate past conduct for compliance purposes, the investigation is automatically stayed by the bankruptcy filing. Neither the Utility nor PG&E Corporation can predict what the outcome of the investigation will be or whether the outcome will have a material adverse effect on their results of operation or financial condition. Regulation of Pacific Gas and Electric Company Federal Regulation The FERC regulates electric transmission rates and access, operation of the California ISO and the California PX, uniform systems of accounts, and contracts involving the wholesale sale of power. The ISO has responsibility for meeting applicable reliability criteria and assuring the maintenance of adequate reserves. The PX, which has now suspended operations, had the responsibility of conducting an open, efficient auction for matching energy bids to supply with demand bids to purchase energy. Both these entities were subject to FERC regulation of tariffs and conditions of service. In addition, the FERC has jurisdiction over the Utility's electric transmission revenue requirements and rates. The FERC also regulates the interstate transportation of natural gas. Further, most of the Utility's hydroelectric facilities are subject to licenses issued by the FERC. On December 20, 1999, the FERC issued its final rule (Order No. 2000) on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. Typically, the establishment of these entities results in the consolidation of transmission charges imposed by successive transmission systems into a single tariff. The Utility is a participant in the ISO, however the FERC has not yet approved the ISO's status as an RTO under Order No. 2000. The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant (Unit 3). NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities. State Regulation The CPUC has jurisdiction to regulate the following utility functions within California: electric distribution service, gas distribution service, and gas transmission service. The CPUC regulates Pacific Gas and Electric Company's rates and conditions of service, sales of securities, dispositions of utility property, rates of return, rates of depreciation, and long-term resource procurement. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor and confirmed by the State Senate for six-year terms. The California Energy Commission (CEC) has the responsibility to make electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a statewide plan of action in case of energy shortages. In addition, the CEC certifies power plant sites and related facilities within California. The CEC also administers funding for public purpose research and development, and renewable technologies programs. Licenses and Permits Pacific Gas and Electric Company obtains a number of permits, authorizations, and licenses in connection with the construction and operation of its generating plants, transmission lines, and gas compressor station 6 facilities. Discharge permits, various Air Pollution Control District permits, United States Department of Agriculture--Forest Service permits, FERC hydroelectric facility and transmission line licenses, and NRC licenses are the most significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. The Utility currently has 10 hydroelectric projects and one transmission line project undergoing FERC license renewal. Regulation of PG&E National Energy Group, Inc. Businesses Federal Regulation The rates, terms, and conditions of the wholesale sale of power by the generating facilities owned or leased by NEG through PG&E Gen, its subsidiaries, and affiliates, and of power contractually controlled by them is subject to FERC jurisdiction under the Federal Power Act. Various NEG subsidiaries and affiliates have FERC-approved market-based rate schedules and accordingly have been granted waivers of many of the accounting, record- keeping, and reporting requirements imposed on entities with cost-based rate schedules. This market-based rate authority may be revoked or limited were the FERC to conclude that the rates charged are no longer just and reasonable. Such a conclusion could be reached were the FERC to conclude, for example, that a NEG subsidiary or affiliate has excess market power. The FERC also regulates the rates, terms, and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide NEG with the necessary access to transmission lines. The FERC also licenses all of NEG's hydroelectric and pumped storage projects. These licenses, which are issued for 30 to 50 years, will expire at different times between 2001 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. The FERC may issue a new license to the existing licensee, issue a license to a new licensee, order that the project be taken over by the federal government (with compensation to the licensee), or order the decommissioning of the project at the owner's expense. NEG-affiliated projects are also subject to other differing federal regulatory regimes. Those qualifying as qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA), are exempt from the Holding Company Act, certain rate filings, and accounting, record-keeping, and reporting requirements that the FERC otherwise imposes and from certain state laws. Others qualify as Exempt Wholesale Generators (EWGs) under the National Energy Policy Act of 1992. EWGs are not regulated under the Holding Company Act, but are subject to FERC and state regulation, including rate approval. NEG's natural gas transmission business is also subject to FERC jurisdiction. Certificates of public convenience and necessity have been obtained from the FERC for construction and operation of the existing pipelines and related facilities and properties, and application has been made to construct the U.S. segment of the North Baja Pipeline. The rates, terms, and conditions of the transportation and sale (for resale) of natural gas in interstate commerce is subject to FERC jurisdiction. As necessary, NEG subsidiaries and affiliates file applications with the FERC for changes in rates and charges that allow recovery of costs of providing services to transportation customers. An October 1999 order permits individually negotiated rates in certain circumstances. The Department of Energy also regulates the importation of natural gas from Canada and exportation of power to Canada. State and Other Regulations In addition to federal laws and regulation, NEG businesses are also subject to various state regulations. First, public utility regulatory commissions at the state level are responsible for approving rates and other terms and 7 conditions under which public utilities purchase electric power from independent power producers. As a result, power sales agreements, which NEG affiliates enter into with such utilities, are potentially subject to review by the public utility commissions, through the commissions' power to review, for example, the process by which the utilities have entered into these agreements. Second, state public utility commissions also have the authority to promulgate regulations for implementing some federal laws, including certain aspects of PURPA. Third, some public utility commissions have asserted limited jurisdiction over independent power producers. For example, in New York the state public utility commissions have imposed limited requirements involving safety, reliability, construction, and the issuance of securities by subsidiaries operating assets located in that state. Fourth, state regulators have jurisdiction over the restructuring of retail electric markets and related deregulation of their electric markets. Finally, states may also assert jurisdiction over the siting, construction, and operation of NEG's generation facilities. In addition, the National Energy Board of Canada and the Canadian gas- exporting provinces issue licenses and permits for removal of natural gas from Canada which can impact customers' ability to import gas for transport over NEG pipelines. Other regulatory matters are described throughout this report. For a discussion of environmental regulations to which PG&E Corporation and it subsidiaries are subject, see the section entitled "Environmental Matters" below. 8 UTILITY OPERATIONS Pacific Gas and Electric Company provides regulated electric and gas distribution and transmission services in Northern and Central California. The Utility's service territory covers 70,000 square miles with an estimated population of approximately 13 million and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, computer technology, financial services, food processing, petroleum refining, agriculture, and tourism. Ratemaking Mechanisms Customer rates are determined by the FERC or the CPUC and are designed to recover the Utility's anticipated reasonable costs and a fair rate of return. Some rates incorporate a performance incentive mechanism by providing rewards and penalties for meeting certain performance criteria. Some of the ratemaking mechanisms affecting both electricity and gas distribution operations are discussed below. General Rate Case. The CPUC authorizes an amount, known as "base revenues," to be collected from ratepayers to recover the Utility's basic business and operational costs for its gas and electric distribution operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, currently are authorized by the CPUC in General Rate Case (GRC) proceedings. During the GRC, which occurs every three years, the CPUC examines the Utility's costs and operations to determine the amount of base revenue requirement the Utility 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 the Utility'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. Since base revenues are determined for a three-year period by GRCs, the Utility may apply for a yearly increase in base revenues (known as an attrition rate adjustment) to reflect inflation and the growth in capital investments necessary to serve customers. The 1999 and 2002 GRCs are discussed below. Cost of Capital. Each year, the Utility files an application with the CPUC to determine the authorized rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. Since February 17, 2000, the Utility's adopted return on common equity (ROE) has been 11.22% on electric and gas distribution operations, resulting in an authorized 9.12% overall rate of return (ROR). The Utility's earlier adopted ROR was 10.6%. The adopted ROR for 2000 resulted in an increase of approximately $49 million in electric and gas distribution revenues. In May 2000, the Utility filed an application with the CPUC to establish its authorized ROR for electric and gas distribution operations for 2001. The application requests a ROE of 12.4%, and an overall ROR of 9.75%. If granted, the requested ROR would increase electric distribution revenues by approximately $72 million and gas distribution revenues by approximately $23 million. The application also requests authority to implement an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would replace the annual cost of capital proceedings. The proposed adjustment mechanism would modify the Utility's cost of capital based on changes in an interest rate index. The Utility also proposes to maintain its currently authorized capital structure of 46.2% long-term debt, 5.8% preferred stock, and 48% common equity. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22% ROE for 2001. A final decision is expected in the second quarter of 2001. The return on the Utility's electric transmission-related assets is determined by the FERC. See "Electric Transmission Rates" below. The return on the Utility's natural gas transmission and storage business was incorporated in rates established in the Gas Accord settlement. See "Gas Ratemaking--Gas Accord" below. Electric and Gas Distribution Performance-Based Ratemaking (PBR). In June 2000, the CPUC granted the Utility's request to withdraw its PBR application filed in November 1998. The Utility had requested the withdrawal in accordance with the 1999 GRC decision issued in February 2000, which required a 2002 GRC before a PBR revenue/rate indexing mechanism could be implemented. In closing the PBR proceeding, the CPUC ordered the Utility to file a new PBR application by September 2000. 9 In September 2000, the Utility filed an application with the CPUC to establish (1) performance standards and associated financial rewards and penalties for electric and gas distribution service, (2) a revenue-sharing mechanism for new categories of non-tariffed products and services (NTP&S) offered by the Utility and (3) ratemaking for proceeds from sales or transfers of certain non-generation related land. The performance standards would cover a period of five years beginning January 1, 2001. The total maximum annual reward or penalty is $54 million per year, consisting of $52 million for electric distribution and $2 million for gas distribution. The revenue-sharing mechanism proposes to share net positive after-tax revenues from new categories of NTP&S equally between ratepayers and shareholders. Finally, the Utility requested that the CPUC establish basic rules about the allocation of gains and losses from the Utility's non-generation-related land sales. In November 2000, the CPUC suspended the schedule in the PBR proceeding until further order. Electric Ratemaking As required by AB 1890, electric rates for all customers were frozen at the level in effect on June 10, 1996, and, beginning January 1, 1998, rates for residential and small commercial customers were reduced by 10% from 1996 levels. The rate freeze ends the earlier of March 31, 2002, or when the Utility has recovered its eligible transition costs (uneconomic generation- related costs). Most transition costs must be recovered during a transition period that ends the earlier of December 31, 2001, or when the Utility has recovered its eligible transition costs. In 1997, the Utility, through a special purpose entity, refinanced the expected 10% rate reduction with $2.9 billion of rate reduction bonds. At December 31, 2000, $2 billion of bonds remained outstanding. If the transition period ends before December 31, 2001, the Utility may be obligated to return a portion of the economic benefits of the transaction to customers. The timing of any such return and the exact amount of such portion, if any, have not yet been determined. The Utility has advised the CPUC that it had recovered all of its transition costs during August 2000 (and possibly as early as May 2000, depending on the final valuation of the Utility's hydroelectric generating assets and when the rate freeze is determined to have ended). The Utility has asked the CPUC to recognize that the rate freeze already has ended for the Utility's customers. After the rate freeze, changes in the Utility's electric revenue requirements in general will be reflected in rates. The Utility believes that after the rate freeze is determined to have ended, the Utility is entitled to recover from ratepayers the costs it incurred to purchase power on behalf of retail customers. At December 31, 2000, the balance of the Utility's undercollected power purchase costs was $6.6 billion. PG&E Corporation and the Utility recognized a fourth quarter charge to earnings of $6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility could no longer conclude that its generation-related regulatory assets and undercollected purchased power costs were probable of recovery from ratepayers. Rate Stabilization Plan Proceeding. Consistent with the Utility's position that it had recovered its transition costs thus requiring an end to the rate freeze, in November 2000, the Utility filed an application with the CPUC seeking approval of a five-year rate stabilization plan (RSP) designed to protect the Utility's customers from the high and volatile wholesale power prices, while increasing rates effective January 1, 2001, to allow the Utility to begin recovery of the Utility's past and ongoing wholesale power purchase costs. The Utility requested that its proposed RSP rates and tariffs be adopted by January 1, 2001, on an interim basis, subject to refund, and that the CPUC approve the application by no later than March 31, 2001. The Utility also proposed to defer receiving a portion of its share of profits from its retained generation facilities, primarily from the Diablo Canyon nuclear power plant and its hydroelectric plants, until a later time during the five-year period and allow those funds instead to be used to offset uncollected power purchase costs. The Utility proposed that for the next two years (after which the Utility expects the current supply shortage will be less critical), the Utility retain its generation facilities and sell the output of these facilities directly to its retail distribution customers on an incentive ratemaking basis to lower the costs of procured power for such customers. On January 4, 2001, the CPUC issued an emergency interim decision denying the Utility's emergency request for a rate increase. Instead of the requested relief, the CPUC approved a 90-day temporary rate increase of 1 cent per kilowatt hour (kWh), subject to refund and adjustment. This rate increase, which raises 10 approximately $70 million per month, is grossly insufficient for the Utility to pay its ongoing procurement bills or to make further financing of these costs possible. On March 27, 2001, the CPUC issued a decision making the 1 cent per kWh surcharge permanent and authorizing the Utility to add an average 3 cent per kWh surcharge to current rates. Although the increase is authorized immediately, the 3 cent per kWh surcharge will not be collected in rates until the CPUC establishes an appropriate rate design for the surcharge, which is not expected to be adopted until May 2001, at the earliest. The revenue generated by the rate increase is to be used only for electric power procurement costs that are incurred after March 27, 2001. The rate increase is subject to refund (1) if not used to pay for such power purchases, (2) to the extent that generators and sellers of power make refunds for overcollections, or (3) to the extent any administrative body or court denies the refunds of overcollections in a proceeding where recovery has been hampered by a lack of cooperation from the Utility. In addition, the CPUC ordered that the 3 cent per kWh surcharge be added to the rate paid to the DWR as adopted by the CPUC in a companion decision discussed below. Also on March 27, 2001, the CPUC issued a decision ordering the Utility and the other California investor-owned utilities to pay the DWR a per-kWh price equal to the applicable generation-related retail rate per kWh established for each utility as in effect on January 5, 2001, for each kWh the DWR sells to the customers of each utility. The CPUC determined that the generation-related component of retail rates should be equal to the total bundled electric rate (including the 1 cent per kWh interim surcharge adopted by the CPUC on January 5, 2001) less the following non-generation-related rates or charges: transmission, distribution, public purpose programs, nuclear decommissioning, and the fixed transition amount. The CPUC determined that the Utility's company-wide average generation-related rate component is 6.471 cents per kWh and that this is the amount that should be paid to the DWR for each kWh delivered by the DWR to the Utility's retail customers after February 1, 2001, until specific rates are calculated. The CPUC ordered the utilities to pay the DWR within 45 days after the DWR supplies power to their retail customers, subject to penalties for each day that payment is late. The amount of power supplied to retail end-use customers after March 27, 2001, for which the DWR is entitled to be paid would be based on the product of the number of kWh that the DWR provided 45 days earlier and the Utility's company-wide average generation-related rate of 6.471 cents per kWh, and the additional 3 cent per kWh surcharge described above. The CPUC also ordered that the utilities immediately pay the sums owed to the DWR for power sold by the DWR from January 18, 2001 through January 31, 2001, under California Senate Bill 7X. Based on an estimated number of kWh sold by the DWR, the Utility paid approximately $30 million to the DWR at the rate of 5.471 cents per kWh as adopted by the CPUC. As the DWR has not advised the CPUC of its revenue requirement for the DWR's power purchases, it is unclear how much of the 3 cent surcharge will be needed by the DWR and how much, if any, may be used by the Utility to recover its procurement costs incurred after March 27, 2001. General Rate Case. In February 2000, the CPUC issued a decision in the Utility's 1999 GRC for the period 1999-2001. The decision was retroactive to January 1, 1999. The CPUC authorized base revenues for the Utility's electric distribution function of approximately $2.3 billion, reflecting an increase of $377 million over base revenues authorized in 1996. In March 2000, two intervenors filed applications for rehearing of the decision, alleging that the CPUC committed legal errors by approving funding in certain areas that were not adequately supported by record evidence. In April 2000, the Utility filed its response to these applications for rehearing, defending the GRC decision against the allegations of error. A CPUC decision on the applications for rehearing is pending. The 1999 GRC decision also ordered that the Utility file a 2002 GRC. In July 2000, the CPUC issued a decision requiring the Utility to file a Notice of Intent (NOI) with the CPUC by May 1, 2001. The CPUC decision affirms that rates would still become effective on January 1, 2002, although the CPUC decision may not be rendered until late 2002. In January 2001, the Utility filed a petition with the CPUC requesting that the May 1, 11 2001 deadline for filing the NOI be suspended, asserting that many assumptions that would have to be made in order to forecast year 2002 costs would very likely need to be changed based on how the wholesale electricity price and natural gas supply crises are resolved. The Utility requested that it be allowed to file an alternative to the schedule, or to the GRC itself, by May 1, 2001. The CPUC has not acted on the Utility's January 2001 petition. On March 27, 2001, the CPUC extended the NOI filing date by the number of days from March 5, 2001 to 30 days after the CPUC renders a decision on the petition. The extension will become effective only if the CPUC denies the petition. If the CPUC grants the petition, the Utility would be allowed to file an alternative schedule or an alternative to the GRC and the CPUC would subsequently decide how to proceed with the case. 2001 Attrition Rate Adjustment Request. In July 2000, the Utility filed an attrition rate adjustment application with the CPUC to increase its 2001 electric distribution revenues by $189 million, effective January 1, 2001, to reflect inflation and the growth in capital investments necessary to serve customers. The Utility did not request an increase in gas distribution revenues. On December 21, 2000, the CPUC issued an interim order finding that a decision on the merits of this application cannot be rendered by January 1, 2001, and determining that if attrition relief is eventually granted, that relief will be effective as of January 1, 2001. Hearings are scheduled to begin in June 2001, and a CPUC decision is expected by January 2002. Revenue Adjustment Proceeding. The CPUC established a separate annual proceeding, the Revenue Adjustment Proceeding (RAP), to review and verify the amounts recorded in the Utility's Transition Revenue Account (TRA), and to verify each electric utility's authorized revenue requirements, including any necessary adjustments to reflect the revenue requirements which are approved in other proceedings. The RAP also establishes revenue allocation and rate design, and identifies all electric balancing and memorandum accounts for continued retention or elimination. The TRA is a regulatory balancing account that is credited with total revenue collected from ratepayers through frozen rates. From this total revenue, the following items are subtracted: (1) revenues collected for transmission services and for the payment of rate reduction bond debt service, (2) the authorized revenue requirement for distribution services, public purpose programs, and nuclear decommissioning costs, and (3) electric industry restructuring implementation costs, energy procurement costs, and other costs. Remaining revenues, if any, are transferred to the Transition Cost Balancing Account (TCBA), a regulatory balancing account that tracks recovery of transition costs, to offset transition costs. Due to the high wholesale power costs at which the Utility has been required to purchase power for its distribution customers since June 2000, revenues from frozen rates have been grossly insufficient to recover the Utility's operating costs, resulting in a TRA under-collection of $6.6 billion at December 31, 2000. On January 4, 2001, the CPUC issued a decision in the Utility's 1999 RAP approving the transfer of $967 million of residual revenue in the TRA to the TCBA for the period from June 1, 1998 through June 30, 1999, and adopted a PX credit adder of .007 cents per kWh for utility customers that elect direct access to offset the energy costs included in the bundled rate. The Utility will file its application for its next RAP to address revenues and costs recorded in the TRA from July 1, 1999 through at least April 30, 2001, on or before June 1, 2001. One of the CPUC's March 27, 2001, decisions retroactively changes the TRA and TCBA accounting mechanisms. (See "Electric Utility Operations--Electric Industry Restructuring--New California Legislation," below.) Annual Transition Cost Proceeding. The Annual Transition Cost Proceeding (ATCP), applicable to all California investor-owned electric utilities, was established to verify the accounting and recording of costs and revenues in the TCBA and ensure that only eligible transition costs have been entered. The TCBA tracks the revenues available to offset transition costs, including the accelerated recovery of plant balances, and other generation-related assets and obligations. Transition costs will receive a limited "reasonableness" review. On January 4, 2001, the CPUC issued a decision in the Utility's 1999 ATCP finding that $2.6 billion recorded in the TCBA from July 1, 1998 through June 30, 1999 are eligible for recovery as transition costs. In February 2000, the Utility's request for approval of the Hunters Point power plant decommissioning cost was bifurcated into a separate phase and will be addressed in a separate decision expected to be issued in the second quarter of 2001. In September 2000, the Utility filed its 2000 ATCP application seeking approval of amounts recorded in the TCBA and generation-related memorandum accounts for the period July 1, 1999 through June 30, 2000. 12 As required by the CPUC, in August 2000, the Utility made a filing with the CPUC that estimated the market value of the Utility's remaining hydroelectric generating assets at $2.8 billion (based on a negotiated value used in a proposed settlement discussed below under "Electric Resources--Hydroelectric Generation Assets.") The Utility credited its TCBA by $2.1 billion, the amount of the estimated value over the assets' book value. At the same time, the Utility made a corresponding debit entry of the same amount in the newly established Generation Asset Balancing Account (GABA) to prevent an immediate charge to earnings that would have otherwise resulted from the credit to the TCBA. The filing will become effective after appropriate review by the CPUC's Energy Division and the TCBA entries are subject to review in the 2001 ATCP to be filed September 1, 2001. The Utility believes that with the credit to the TCBA, the Utility has recovered all of its transition costs as of early August 2000. If the final value of the hydroelectric assets is higher than the estimate, the Utility believes its transition costs would have been recovered as of an earlier date, possibly as early as May 2000. However, in a decision issued on March 27, 2001, the CPUC has stated that with the retroactive accounting changes adopted in the decision, the conditions for meeting the rate freeze have not been met. See "Electric Utility Operations--Electric Industry Restructuring--New California Legislation," below. Electric Industry Restructuring Implementation Costs. Under AB 1890, certain electric industry restructuring implementation costs found reasonable by the CPUC may be recovered from electric customers. In May 1999, the CPUC approved a multi-party settlement agreement that, among other things, permits the Utility to recover 1997 and 1998 restructuring implementation costs of $41.3 million (reflecting a reduction of $10 million from the Utility's requested revenue requirement). In addition, the Utility is authorized to recover in its TRA costs related to the Consumer Education Program and the Electric Education Trust funded by the Utility and FERC-approved ISO and PX development and start-up costs. At the end of the transition period, if recovery of these restructuring implementation costs recorded in the TRA displaces recovery of transition costs recorded in the TCBA, the Utility may recover up to $95 million of such displaced transition costs after the transition period. Electric Restructuring Costs Account (ERCA). The CPUC authorized the Utility to establish the Electric Restructuring Costs Account (ERCA) to record the restructuring implementation costs that were removed from its 1999 GRC revenue requirement request, any unanticipated restructuring costs incurred as a result of directives from the CPUC or the FERC, and certain other costs. In July 2000, the Utility filed an application seeking approval of $142.5 million of costs recorded in the ERCA. In August 2000, protests were filed by Enron Corporation, the CPUC's Officer of Ratepayer Advocates (ORA), and The Utility Reform Network (TURN), challenging the evidentiary support for the costs, among other concerns. This matter is pending. Revenues from Must-Run Contracts. The ISO has designated certain units at electric generation facilities as necessary to remain available to maintain the reliability of the electric transmission system. These units are called "must-run" units. In general, the ISO dispatches these units under cost-based contracts regulated by the FERC that allow the owners to recover a portion of fixed and operating costs of the must-run units. The owners of must-run units choose among two different forms of must-run contract, both of which cover operating costs. One form provides payments of a percentage of the unit's fixed cost revenue requirement and does not limit market participation. The other form provides 100% fixed cost recovery but allows only very restricted market participation. The Utility's two remaining fossil-fueled power plants (Hunters Point and Humboldt Bay), three of its hydroelectric generation facilities, and a combustion turbine located at a substation in San Jose, California, are under must-run contracts. The form of must-run contract chosen for all of these facilities (except Hunters Point and the combustion turbine) is the one that does not limit market participation. The Utility currently receives approximately $91 million per year as payments under these must-run contracts, plus fuel costs. In addition, the Utility has the opportunity to earn market revenues for all of these plants except Hunters Point and the combustion turbine, when the ISO has not dispatched the plant. FERC Transmission Owner Rate Case. The ISO controls most of the state's electric transmission facilities. The Utility serves as the scheduling coordinator to schedule transmission with the ISO to facilitate continuing service under wholesale transmission contracts that the Utility entered into before the ISO was established. The ISO bills the Utility for providing certain services associated with these contracts. These ISO charges are referred 13 to as the "scheduling coordinator costs." As part of the Utility's Transmission Owner rate case filed at the FERC, the Utility established a balancing account, the Transmission Revenue Balancing Account (TRBA), to record these scheduling coordinator costs in order to recover these costs through transmission rates. Certain transmission-related revenues collected by the ISO and paid to the Utility are also recorded in the TRBA. Through December 31, 2000, the Utility has recorded approximately $33 million of these scheduling coordinator costs in the TRBA. (The Utility has also disputed approximately $26 million of these costs as incorrectly billed by the ISO. Any refunds that ultimately may be made by the ISO would be credited to the TRBA.) In September 1999, a proposed decision was issued denying recovery of these scheduling coordinator costs. The proposed decision is subject to change by the FERC in its final decision. The FERC is expected to issue a final decision sometime in 2001. On January 11, 2000, the FERC accepted a proposal by the Utility to establish the Scheduling Coordinator Services (SCS) Tariff that would act as a back-up mechanism for recovery of the scheduling coordinator costs if the FERC ultimately decides that these costs may not be recovered in the TRBA. The FERC also conditionally granted the Utility's request that the SCS Tariff be effective retroactive to March 31, 1998, but the FERC suspended the procedural schedule until the final decision is issued regarding the inclusion of scheduling coordinator costs in the TRBA. AB 1890 Electric Base Revenue Increase. AB 1890 provided for an increase in the Utility's electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. The CPUC authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC authorized an additional base revenue increase of $77 million. The CPUC will determine how much of the authorized increases were actually spent on system safety and reliability during 1997 and 1998, and adjust the amounts downward if necessary. The Utility claims that it overspent the 1997 authorized revenue requirement by approximately $11.8 million and that the Utility underspent 1998 incremental revenues by approximately $6.5 million. The Utility has proposed that the underspent amount be credited to TRA revenues. In July 1999, the ORA recommended that $88.4 million in expenditures for 1997 and 1998 be disallowed. In August 1999, TURN recommended an additional $14 million disallowance for a total recommended disallowance for 1997 and 1998 expenditures of $102.4 million. The Utility opposed the recommended disallowances and hearings were held in October 1999. It is uncertain when a proposed decision will be issued by the CPUC. Any proposed decision would be subject to comment by the parties and change by the CPUC before a final decision is issued. Electric Transmission Rates. Since April 1998, electric transmission revenues have been authorized by the FERC, including various rates to recover transmission costs from the Utility's former bundled retail transmission customers. The FERC has not yet acted upon a settlement filed by the Utility that, if approved, would allow the Utility to recover $345 million in electric transmission rates for the 14-month period of April 1, 1998 through May 31, 1999. During that period, somewhat higher rates were collected, subject to refund. A FERC order approving this settlement is expected by the end of 2001. The Utility has accrued $24 million for potential refunds related to the period ended May 31, 1999. In April 2000, the FERC approved a settlement that permits the Utility to recover $264 million in electric transmission rates retroactively for the 10-month period from May 31, 1999 to March 31, 2000. In September 2000, the FERC approved another settlement that permits the Utility to recover $340 million annually in electric transmission rates and made this retroactive to April 1, 2000. Further, in November 2000, the FERC accepted, subject to refund, the Utility's proposal to collect $397 million in electric transmission rates beginning on May 6, 2001. Post-Transition Period Ratemaking Proceeding. In October 1999, the CPUC issued a decision in the Utility's post-transition period ratemaking proceeding. Among other matters, the CPUC decision prohibits the Utility from collecting after the rate freeze any costs incurred during the rate freeze but not recovered during the rate freeze, including costs that are not transition costs and not related to generation assets such as undercollected wholesale power purchase costs incurred on behalf of retail distribution customers. In November 2000, the California Supreme Court denied the Utility's petition for review of an appellate decision that had denied the Utility's petition for review of the CPUC's decision. The Utility has filed a complaint against the CPUC in federal court requesting the court to declare that the Utility is permitted as a matter of federal law to recover from distribution customers the wholesale power purchase costs it has incurred to purchase power on their behalf. For more information, see "Item 3--Legal Proceedings," below. 14 In the October 1999 decision, the CPUC also established the Purchased Electric Commodity Account (PECA) for the Utility to track energy costs after the rate freeze and transition period end. In June 2000, the CPUC issued a decision in which the CPUC determined that the PECA would reflect a pass- through of energy costs, possibly subject to after-the-fact reasonableness reviews. The decision states that after the rate freeze ends, there will be rate proceedings that will, among other matters, address electric energy procurement practices and rates. Gas Ratemaking Gas Accord. The Gas Accord separated or "unbundled" the Utility's gas transmission services from its distribution services, changed the terms of service and rate structure for gas transportation, increased the opportunity for core customers to purchase gas from competing suppliers, established a form of incentive mechanism to measure the reasonableness of core procurement costs, and established gas transmission and storage rates through 2002. In November 2000, the Utility filed an advice letter requesting authorized increases in the rates established for 2001 by the Gas Accord. Additional information about the Gas Accord is provided below in "Utility Operations-Gas Utility Operations." General Rate Case. In February 2000, the CPUC issued a decision in the Utility's GRC for the period 1999-2001. The decision is retroactive to January 1, 1999. The CPUC authorized base revenues for the Utility's gas distribution function, including public purpose programs, of approximately $892 million, reflecting an increase of approximately $93 million over base revenues authorized in 1996. Revised gas transportation rates reflecting the revenue changes resulting from the GRC and other regulatory proceedings were effective March 1, 2000. (For a discussion of the 2002 GRC, see above under "Electric Ratemaking.") The Core Fixed Cost Account (CFCA) is the regulatory balancing account that matches gas distribution and storage authorized revenue to the actual revenue collected from core customers. During May 2000, the Utility refunded approximately $320 million to core gas customers to reduce an over-collection in the CFCA. Since the volumes of gas delivered to core customers during the 1998 and 1999 winter seasons were higher than the forecasted volumes used to set the rates, an over-collection resulted. Beginning in December 2000, storage activity is recorded in a new procurement balancing account, Core Firm Storage Account, instead of in the CFCA, and are included in monthly core procurement rates. Gas Procurement Costs. The Utility procures gas for more than 90 percent of its core customers. The Utility passes on the natural gas costs it incurs on behalf of customers to ratepayers. The core procurement rate is set monthly based on the forecasted cost of gas. Gas procurement activity is recorded in the Purchased Gas Account (PGA). The PGA matches the actual gas commodity costs to the revenue collected from customers. Over- or under-collections in the PGA are collected or returned to customers through an adjustment to the gas procurement rate in subsequent months. The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the proceeding in which distribution costs and balancing account balances are allocated to customers. The BCAP normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. Balancing accounts for gas distribution and public purpose program revenue requirements accumulate differences between authorized revenue requirements and actual base revenues. In April 2000, the Utility filed its 2000 BCAP application to cover the period of January 1, 2000 through December 31, 2002, requesting a decrease in the annual base revenue requirement of $132 million compared to the authorized revenue requirement of $941 million at the time the application was filed. On October 27, 2000, the Utility filed with the CPUC a settlement agreement between the Utility and various parties and groups representing noncore industrial, electric generation, and co-generation customers. The settlement agreement resolved all issues relating the 2000 BCAP application raised by parties regarding customer throughput, marginal costs, the allocation of balancing account balances, and core and noncore rate design. If the settlement is adopted, there would be a decrease in the base revenue requirement of approximately $113 million, subject to adjustment for the most recent balancing account balances and CPUC decisions in place when the CPUC acts on the proposed settlement. A decision is expected in the third quarter of 2001. 15 Public Purpose Programs Under state law, the Utility is authorized to collect not less than $198 million in a separate nonbypassable charge included in frozen electric rates to fund Utility and other entities' investments in four public purpose programs: (1) cost-effective energy efficiency and energy conservation programs, (2) research, development and demonstration programs, (3) renewable energy resources programs, and (4) low-income electricity programs including targeted energy efficiency services and rate discounts. Low-income energy efficiency programs are funded at the level of need, but are not to be funded at less than the 1996 level of expenditures. The Utility 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 energy technologies at not less than $48 million per year, and low-income energy efficiency programs at not less than $14 million per year. The Utility also collects funds for the California Alternate Rates for Energy (CARE) low-income discount rate, a rate subsidy paid for by the Utility's other customers, which is currently about $31 million per year. Under the oversight of the CPUC, the Utility administers both the cost- effective energy efficiency and low-income energy efficiency programs. These two programs are reviewed annually in the Annual Earnings Assessment Proceeding (AEAP). In March 1999, the CPUC determined that these programs should continue to be administered by investor-owned utilities, subject to CPUC oversight, through 2001. Effective January 1, 2000, Section 327 of the California Public Utilities Code requires utilities to continue to administer low-income energy efficiency programs. The California Energy Resources Conservation and Development Commission (also called the California Energy Commission (CEC)) administers both the public interest research and development program and the renewable energy program on a statewide basis. The Utility transfers $78 million per year to the CEC for these two programs. In October 2000, the California Legislature passed and the Governor signed legislation extending the existing surcharge on electricity to fund public purpose energy efficiency, renewable energy, and research development and demonstration programs for another 10 years, beginning January 1, 2002. The AEAP determines shareholder incentives to be earned for the Utility's demand side management (DSM) programs. The 1999 AEAP determines shareholder incentives to be earned for the Utility's pre-1998 DSM activities and 1998 and later energy efficiency programs. The Utility was authorized in 2000 to collect $15.67 million for pre-1998 DSM earnings, $0.11 million for Program Year (PY) 1998 Low-Income Energy Efficiency (LIEE) earnings, and $10.45 million for PY 1998 non-LIEE earnings. After consolidating the adjusted incentive payment installments from prior years, the net revenue change in 2000 from shareholder incentives should be an electric increase of approximately $3.4 million and a gas decrease of approximately $1.5 million. In May 2000, the Utility filed its 2000 AEAP application seeking to recover approximately $53 million of shareholder incentives for attainment of milestones for PY 1999 energy efficiency programs, and for achieving savings for PY 1998 and 1999 LIEE programs and for DSM accomplishments related to pre- 1998 program commitments. In October 2000, the CPUC postponed the proceedings until further notice. Electric Utility Operations Electric Industry Restructuring The goal of California electric industry restructuring (AB 1890) was to open up the electric generation function of traditional utilities to competition to give electric customers of investor-owned utilities (such as Pacific Gas and Electric Company) the choice of continuing to purchase electric power from investor-owned utilities or purchasing electric power from alternative providers (including independent power generators and retail electricity providers such as marketers, brokers, and aggregators). Purchasing electric power from an alternative generation provider is called "direct access." Beginning March 31, 1998, customers were permitted to choose direct access. For those customers who did not choose direct access, investor-owned utilities were to continue to purchase electric power on their behalf. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including those customers who choose direct access. During the transition period, the California investor-owned utilities were required to sell into the 16 PX all of their generated electric power. "Must-take" generation resources, such as nuclear generation from Diablo Canyon, electric power generated by QFs and electricity that the Utility is required to purchase under existing contractual commitments, were also required to be scheduled through the PX. These "must take" resources were bid into the PX at $0 per megawatt-hour (MWh) to ensure that these resources are used to meet demand. During the transition period, the California investor-owned utilities also were required to buy power on behalf of their retail customers through the PX. Following the divestiture of much of their power generation facilities in connection with electric industry restructuring, the majority of the power purchased through the PX was supplied by third party generators. The CPUC did not permit the utilities to buy power directly from third parties through bilateral agreements until August 2000. California Power Crisis. California has endured a power crisis as demand for power far outstripped supply. Since June 2000, wholesale power prices in California have steadily increased to an average cost of 18.16 cents per kWh for the seven month period of June 2000 through December 2000, as compared to an average cost of 4.23 cents per kWh for the same period in 1999. During 2000, the Utility collected only approximately 5.4 cents per kWh through frozen rates for the recovery of its wholesale power costs. Many factors have contributed to the high wholesale power prices, including: . Economic and population growth in California. . A lack of new power supplies to meet the growing demand. . A substantial increase in natural gas prices. Since many power plants serving California are natural gas fired, the natural gas prices paid by generators in producing electricity are reflected in the price of power charged by the generators. . Limited availability of hydroelectric power due to dryer than usual conditions. . Uncoordinated power plant outages due to scheduled maintenance or unplanned outages. . Dysfunctional power markets that produced unjust and unreasonable price levels. . The tendency of frozen retail rates to eliminate the incentive for customers to conserve energy and reduce demand. . Delays in regulatory approvals to permit the California investor-owned utilities to enter into long-term power purchase contracts as a hedge against price fluctuations. After permission was given in August 2000, there have been further delays in regulatory approvals of reasonableness standards for entering into bilateral contracts. FERC Order. On December 15, 2000, the FERC issued an order adopting remedies for what the FERC characterized as the seriously flawed electric power markets in California. Among other matters, the FERC: . Eliminated, effective December 15, 2000, the requirement that the California investor-owned utilities sell all of their generation into and buy all of their energy needs from the PX, which results in over reliance on spot market (i.e., real-time) purchases. The order encourages the utilities to meet their purchase power needs through bilateral long-term contracts of two years or more and to adopt a balanced portfolio of contracts to mitigate cost exposure. To encourage the execution of bilateral contracts, the order requires the PX's rate schedules to terminate effective at the close of business on April 30, 2001. . Adopted a price benchmark at $74 per MWh for assessing prices of five- year energy supply contracts to be used by the FERC in assessing any complaints regarding justness and reasonableness of pricing long-term contracts. . Permitted penalties to be imposed on market participants who do not schedule at least 95% of their load in advance of the ISO's real-time market (through self-scheduling, bilateral contracts, or the PX markets), to reduce the reliance on the ISO's real-time market to meet supply. A penalty charge will be assessed when more than 5% of a market participant's load is scheduled into the ISO's real-time market. Penalties are to be disbursed to other market participants who schedule their load properly. The FERC order does not contain provisions for penalties to be imposed on generators who do not schedule in advance. 17 . Established an interim $150 per MWh "soft cap" modification of the single price auction so that bids above $150 MWh will not set the market clearing prices paid to all bidders at or below $150 per MWh. Bids above the $150 MWh level will trigger certain weekly reporting requirements and FERC monitoring. These price provisions will be in effect until April 30, 2001. . Deferred the consideration of retroactive refund issues linked to protective orders associated with the volatile prices experienced in California this past summer. Although the period for potential refund liability continues until December 31, 2002, with respect to specific transactions, refund potential on a transaction will close after 60 days unless the FERC has issued written notification to the seller that its transaction is still under review. PG&E Corporation and the Utility believe the actions outlined in the order will not provide a complete solution that ensures reliability of the state's electric supply and relief from future price increases, particularly since the FERC order fails to require sellers to enter into forward contracts at reasonable prices, and fails to provide an effective price cap. In addition, the FERC order does not address issues associated with retroactive refund and retroactive remedial authority issues. The Utility has filed a request for rehearing of the FERC's order to the extent that it does not provide effective mitigation of prices. In March 2001, the FERC ordered refunds of $68.7 million for January 2001 and subsequently ordered refunds of $55 million for February 2001 and indicated it would continue to review December 2000 wholesale prices. The generators have appealed the decision, and will supply cost justification. Any refunds will be offset against amounts owed the generators. The California Independent System Operator and the California Power Exchange. The PX and the ISO, both California public benefit non-profit corporations, began operating on March 31, 1998, as provided for under AB 1890. The FERC has jurisdiction over both the ISO and the PX. Pursuant to the FERC order of December 15, 2000, the ISO Board of Governors, which included representatives of market participants, was replaced with a non-stakeholder board who are independent of market participants. The ISO operates and controls most of the state's electric transmission facilities (which continue to be owned and maintained by the California utilities) and provides comparable open access to electric transmission service. The ISO accepts balanced schedules for supply and load from scheduling coordinators, including the PX and the Utility, and market participants and manages the availability of electric transmission on a statewide basis for these transactions. The ISO also purchases necessary generation and ancillary services on a real-time basis to maintain grid reliability. 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 of utility distribution systems remains with the CPUC. Until January 31, 2001, the PX provided an auction process, intended to be competitive, to establish hourly transparent market clearing prices for electricity in the markets operated by the PX. The PX operated two markets: the day-ahead market where market participants purchase power for their customers' needs on the following day and the day-of-or hour-ahead market where market participants purchase power needed to serve their customers on the same day. The PX set a market-clearing price for electricity by matching all demand bids (the amount of energy that an eligible customer is willing to purchase and the maximum price that the customer is willing to pay) with supply bids (the price at which a seller is prepared to sell energy) ranked from lowest to highest. The highest-accepted generation supply bid used to serve load set the PX market-clearing price for electricity. The market- clearing price then became the single cost for electricity throughout California for that energy delivery hour. Due to downgrades in the Utility's credit ratings and the Utility's alleged failure to post collateral for all market transactions, the PX suspended the Utility's market trading privileges as of January 19, 2001. On January 31, 2001, the PX suspended its day-of and day-ahead markets in response to the FERC's order directing the PX to comply with the terms of its December 15, 2000 order and implement a $150 per MWh "soft" price cap. The FERC ordered the PX to recalculate all PX transactions since December 15, 2000. The PX subsequently filed for bankruptcy protection. 18 In May 1999, the PX obtained FERC approval to operate the block forward market (BFM), an exchange that matches bids to buy power with offers to sell power more than one day in advance of the contracted delivery date. In July 1999, the Utility obtained CPUC authority to participate in the BFM for contracts that called for delivery by October 31, 2000 and subject to a volume limit. In March 2000, the CPUC raised the volume limit to permit the Utility to cover its "net open position" (the amount of power to meet the Utility's customers' needs that can not be met with Utility-owned generation or power under contract to the Utility) and affirmed that all PX purchases made during the transition period are deemed reasonable. The CPUC also expanded the Utility's authority to participate in the BFM through the end of the transition period. Participation in the BFM lessened after the FERC's December 15, 2000 order, discussed above. The PX sought to liquidate the Utility's BFM contracts for the purchase of power. On January 25, 2001, a California Superior Court judge granted the Utility's application for a temporary restraining order, which thereby restrained and enjoined the PX from liquidating the Utility's contracts, pending a hearing on a preliminary injunction on February 5, 2001. Immediately before the hearing, California Governor Gray Davis, acting under California's Emergency Services Act, commandeered the contracts for the benefit of the State. Under the Act, the State must pay the Utility the reasonable value of the contracts, although the PX may seek to recover the monies that the Utility owes to the PX from any proceeds realized from those contracts. The Utility has filed a claim with the California Victim Compensation and Government Claims Board which will be heard with other claims filed by the PX. New California Legislation. Some generation providers refused to sell power into the California markets based on their concern as to the credit quality of the California investor-owned utilities whose rates were still frozen. The Secretary of the U.S. Department of Energy (DOE) ordered such providers to continue selling into the California markets on request by the ISO. On January 18, 2001, the California Assembly passed Senate Bill 7X that appropriated $400 million and authorized the DWR to use such funds to purchase power at no more than 5.5 cents per kWh (far less than the current wholesale market rates in early 2001) and then resell it to the Utility at cost to enable the Utility to continue to serve its customers. The DWR was authorized to purchase power through January 31, 2001. On February 1, 2001, the California Governor signed Assembly Bill No. 1 (AB 1X) which was passed by the California Legislature during a special session to take effect immediately as an urgency statute. AB 1X authorizes the DWR to enter into contracts for the purchase of electric power for such periods and at such prices as the DWR deems appropriate consistent with the objectives of AB 1X to have an overall portfolio of contracts resulting in reliable service at the least cost. AB 1X prohibits the DWR from entering into any contract after January 1, 2003. AB 1X requires the DWR to sell power that it purchases directly to retail end use customers, except as may be necessary to maintain system integrity. AB 1X provides that the DWR will retain title to the power it purchases and that payment for any sale of power by the DWR is a direct obligation of retail end use customers to the DWR. The DWR may contract with the electric utilities for the electric utilities to transmit and distribute the power purchased and sold by the DWR and to provide billing, collection, and other related services, as agent of the DWR, on terms that reasonably compensate the utilities. AB 1X does not authorize the DWR to take ownership of transmission, generation, or distribution assets of any electric utility. AB 1X states it shall not be construed (1) to reduce or modify any electrical corporation's obligation to serve, or (2) to obligate the DWR for any procurement cost obligations of the utilities that existed before January 31, 2001. AB 1X authorizes the CPUC to set rates to cover revenue requirements of DWR's power purchasing program, but prohibits the CPUC from increasing electric rates for residential customers who use less power than 130% of their existing baseline quantities, until the DWR has recovered the costs of power it has purchased for retail customers. On March 27, 2001, the CPUC issued a decision in which it noted that although the DWR has assumed responsibility to purchase some of the utilities' power requirements, it has not committed to purchase all of the utilities' net open position, i.e., the power needs of the retail electric customers that cannot be met by utility-owned generation or power under contract to the utilities. To the extent the DWR does not buy enough power to cover the Utility's net open position, the ISO purchases emergency power on the high- priced spot market to meet system reliability requirements and the net open position. The ISO may attempt to charge the 19 Utility a proportionate share of the ISO's purchases. The Utility believes that under the current circumstances and applicable tariffs it is not responsible for such ISO charges. In addition, on April 3, 2001, the CPUC adopted a method to calculate the California Procurement Adjustment, as described in Public Utilities Code Section 360.5 (added by Assembly Bill 1X). Section 360.5 requires the CPUC to determine (1) the portion of each electric utility's electric retail rate effective on January 5, 2001, the "California Procurement Adjustment" or CPA, that is equal to the difference between the generation-related component of the utility's retail rate in effect on January 5, 2001, and the sum of the costs of the utility's own generation, QF contracts, existing bilateral contracts (i.e., entered into before February 1, 2001), and ancillary services, and (2) the amount of the CPA that is allocable to the power sold by the DWR. The CPUC decided that the CPA should be a set rate calculated by determining each utility's generation-related revenues (for the Utility the CPUC has proposed that this be equal to 6.471 cents per kWh multiplied by total kWh sales by the Utility to the Utility's retail customers), then subtracting each utility's statutorily authorized generation-related costs, and dividing the result by each utility's total kWh sales. Each utility's CPA rate will be used to determine the amount of bonds the DWR may issue. Using the CPUC's methodology, but substituting the CPUC's cost assumptions with actual expected costs and including costs the CPUC has refused to recognize, the Utility's calculations show that the CPA for the 11-month period February through December 2001 would be negative by $2.2 billion, (i.e., there would be no CPA available to the DWR) assuming the DWR purchases 84 percent of the Utility's net open position. If AB 1X were amended to also include in the CPA all the incremental revenue from the 3 cent per kWh increase discussed above (approximately $2.3 billion for 11 months), then the amount available to the DWR for the CPA for the comparable 11-month period, assuming the Utility were allowed to recover its costs first, would be approximately $100 million. The Utility believes the method adopted by the CPUC is unlawful and inconsistent with Section 360.5 because, among other reasons, it establishes a set rate that does not reflect actual residual revenues, overstates the CPA by excluding and/or understating authorized costs, and to the extent it is dedicated to the DWR does not allow the Utility to recover its own revenue requirements and costs of service. The Utility has filed an application for rehearing of the decision. Recovery of Transition Costs, Wholesale Power Purchase Costs, and End of Rate Freeze. Based on the premise that market-based revenues would not be sufficient to recover the utilities' uneconomic generation costs, AB 1890 provides the investor-owned utilities the opportunity to recover their transition costs during a transition period ending the earlier of December 31, 2001, or when the particular utility has recovered its transition costs. Some transition costs may be recovered after the transition period. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above-market sunk costs (i.e., costs associated with utility generating facilities that are fixed and unavoidable and that were included in customer rates on December 20, 1995) 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.) The Utility tracks the recovery of its transition costs in its TCBA. Transition costs may be recovered only through the competition transition charge (CTC) (the amount of revenues remaining after paying authorized operating costs), the excess of market value of generating assets over book value, and retained generation revenues. Due to the high wholesale power prices the Utility has been required to pay to purchase power for its customers, revenues from frozen rates since June 2000 have been insufficient to provide any CTC revenues. Under current CPUC decisions, if undercollected power purchase costs recorded in the TRA are not recovered through frozen rates by the end of the transition period, they cannot be recovered or offset against over-collections of transition costs. The Utility has filed a lawsuit in federal district court against the CPUC challenging these decisions. See "Item 3--Legal Proceedings," below. Under AB 1890, when the Utility has recovered its eligible transition costs, the conditions for terminating the rate freeze and ending the transition period will have been satisfied. At August 31, 2000, consistent with 20 transition period accounting mechanisms adopted by the CPUC, the Utility credited its TCBA by $2.1 billion, the amount by which a negotiated $2.8 billion hydroelectric generation asset valuation exceeded the aggregate book value of such assets. Based on this credit, the Utility believes it recovered its eligible transition costs during August 2000. At August 31, 2000, there was a balance of approximately $2.2 billion of undercollected wholesale power costs recorded in the TRA. If the final valuation for the hydroelectric assets is greater than $2.8 billion, as the Utility expects, the Utility believes it will have recovered its transition costs possibly as early as May 2000. The undercollected TRA balance as of the end of the earlier determined transition period will be less than the $2.2 billion August 31, 2000 balance and could be zero depending on the ultimate valuation of the hydroelectric assets and when the transition period actually ends. Under current CPUC decisions and AB 1890, the Utility's customers are responsible for wholesale power purchase costs after the Utility has recovered its transition costs. In one of its March 27, 2001 decisions, the CPUC adopted TURN's proposal to transfer on a monthly basis the balance in each utility's TRA to the utility's TCBA. The accounting changes are retroactive to January 1, 1998. The Utility believes the CPUC is retroactively transforming the undercollected power purchase costs in the TRA into transition costs in the TCBA. However, the CPUC characterized the accounting changes as merely reducing the prior revenues recorded in the TCBA, thereby affecting only the amount of transition cost recovery achieved to date. The CPUC also ordered that the utilities restate and record their generation memorandum accounts balances to the TRA on a monthly basis before any transfer of generation revenues to the TCBA. The CPUC found that based on the accounting changes, the conditions for meeting the end of the rate freeze have not been met. The Utility believes the adoption of TURN's proposed accounting changes results in illegal retroactive ratemaking and constitutes an unconstitutional taking of the Utility's property, and violates the federal filed rate doctrine. The Utility also believes the other CPUC decisions are similarly illegal to the extent they would compel the Utility to make payments to the DWR and QFs without providing adequate revenues for such payments. The Utility plans to challenge the decisions in appropriate legal forums. PG&E Corporation and the Utility recognized a fourth quarter charge to earnings of $6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility could no longer conclude that its generation-related regulatory assets and undercollected purchased power costs were probable of recovery from ratepayers. Further, absent a regulatory judicial, or legislative solution, the Utility cannot conclude that any power purchase costs it incurs during 2001 in excess of revenues from retail rates are probable of recovery through future rates. Retail Direct Access. Customers participating in direct access may purchase their electric power directly either through (1) competing non-utility retail electric providers such as brokers, marketers, aggregators, or other retailers, or (2) direct negotiated contracts with electric generators. Energy service providers (ESPs) supplying the direct access market had three billing options: (1) consolidated energy supplier billing, under which the utility bills the energy supplier for the services provided directly by the utility to the customer, and the supplier, in turn, provides a consolidated bill to the customer, (2) consolidated distribution company billing, under which the utility places the supplier's energy charge on a distribution bill, or (3) dual billing, under which the energy supplier and the utility bill separately for their own services. All customers (with limited exceptions), whether they choose direct access or not, were required to pay the nonbypassable CTC to be collected by their distribution utility in connection with recovery of the utilities' transition costs. The majority of direct access customers have been small commercial and large industrial customers. In light of the California electricity crisis, many ESPs have returned their direct access customers to Utility service. As of March 30, 2001, the Utility only had 36,641 direct access customers. AB 1X provides that, at a time to be determined by the CPUC, the right of retail customers to procure service from other ESPs will be suspended until the DWR no longer supplies power for retail end use customers. There may be further legislation to address direct access. Pursuant to CPUC regulations, the Utility has provided a PX energy credit to direct access customers. As wholesale power prices began to increase beginning in June 2000, the level of PX credits increased correspondingly to the point where the credits exceeded the Utility's distribution and transmission charges to direct access customers. Although the Utility paid approximately $39 million in PX credits, the Utility has ceased 21 paying these credits. The Utility believes whether these credits are owed, and if so in what amount, may be affected by the resolution of when the rate freeze ended (the Utility believes its rate freeze ended as early as May 2000 depending on the final valuation of the Utility's hydroelectric generating assets) and by whether the FERC ultimately orders refunds of wholesale prices which have been found by the FERC to be unjust and unreasonable. As of March 29, 2001, the estimated total of accumulated credits potentially owing to direct access customers that have not been paid by the Utility may be as high as $503 million. Three ESPs have filed complaints against the Utility at the CPUC arguing that the Utility violated CPUC orders and demanding payment for credits accumulated for their customers. The large PX credits have reduced revenues which, along with high PX costs, have contributed to the under- collection in the Utility's TRA. 22 Electric Operating Statistics At December 31, 2000, the Utility served approximately 4.6 million electric distribution customers. The following table shows the Utility's operating statistics (excluding subsidiaries) for electric energy sold, including the classification of sales and revenues by type of service. Before August 2000, the Utility was required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier.
2000 1999 1998 1997 1996 ---------- ---------- ---------- ---------- ---------- Customers (average for the year): Residential............ 4,071,794 4,017,428 3,962,318 3,915,370 3,874,223 Commercial............. 471,080 474,710 469,136 465,461 459,001 Industrial............. 1,300 1,151 1,093 1,121 1,248 Agricultural........... 78,439 85,131 85,429 86,359 87,250 Public street and highway lighting...... 23,339 20,806 18,351 17,955 17,583 Other electric utilities............. 8 0 14 47 28 ---------- ---------- ---------- ---------- ---------- Total................. 4,645,960 4,599,226 4,536,341 4,486,313 4,439,333 ========== ========== ========== ========== ========== Sales-kWh (in millions): Residential............ 28,753 27,739 26,846 25,946 25,458 Commercial............. 31,761 30,426 28,839 28,887 27,868 Industrial(1).......... 16,899 16,722 16,327 16,876 15,786 Agricultural(1)........ 3,818 3,739 3,069 3,932 3,631 Public street and highway lighting...... 426 437 445 446 438 Other electric utilities............. 266 167 2,358 3,291 1,213 ---------- ---------- ---------- ---------- ---------- Total energy delivered............ 81,923 79,230 77,884 79,378 74,394 ========== ========== ========== ========== ========== Revenues (in thousands): Residential............ $3,007,675 $2,961,788 $2,891,424 $3,082,013 $3,033,613 Commercial............. 2,693,316 2,837,111 2,793,336 2,932,560 2,840,101 Industrial............. 509,486 863,951 933,316 1,028,378 1,005,694 Agricultural........... 385,961 391,876 350,445 413,711 396,469 Public street and highway lighting...... 43,403 49,209 51,195 53,183 55,372 Other electric utilities............. 26,269 16,501 50,166 118,781 81,855 Revenues from energy deliveries........... 6,666,110 7,120,436 7,069,882 7,628,626 7,413,104 Miscellaneous.......... 194,947 162,105 161,156 (9,439) 112,303 Regulatory balancing accounts.............. (6,765) (50,780) (40,408) 71,441 (365,192) ---------- ---------- ---------- ---------- ---------- Operating revenues.... $6,854,292 $7,231,761 $7,190,630 $7,690,628 $7,160,215 ========== ========== ========== ========== ========== The following table shows certain customer information: 2000 1999 1998 1997 1996 Selected Statistics: ---------- ---------- ---------- ---------- ---------- Average annual residential usage (kWh)................. 7,062 6,905 6,776 6,627 6,571 Average billed revenues per kWh (cents per kWh): Residential........... 10.46 10.68 10.77 11.88 11.92 Commercial............ 8.48 9.32 9.69 10.15 10.19 Industrial(1)......... 3.02 5.17 5.72 6.09 6.37 Agricultural(1)....... 10.11 10.48 11.42 10.52 10.92 Net plant investment per customer ($)...... 1,969 2,388 2,705 3,027 3,198
- -------- (1) Beginning April 1998, the sales-kWh and average billed revenues per kWh include electricity provided to direct access customers where the Utility does not earn commodity charges. 23 Electric Resources The Utility's sources of generation during 2000 were as follows: 15% from the Utility's hydroelectric assets, 21% from the Utility's nuclear facilities at Diablo Canyon, 1% from the Utility's fossil-fueled plants, and 63% from QFs and other power suppliers. In 1995, the CPUC issued a decision which required the Utility to "file a plan to voluntarily divest [itself] of at least 50% of [its] fossil generating assets." As an incentive to divest, the CPUC reduced the rate of return on the Utility's generating assets, including its hydroelectric generation assets and Diablo Canyon, to 6.77%. The Utility has sold all but two of its fossil-fueled electric generating plants and has sold all of its geothermal generating facilities. The Utility's own generation resources and contracted for generation resources serve approximately 36% of the Utility's retail electric customers. Until December 15, 2000, the Utility was required to sell all of its owned generation, and generation purchased by the Utility under long-term contracts with QFs and other power providers, to the PX. The December 15, 2000 FERC order eliminated the requirement that the California investor-owned utilities sell all of their generation into (and buy all of their energy needs from) the PX. The PX suspended the Utility's trading privileges on January 19, 2001 and the PX markets were suspended as of January 31, 2001. Since January 31, 2001, the Utility has been scheduling its own generation through the ISO for use by the Utility's customers. The remainder of the power needed to serve the Utility's customers has been purchased by the DWR or the ISO. Generating Capacity Except as otherwise noted below, as of December 31, 2000, Pacific Gas and Electric Company owned and operated the following generating plants, all located in California, listed by energy source:
Number Net of Operating Generation Type County Location Units Capacity kW --------------- --------------- ------ ----------- Hydroelectric: Conventional Plants....... 16 counties in Northern and 107 2,684,100 Central California Helms Pumped Storage Plant.................... Fresno 3 1,212,000 --- --------- Hydroelectric Subtotal.. 110 3,896,100 --- --------- Steam Plants: Humboldt Bay.............. Humboldt 2 105,000 Hunters Point(1).......... San Francisco 3 377,000 --- --------- Steam Subtotal.......... 5 482,000 --- --------- Combustion Turbines: Hunters Point(1).......... San Francisco 1 52,000 Mobile Turbines(2)........ Humboldt and Mendocino 3 45,000 --- --------- Combustion Turbines Subtotal............... 4 97,000 --- --------- Nuclear: Diablo Canyon............. San Luis Obispo 2 2,174,000 --- --------- Total................... 121 6,649,100 === =========
- -------- (1) In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Hunters Point fossil-fueled power plant, which the ISO has designated as a "must run" facility. The agreement expresses the Utility's intention to retire the plant when it is no longer needed by the ISO. (2) Listed to show capability; subject to relocation within the system as required. The Utility is interconnected with electric power systems in 14 Western states, Alberta and British Columbia, Canada, and Mexico. 24 Hydroelectric Generation Assets The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses with a total generating capacity of 3,896 megawatts (MW). The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes 94 contracts for water rights and 163 statements of water diversion and use. Under AB 1890 all generation assets must be market-valued by December 31, 2001 through appraisal, sale or other divestiture. In 1999, the Utility filed an application with the CPUC to determine the market value of the Utility's hydroelectric generation facilities and related assets through an open competitive auction similar to the auction process used in the previous sales of the Utility's fossil fueled and geothermal plants. In November 2000, the CPUC's draft environmental impact report (EIR) reviewing the potential environmental impacts of the proposed auction under the California Environmental Quality Act (CEQA) was issued. As an alternative to the auction proposal, in August 2000, the Utility and other parties filed an application with the CPUC for approval of a settlement under which the hydroelectric facilities would be transferred to a California- based affiliate of PG&E Corporation at a value of $2.8 billion, subject to a 40-year revenue sharing agreement. In November 2000, the Utility withdrew its support from the settlement. In December 2000, the Utility submitted updated testimony in the valuation proceedings indicating that the market value of the hydroelectric assets ranges from $3.9 billion to $4.2 billion assuming that the assets were sold in a competitive auction or other arm's-length sale. Updated joint testimony was also submitted by the CPUC's Office of Ratepayer Advocates (ORA), TURN, and the California Farm Bureau Federation (CFBF). These parties had previously submitted joint testimony in which they recommended a valuation of $2.665 billion assuming the hydroelectric facilities would be retained by the Utility. Their updated testimony estimates that recent higher market prices result in an increase in the value of the assets by approximately $943 million, although they do not recommend any change to their previous valuation of $2.665 billion. Instead, they recommend that ratepayers receive all future operating profits from hydroelectric generation operations, which, based on higher price forecasts, will ensure that ratepayers obtain the full value of the assets. Further, the joint parties recommend that the amount of the final market valuation that exceeds book value be used to reduce the Utility's undercollected wholesale power purchase costs recorded in the Utility's TRA rather than crediting the Utility's TCBA. The Utility has opposed this proposal, as it would unlawfully delay the completion of transition cost recovery by the Utility as well as delay the end of the rate freeze. In response to the California wholesale electricity crisis, in January 2001, the California Governor signed Assembly Bill 6 (AB6) which prohibits public utilities from disposing of any generation facility before January 1, 2006. In light of AB6, the hydroelectric valuation proceeding will no longer address the disposition of the hydroelectric facilities. On February 21, 2001, the Utility requested that the CPUC suspend the CEQA review in light of AB6. Absent a resolution suspending the CEQA review, the Utility provided comments on the draft EIR on March 9, 2001. In its rate stabilization proceeding, the Utility has proposed to defer receiving a portion of its share of profits from its hydroelectric plants until a later time and allow those funds instead to be used to offset uncollected power purchase costs. The Utility has proposed that for the next two years (after which the Utility expects the current supply shortage will be less critical), the Utility sell the output of these facilities directly to its retail distribution customers on an incentive ratemaking basis to lower the costs of procured power for such customers. Diablo Canyon Nuclear Power Plant 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, 2000, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 82% and 84%, respectively. 25 The table below outlines Diablo Canyon's refueling schedule for the next five years. Diablo Canyon refueling outages typically are scheduled every 19 to 21 months. The schedule below assumes that a refueling outage for a unit will last approximately 35 days, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages.
2001 2002 2003 2004 2005 ----- ---- -------- -------- -------- Unit 1 Refueling............................... May February October Startup................................. June March November Unit 2 Refueling............................... April February October Startup................................. June March November
Diablo Canyon Ratemaking. Since January 1, 1997, the Utility's sunk costs in Diablo Canyon have been recovered from ratepayers through a sunk cost revenue requirement, at a reduced return on common equity equal to 6.77% that will remain in effect through the end of the transition period. (Sunk costs are costs associated with the facility that are fixed and unavoidable.) The Diablo Canyon sunk costs revenue requirement is being recovered as a transition cost through the TCBA. In connection with the new ratemaking, the CPUC 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. The audit was completed in August 1998. In September 2000, the CPUC issued a decision that concluded that because the audit found that Diablo Canyon costs are presented fairly, no further action would be taken and the proceeding would be closed. Also since January 1, 1997, a performance-based Incremental Cost Incentive Price (ICIP) mechanism has been used to recover Diablo Canyon's operating costs and the cost of capital additions incurred after December 31, 1996. The ICIP mechanism establishes a rate per kWh generated by the facility for the period 1997 through 2001. The CPUC-authorized ICIP price for 2001 is 3.49 cents per kWh, resulting in estimated ICIP revenues of $552 million based on an assumed capacity factor of 83.6%. The estimated sunk cost revenue requirement for 2001 is approximately $1.1 billion. Any variance between ICIP revenues and related costs is reflected in earnings. After the transition period, Diablo Canyon generation must be sold at the prevailing market price for power. Further, pursuant to the 1997 CPUC decision establishing the ICIP, the Utility is required to begin sharing 50% of the net benefits of operating Diablo Canyon with ratepayers beginning after the transition period. In June 2000, the Utility filed an application with the CPUC requesting approval of its proposal for sharing with ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon. The net benefit sharing methodology proposed in the Utility's application would be effective at the end of the current electric rate freeze for the Utility's customers and would continue for as long as the Utility owned Diablo Canyon. Under the proposal, the Utility would share the net benefits of operating Diablo Canyon based on the audited profits from operations, determined consistent with the prior CPUC decision. If Diablo Canyon experiences losses, such losses would be accrued and netted against profits in the calculation of the net benefits in subsequent periods (or against profits in prior periods if subsequent profits are insufficient to offset such losses). Any changes to the net sharing methodology would have to be approved by the CPUC. However, the CPUC has suspended the proceeding to consider the net benefit sharing methodology. In the Utility's rate stabilization proceeding (see "Electric Ratemaking" above), parties have proposed that the requirement to establish a sharing methodology be rescinded and that Diablo Canyon be placed on cost of service ratemaking. It is uncertain what future ratemaking will be applicable to Diablo Canyon. Nuclear Fuel Supply and Disposal. The Utility 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 Diablo Canyon operations forecasts and a combination of existing contracts and inventories, the requirement for uranium supply will be met through 2004, the requirement for the conversion of uranium to 26 uranium hexaflouride will be met through 2001, and the requirement for the enrichment of the uranium hexaflouride to enriched uranium will be met through 2002. The fuel fabrication contract for the two units will supply their requirements for the next seven operating cycles of each unit. These contracts are intended to ensure long-term fuel supply, but permit the Utility the flexibility to take advantage of short-term supply opportunities. In most cases, the Utility's nuclear fuel contracts are requirements-based, with the Utility's obligations linked to the continued operation of Diablo Canyon. Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the DOE is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, Pacific Gas and Electric Company signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has been unable to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted by the DOE for interim or permanent storage before 2010, at the earliest. At the projected level of operation for Diablo Canyon, the Utility's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2006. 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. In July 1988, the NRC gave final approval to the Utility to store radioactive waste from the nuclear generating unit (Unit 3) at Humboldt Bay Power Plant (Humboldt) at Humboldt before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available. Insurance. The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL, which is owned by utilities with nuclear generating facilities, provides insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. Under these insurance policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective premium assessments of $12 million (property damage) and $4 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NEIL. The Price-Anderson Act, as amended by Congress in 1988 (Price Act), limits public liability claims that could arise from a nuclear incident to a maximum of $9.5 billion per incident. The Price Act requires that all nuclear utilities share in the payment for nuclear liability claims resulting from a nuclear incident. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $9.3 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, the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Decommissioning. The Utility's estimated total obligation to decommission and dismantle its nuclear power facilities is $1.7 billion in 2000 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. 27 Nuclear decommissioning costs recovered in rates are placed in external trusts. The funds in these trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the funds held in the trusts, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Monies may not be released from the external trusts until authorized by the CPUC. In December 1997, the CPUC granted the Utility's request for authority to disburse up to $15.7 million from the Humboldt Bay Power Plant decommissioning trusts to finance three partial nuclear decommissioning projects at Humboldt Unit 3. Accordingly, as of December 31, 2000, $9.3 million ($15.7 million less $6.4 million in expected tax benefits) has been disbursed from the Humboldt Unit 3 non-tax-qualified trust to reimburse the Utility for nuclear decommissioning expenses associated with the partial decommissioning projects. The remaining $6.4 million of the approved expenses will be disbursed only if the Internal Revenue Service (IRS) disallows the expected tax benefits. In February 2000, the CPUC granted the Utility's request to disburse an additional amount of up to $7 million from the Humboldt Bay Power Plant decommissioning trusts to explore licensing and permitting of an on-site dry cask storage facility for the spent nuclear fuel that would allow early decommissioning of Humboldt Bay Power Plant Unit 3. As of December 31, 2000, $1.7 million ($2.9 million project cost less $1.2 million in expected tax benefits) has been disbursed from the Humboldt Unit 3 non-tax-qualified trust to reimburse the Utility for nuclear decommissioning expenses associated with the dry cask storage facility. Additional licensing and permitting activities are continuing. As of December 31, 2000, the Utility had accumulated external trust funds with an estimated liquidation value of $1.36 billion, based on quoted market prices and net of deferred taxes on unrealized gains, to be used for the decommissioning of the Utility's nuclear facilities. The amount recovered in rates for nuclear decommissioning costs is authorized by the CPUC as part of the GRC. The CPUC considers the trusts' asset levels, together with revised earnings and decommissioning cost 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, 2000, annual nuclear decommissioning trust contributions collected in rates were $26.47 million. Of this amount, the Utility was able to contribute only $14 million to the trusts in 2000 due to the Utility's liquidity crisis. The Utility expects that it will be required to refund the difference to customers in 2001. The Utility has filed for a new schedule of ruling amount (SRA) with the IRS that would lower the amount collected through rates to $24 million. The IRS has not yet approved the Utility's proposed SRA. If approved, the difference between the previous amount collected in rates and the new amount would be refunded to customers. Since January 1, 1998, nuclear decommissioning costs, which are not transition costs, have been recovered through a nonbypassable charge that will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. The CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and to establish the annual revenue requirement and attrition factors over subsequent three-year periods. Other Electric Resources QF Generation and Other Power Purchase Contracts. The Utility is required by CPUC decisions to purchase electric energy and capacity provided by independent power producers that are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). The CPUC required California utilities to enter into a series of QF long-term power purchase agreements (PPAs) and approved the applicable terms, conditions, price options, and eligibility requirements. The PPAs require the Utility to pay for energy and capacity. Energy payments are based on the QF project's actual electrical output and capacity payments are based on the QF project's total available capacity and contractual capacity commitment. Capacity payments may be reduced if the facility does not meet the performance requirements specified in the PPAs. 28 Until December 15, 2000, the Utility was required to schedule into the PX all of the electric power generated by QFs and other providers that the Utility is required to purchase under existing contractual commitments. (The December 15, 2000 FERC order eliminated this mandatory sell requirement.) The Utility has paid these suppliers directly pursuant to price provisions contained in their PPAs. The invoices sent by the PX for the cost to serve the Utility's retail customers included credits for power provided by these suppliers based on electric market prices. In general, before the steep increase in wholesale power prices that began in June 2000, the price for energy payments under QF contracts was higher than the market price. The amount of the contract payment exceeding the market price is recoverable as a transition cost. Under Section 390(c) of the Public Utilities Code (PUC) adopted in AB 1890 and implemented by a November 1999 CPUC decision, QFs could make a one-time election to receive energy payments based on the PX day ahead market clearing price, on an interim basis and subject to true-up, instead of receiving short-run avoided costs energy payments based on the "transition formula" adopted by AB 1890 and set forth in PUC Section 390(b). Those that elected not to exercise this option continued to receive PPA payments based on the Utility's short-run avoided costs. As the wholesale market price of power rose dramatically, many QFs elected to receive PX-based payments, causing the Utility's procurement costs to increase significantly. For the period from June 2000 through December 2000, energy costs for deliveries from QFs who switched to PX pricing were approximately $375 million more than these QFs would have received under the transition formula. On January 10, 2001, the Utility filed an emergency motion with the CPUC requesting that the CPUC true-up payments made to switching QFs since June 2000 to the Utility's "transition formula" short-run avoided cost energy rates or, in the alternative, to PX-based rates capped at $67.45 per megawatt- hour. On February 22, 2001, the CPUC issued a decision ordering that QFs that had exercised their one-time option to switch to PX-pricing would be paid short-run avoided cost energy payments based on the transition formula effective on January 19, 2001. The Utility paid approximately 15 percent of amounts due QFs for deliveries made in December 2000 and January 2001. The Utility made no payment for QF deliveries received in February 2001. On March 27, 2001, the CPUC issued a decision requiring the Utility and the other California investor-owned utilities to pay QFs fully for energy deliveries made on and after the date of the decision. The CPUC decision requires the Utility to pay QFs for energy and capacity deliveries within 15 days following the current monthly billing period instead of the 30 days after the close of the billing period required by the PPAs. The CPUC stated that its change to the payment provision was required to maintain energy reliability in California. The CPUC held that a failure to make a required payment would result in a fine in the amount owed to the QF. The decision also adopts a revised pricing formula relating to the California border price of gas applicable to energy payments to all QFs, including those that do not use natural gas as a fuel. Based on the Utility's preliminary review of the decision, the revised pricing formula would reduce the Utility's 2001 average QF energy and capacity payments from approximately 12.7 cents per kWh to 12.3 cents per kWh. Most of the PPAs expire on various dates through 2028, though some have no stated expiration date. Deliveries from these power producers account for approximately 23% of the Utility's 2000 electric energy requirements and no single contract accounted for more than 5% of the Utility's energy needs. As of December 31, 2000, the Utility had commitments to purchase approximately 5,200 MW of capacity under CPUC-mandated PPAs. Of the 5,200 MW, approximately 4,400 MW are operational. Development of the majority of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 4,400 MW of operational capacity consists of 2,700 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. The Utility also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the supplier's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 29 to 2031. Costs associated with these contracts to purchase power are eligible for recovery by the Utility as transition costs through the collection of the nonbypassable CTC. At December 31, 2000, the undiscounted future minimum payments under these contracts are approximately $31.5 million for each of the years 2001 through 2004 and a total of $221 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 4.6% of the Utility's 2000 electric energy requirements. The amount of energy received and the total payments made under all these power purchase contracts were:
2000 1999 1998 1997 ------ ------ ------ ------ ($ in millions) Kilowatt-hours received............................ 25,446 25,910 25,994 24,389 Energy payments.................................... $1,549 $ 837 $ 943 $1,157 Capacity payments.................................. $ 519 $ 539 $ 529 $ 538 Irrigation district and water agency payments...... $ 56 $ 60 $ 53 $ 56
Bilateral Agreements. Until August 2000, CPUC decisions required the Utility to purchase power for its retail customers solely through the PX and ISO. On July 21, 2000, the Utility filed an emergency motion with the CPUC seeking authorization to enter into bilateral agreements directly with third parties to purchase power, capacity, and ancillary services, citing the need to better hedge against high power prices in the PX day-ahead and ISO real- time markets and to introduce new supply into California. In its July 2000 request, the Utility proposed that the CPUC adopt prospective reasonableness standards which would allow the CPUC to determine at the time of inception whether a transaction was reasonable per se compared to specific market prices. Without such prospective reasonableness standards, the CPUC can second-guess the Utility's decision to enter into contracts and disallow some or all of those costs deemed after-the-fact to be "unreasonable." On August 3, 2000, the CPUC approved the Utility's emergency motion and allowed the Utility to enter into bilateral contracts, subject to previous limits established for BFM purchases (i.e., used to cover the Utility's net open position), provided that all such contracts must expire on or before December 31, 2005. The CPUC's approval of bilateral contracting authority was subject to agreement on implementation details, such as appropriate pricing benchmarks, with ORA and the CPUC's Energy Division. ORA and the Energy Division rejected the Utility's proposed standards and neither has suggested alternative standards. Despite this stalemate, during September and October 2000, the Utility held an auction soliciting offers for energy purchases at fixed prices for one to five years. In October 2000, the Utility entered into bilateral power purchase contracts with several suppliers. In December 2000, the Utility again solicited offers from power suppliers, but the responses were priced above then-current market prices so the Utility elected not to enter into any contracts at that time. The downgrade of the Utility's credit ratings since December 2000 has effectively barred the Utility from entering into additional long-term contracts. In its December 15, 2000 order, the FERC noted that it was critical for the CPUC to give timely and predictable approval of the prudence of a balanced portfolio of short- and long-term contracts. On December 22, 2000, the CPUC issued a decision requesting comments from interested parties on a set of reasonableness standards proposed in the decision. In this decision, the CPUC proposed price benchmarks which were well below the then current market prices, making it impossible for the Utility to enter into bilateral purchases which the CPUC could deem reasonable. The Utility filed comments to the proposed decision objecting to the proposed standards as unworkable. In January 2001, the CPUC issued another proposed decision adopting similar unrealistic price benchmarks for bilateral purchases. Again, the Utility filed comments expressing its concerns with the new draft decision. It is uncertain whether or when the CPUC will issue appropriate realistic reasonableness standards. Electric Transmission and Distribution To transport energy to load centers, Pacific Gas and Electric Company as of December 31, 2000 owned approximately 18,376 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and 30 transmission substations having a capacity of approximately 39,859,000 kilovolt-amperes (kVA), including spares, excluding power plant interconnection facilities. Energy is distributed to customers through approximately 115,131 circuit miles of distribution system and distribution substations having a capacity of approximately 23,524,000 kVA. In connection with electric industry restructuring, in 1998 the utilities relinquished control, but not ownership, of their transmission facilities to the ISO. The FERC has jurisdiction over the transmission facilities and revenue requirements and rates for transmission service are set by the FERC. The ISO commenced operations on March 31, 1998. The ISO, regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. As control area operator, the ISO is also responsible for assuring the reliability of the transmission system. In 1998, the FERC approved the forms of agreements for reliability must-run (RMR) generating facilities that have been entered into between RMR facility owners and the ISO to ensure grid reliability and avoid the exercise of local market power. The costs of RMR contracts attributed to supporting the Utility's historic transmission control area are charged to the Utility as a Participating Transmission Owner (PTO). These costs, which were approximately $178 million in 2000, are currently recovered from the Utility's retail customers and, subject to the outcome of current FERC proceedings, wholesale transmission customers. In March 2000, the ISO filed an application with the FERC seeking to establish its own Transmission Access Charge (TAC) as directed in AB 1890. The FERC accepted the ISO's TAC filing, subject to refund, but suspended the proceeding to allow the parties to enter into settlement discussions. In late December 2000, the ISO made a further implementation filing, also accepted by the FERC subject to refund, to establish specific TAC rates because a transmission-owning municipality had applied to become a new PTO, thereby triggering effectiveness of the ISO TAC rate methodology. The ISO's TAC methodology provides for transition to a uniform statewide high voltage transmission rate, based on the revenue requirements of all PTOs associated with facilities operated at 200 kV and above. The TAC methodology also requires original PTOs such as the Utility to pay certain increases incurred by new PTOs resulting from joining the ISO during a 10-year transition period. The Utility's obligation for this cost shift is currently capped at $32 million per year. The Utility has been working closely with the ISO to remedy transmission constraints on the Utility's electric transmission system. Of particular concern are the constraints on Path 15, which is located in the southern portion of the Utility's service area, and serves as the part of the primary transmission link between Northern and Southern California. At times, the current facilities cannot accommodate all low-cost power intended to be transmitted between Southern California (where the Utility's Diablo Canyon nuclear power plant is located) and Northern California. This often results in significant wholesale power price differentials between Northern and Southern California with relatively high power prices in Northern California and relatively low power prices in Southern California. The Utility's investment in maintenance and expansion of its transmission system has been growing substantially over the past several years. The Utility anticipates making an additional capital investment of approximately $260 million in its transmission system in 2001. Through the ISO's Long-Term Grid Planning Process, the Utility annually files its transmission upgrade plans and provides the ISO the opportunity to concur with the Utility's planned upgrades. As a result of the ISO concluding that the available power reserves were precipitously low, the ISO ordered the Utility to implement emergency procedures in the Utility's service territory frequently during the summer 2000 and winter 2001, and as recently as March 2001. On some occasions these measures included rolling outages affecting a large number of retail customers. It is anticipated that a projected power supply shortage for peak demand periods, including the summer of 2001, will result in further rolling outages. To the extent conservation efforts are successful, the need for such emergency measures may be lessened. Depending on the location of the available power supply relative to the load, transmission constraints could exacerbate the supply problem. Completion of the Utility's planned transmission projects before the summer 2001 peak are expected to mitigate most of these constraints. 31 Most of the Utility's distribution services remain subject to CPUC jurisdiction. The CPUC is considering whether it should pursue further reforms in the structure and regulatory framework governing electricity distribution service. Gas Utility Operations Pacific Gas and Electric Company owns and operates an integrated gas transmission, storage, and distribution system in California. The Utility served approximately 3.8 million gas customers at December 31, 2000. Most of these customers continue to obtain gas supplies from the Utility under regulated tariff rates. The Utility offers transmission, distribution, and storage services as separate and distinct services to its industrial and larger commercial gas (non-core) customers. Customers have the opportunity to select from a menu of services offered by the Utility and to pay only for the services that they use. Access to the transmission system is possible for all gas marketers and shippers, as well as non-core end users. The Utility's residential and smaller commercial gas (core) customers can select the commodity gas supplier of their choice. However, the Utility continues to purchase gas as a regulated supplier for those core customers who request it. At December 31, 2000, the Utility's system consisted of approximately 6,261 miles of transmission pipelines, three gas storage facilities, and approximately 37,958 miles of gas distribution lines. The Utility's Line 400/401 interconnects with the natural gas transmission system of the Utility's sister subsidiary, PG&E Gas Transmission, Northwest Corporation (PG&E GTN). The PG&E GTN pipeline begins at the border of British Columbia, Canada, and Idaho, and extends through northern Idaho, southeastern Washington and central Oregon, and ends on the Oregon-California border where it connects with the Utility's Line 400/401. The 840-mile combined Utility-PG&E GTN pipeline provides about 2,700 million cubic feet per day (MMcf/d) of capacity. More than 1,800 MMCf/d can be delivered to Northern and Southern California; and the remaining capacity can be delivered to the Pacific Northwest. The Utility's Line 300, which connects to the U.S. Southwest pipeline systems (Transwestern, El Paso, and Kern River) owned by third parties has a capacity of 1,140 MMcf/d. The Utility's underground gas storage facilities located at McDonald Island, Los Medanos, and Pleasant Creek, have a total working gas capacity of 98 billion cubic feet (Bcf). The Utility's peak day send-out of gas on its integrated system in California during the year ended December 31, 2000, was 3,795 million cubic feet (MMcf). The total volume of gas throughput during 2000 was approximately 937,000 MMcf, of which 281,000 MMcf was sold to direct end-use or resale customers, 49,000 MMcf was used by the Utility primarily for its fossil-fueled electric generating plants, and 606,000 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. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years updating recorded data for the previous year. The 2000 California Gas Report updates the Utility's annual gas requirements forecast (excluding bypass volumes) for the years 2000 through 2020, forecasting average annual growth in gas throughput served by the Utility of approximately 1.4%. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching, and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing the Utility's system entirely. 32 Gas Operating Statistics The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries) for gas, including the classification of sales and revenues by type of service.
Years Ended December 31, --------------------------------------------------------- 2000 1999 1998 1997 1996 ---------- ---------- ---------- ---------- ---------- Customers (average for the year): Residential........... 3,642,266 3,593,355 3,536,089 3,491,963 3,455,086 Commercial............ 203,355 203,342 200,620 198,453 198,071 Industrial............ 1,719 1,625 1,610 1,650 1,500 Other gas utilities... 6 4 5 3 2 ---------- ---------- ---------- ---------- ---------- Total.............. 3,847,346 3,798,326 3,738,324 3,692,069 3,654,659 ========== ========== ========== ========== ========== Gas supply--thousand cubic feet (Mcf) (in thousands): Purchased from suppliers in: Canada............... 216,684 230,808 298,125 280,084 253,209 California........... 32,167 18,956 17,724 10,655 28,130 Other states......... 75,834 107,226 122,342 131,074 110,604 ---------- ---------- ---------- ---------- ---------- Total purchased.... 324,685 356,990 438,191 421,813 391,943 Net (to storage) from storage.............. 19,420 (980) (14,468) 14,160 6,871 ---------- ---------- ---------- ---------- ---------- Total.............. 344,105 356,010 423,723 435,973 398,814 Pacific Gas and Electric Company use, losses, etc.(1)...... 62,960 47,152 129,305 173,789 134,375 ---------- ---------- ---------- ---------- ---------- Net gas for sales.. 281,145 308,858 294,418 262,184 264,439 ========== ========== ========== ========== ========== Bundled gas sales and transportation service--Mcf (in thousands): Residential........... 210,515 233,482 223,706 191,327 190,246 Commercial............ 66,443 70,093 66,082 60,803 62,178 Industrial............ 4,146 5,255 4,616 10,054 12,015 Other gas utilities... 41 28 14 0 0 ---------- ---------- ---------- ---------- ---------- Total.............. 281,145 308,858 294,418 262,184 264,439 ========== ========== ========== ========== ========== Transportation service only--Mcf (in thousands): Vintage system (Substantially all Industrial)(2)....... 606,152 484,218 396,872 218,660 189,695 PG&E Expansion (Line 401)(3).............. 0 0 0 233,269 237,776 ---------- ---------- ---------- ---------- ---------- Total.............. 606,152 484,218 396,872 451,929 427,471 ========== ========== ========== ========== ========== Revenues (in thousands): Bundled gas sales and transportation service: Residential.......... $1,680,745 $1,542,705 $1,414,313 $1,170,135 $1,109,463 Commercial........... 513,080 448,655 426,299 374,084 362,819 Industrial........... 35,347 24,638 24,634 46,592 42,520 Other gas utilities.. 0 77 1,072 3,701 510 ---------- ---------- ---------- ---------- ---------- Bundled gas revenues.......... 2,229,172 2,016,075 1,866,318 1,594,512 1,515,312 Transportation only revenue: Vintage system (Substantially all Industrial)......... 324,319 267,544 232,038 207,160 180,197 PG&E Expansion (Line 401)................ 13,392 19,091 42,194 90,180 85,144 ---------- ---------- ---------- ---------- ---------- Transportation service only revenue......... 337,711 286,635 274,232 297,340 265,341 Miscellaneous......... 84,526 (47,311) 41,364 50,295 (9,271) Regulatory balancing accounts............. 131,762 (259,648) (448,351) (137,787) 57,864 ---------- ---------- ---------- ---------- ---------- Operating revenues.......... $2,783,171 $1,995,751 $1,733,563 $1,804,360 $1,829,246 ========== ========== ========== ========== ==========
- -------- (1) 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 4,833 MMcf, 1,251 MMcf, 34,169 MMcf, 72,958 MMcf, and 78,552 MMcf for 2000, 1999, 1998, 1997, and 1996, respectively. (3) Starting in 1998, Vintage system and PG&E Expansion are combined and reported as total transportation service. 33
Years Ended December 31, ---------------------------------- 2000 1999 1998 1997 1996 ------ ------ ------ ------ ------ Selected Statistics: Average annual residential usage (Mcf)..... 59 65 63 55 55 Heating temperature--% of normal (1)....... 101.2 108.5 93.0 71.7 75.7 Average billed bundled gas sales revenues per Mcf: Residential............................... $ 7.98 $ 6.61 $ 6.32 $ 6.12 $ 5.83 Commercial................................ 7.72 6.40 6.45 6.15 5.84 Industrial................................ 8.53 4.69 5.36 4.63 3.54 Average billed transportation only revenue per Mcf: Vintage system............................ 0.54 0.66 0.66 0.71 0.67 PG&E Expansion (Line 401)................. 2.04 0.53 0.54 0.39 0.36 Net plant investment per customer (2)..... $1,003 $1,011 $1,040 $1,031 $1,061
- -------- (1) Over 100% indicates colder than normal. Natural Gas Supplies The objective of Pacific Gas and Electric Company's Gas Procurement Department is to maintain a balanced supply portfolio that provides supply reliability and contract flexibility, minimizes costs, and fosters competition among the Utility's gas suppliers. To ensure a diverse and competitive mix of natural gas to serve the Utility's customers, the Utility purchases gas directly from producers and marketers in both Canada and the United States. Due to the Utility's deteriorating financial condition resulting from the dysfunctional California wholesale power market, in December 2000 and January 2001, several gas suppliers demanded prepayment, cash on delivery, or other forms of payment assurance before they would deliver gas, instead of the normal payment terms under which the Utility would pay for the gas after delivery. As the Utility was unable to meet such demands at that time, several gas suppliers refused to supply gas accelerating the depletion of the Utility's gas storage reserves, and potentially accelerating the electric power crisis if the Utility were required to divert gas from industrial users, including natural gas fired power plant operators. The U.S. Secretary of Energy issued a temporary order on January 19, 2001, requiring the gas suppliers to make deliveries to avoid a worsening natural gas shortage emergency. However, this order expired on February 7, 2001, and certain companies, representing about 10% of the Utility's natural gas suppliers, terminated deliveries after the orders expired. The Utility tried to mitigate the worsening supply situation by withdrawing more gas from storage and, when able, purchasing additional gas on the spot market. Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge its gas account receivables and its gas inventories for up to 90 days (extended to 180 days in a CPUC draft decision issued on February 15, 2001) to secure gas for its core customers. At March 29, 2001, the amount of gas accounts receivables pledged was approximately $900 million. As of March 29, 2001, approximately 30% of the Utility's suppliers of natural gas had signed security agreements with the Utility and discussions were continuing with the Utility's other suppliers. Additionally, the Utility is currently implementing a program to obtain longer-term summer and winter supplies and daily spot supplies. The Utility has also filed an application with the CPUC to declare a gas emergency, and require one of the Utility's larger gas suppliers to sell incremental gas supplies to the Utility. The gas supplier has protested the application. The CPUC is expected to rule on the application at its meeting on April 19, 2001. Under current CPUC regulations, the Utility purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 2000, approximately 67% of the Utility's total purchases of natural gas consisted of 34 Canadian-sourced gas transported by Canadian pipeline companies and PG&E GTN, and Rocky Mountain-sourced gas transported by PG&E GTN, approximately 10% was purchased in California, approximately 21% was purchased in the U.S. Southwest and was transported primarily by the El Paso Natural Gas Company and Transwestern Pipeline Company pipelines, and approximately 2% was purchased in the Rocky Mountains and transported by Kern River Gas Transmission Company. California purchases include supplies from various California producers and supplies transported into California by others. The following table shows the total volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by the Utility from these sources during each of the last five years.
2000 1999 1998 1997 1996 ------------------ ------------------ ------------------ ------------------ ------------------ 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................. 216,684 $4.05 230,808 $2.50 298,125 $2.00 280,084 $1.77 253,209 $1.57 California............. 32,167 8.20 18,956 2.45 17,724 2.44 10,655 2.12 28,130 1.90 Other states (substantially all U.S. Southwest)....... 75,835 5.99 107,227 2.42 122,342 2.62 131,074 3.75 110,604 3.72 ------- ----- ------- ----- ------- ----- ------- ----- ------- ----- Total/Weighted Average............... 324,686 $4.92 356,991 $2.47 438,191 $2.19 421,813 $2.39 391,943 $2.21 ======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- -------- (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. Beginning March 1, 1998, the average price for gas also includes intrastate pipeline demand and reservation charges. These costs previously were bundled in gas rates. Gas Regulatory Framework In August 1997, the CPUC approved the Gas Accord, which restructured the Utility's gas services and its role in the gas market. Among other matters, the Gas Accord separates, or "unbundles," the rates for the Utility's gas transmission services from its distribution services. As a result of the Gas Accord, the Utility's customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from the Utility. Most of the Utility's industrial and larger commercial customers (noncore customers) now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial customers (core customers) buy gas as well as transmission and distribution services from the Utility as a bundled service. Customer rates for gas are updated on a monthly basis to reflect changes in the Utility's gas procurement costs. The Gas Accord also established an incentive mechanism (the core procurement incentive mechanism or CPIM) for recovery of the Utility's core gas procurement costs in rates through 2002. The CPIM provides the Utility with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs. Under the CPIM, all Utility procurement costs are compared to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are deemed reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, the Utility's ratepayers and shareholders share savings or costs, respectively. The Utility has recovered all gas costs through October 31, 1999. In February 2001, the Utility filed a CPIM performance report for the period of November 1, 1999, through October 31, 2000. The report determined that all gas commodity and transportation costs for the period are within the tolerance band, and therefore should be deemed reasonable and recoverable in full from ratepayers. The Gas Accord also established gas transmission and storage rates for the period from March 1998 through December 31, 2002. Rates for gas distribution service continue to be set by the CPUC in BCAP proceedings, and are designed to provide the Utility an opportunity to recover its costs of service and include a return on investment. See "Utility Operations--California Ratemaking Mechanisms--Gas Ratemaking--The Biennial Cost Allocation Proceeding (BCAP)." 35 In January 1998, the CPUC opened a rulemaking proceeding to explore alternative market structures in the natural gas industry in California. In January 2000, the Utility and a broad-based coalition of shippers, consumer groups, marketers, and others filed a settlement with the CPUC which reaffirmed the basic structure of the Gas Accord and would continue the Gas Accord through its original term of December 31, 2002. In May 2000, the CPUC approved the uncontested settlement. Transportation Commitments The Utility 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 the Utility will pay each year may change due to changes in tariff rates. The total demand and volumetric transportation charges paid by the Utility under these agreements were approximately $94 million in 2000. This amount includes payments made to PG&E GTN of approximately $46 million in 2000, which are eliminated in the consolidated financial statements of PG&E Corporation. 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 firm transportation capacity for its gas purchases. The Utility continues to procure gas for almost all of its core customers and, up until February 2001, procured gas for those noncore customers who chose bundled service (core subscription customers). (Core subscription service ended on February 28, 2001, and most former core subscription customers elected to receive bundled service as core customers.) The Utility is continuing its efforts to broker or assign any of its remaining contracted-for but unused interstate and Canadian transportation capacity, including unused capacity held for its core and core- subscription customers. Under a firm transportation agreement with PG&E GTN that runs through October 31, 2005, the Utility currently retains capacity of approximately 600 MMcf/d on the PG&E GTN system to support its core and core-subscription customers. The Utility has been able to broker its unused capacity on PG&E GTN's system, when not needed for core and core-subscription customers. The Utility may recover demand charges through the CPIM and through brokering activities. PG&E NATIONAL ENERGY GROUP, INC. PG&E Corporation's wholly owned subsidiary, PG&E National Energy Group, Inc. (NEG), is an integrated energy company with a strategic focus on power generation, new power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. On December 22, 2000, NEG completed the sale of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries, to El Paso Field Services Company, a subsidiary of El Paso Energy Corporation. The Texas operations that were sold included gas gathering, transportation, and processing facilities, and natural gas liquids (NGL) pipelines. In addition, during 2000, NEG completed the sale of the retail energy services and value-added services businesses of its subsidiary, PG&E Energy Services Corporation. NEG's ability to anticipate and capture profitable business opportunities created by deregulation will have a significant impact on PG&E Corporation's future operating results. Implementation of PG&E Corporation's national energy strategy depends, in part, upon the opening of energy markets to provide customer choice of supplier. Undue delays in deregulation of the electric generation and natural gas supply business could impact the pace of growth of NEG's businesses. 36 Integrated Power Generation, and Energy Trading and Marketing Business NEG manages the operations, fuel supply, and sale of electric output of its owned and leased generating facilities as an integrated portfolio with its contractually controlled generating facilities and its other marketing and trading activities. NEG had a net ownership interest in 5,230 MW of generating capacity as of December 31, 2000. In addition, NEG had 19,993 MW of gas-fired generating facilities in construction or under development for which NEG has secured the necessary turbines. NEG controls the output of 518 MW of operating generating capacity and 3,722 MW of generating capacity in construction or development through various long-term contracts as of December 31, 2000. NEG's energy marketing and trading activities are focused in markets in which it owns or controls generating facilities and in developed competitive markets. NEG's integrated power generation, and energy marketing and trading business is principally engaged in the following areas: . ownership and operation of generating facilities, . new power plant development and construction, . contractual control of generating capacity, . energy marketing and trading, and . risk management. Ownership and Operation of Generating Facilities. As of December 31, 2000, NEG had ownership or leasehold interests in 19 operating generating facilities with a net generating capacity of 5,230 MW. These facilities include five gas- fired generating facilities with a net generating capacity of 1,055 MW, ten generating facilities that primarily burn coal or waste coal, in some cases in combination with oil or gas, with a net generating capacity of 2,997 MW, three hydroelectric systems or pumped storage facilities with a net generating capacity of 1,166 MW, and one 12 MW wind generating facility. NEG provides operating and management services for 16 of its 19 owned and leased generating facilities. NEG's generating facilities fall into two categories: merchant plants and independent power projects. Merchant plants sell their electrical output in the competitive wholesale electric market on a spot basis or under contractual arrangements of various terms. Independent power projects sell all or a majority of their electrical capacity and output to one or more third parties under long-term power purchase agreements tied directly to the output of that plant. In order to provide fuel for independent power projects, natural gas and coal supply commitments are typically purchased from third parties under long- term supply agreements. All of the generating facilities developed or placed in operation before 1997 are independent power projects. NEG had a net ownership interest of 1,100 MW in independent power projects as of December 31, 2000. All other generating facilities acquired, placed in operation, or controlled through contracts, during or after 1997 are merchant plants. Generating facilities under construction or in development are expected to be operated as merchant plants. New Power Plant Development and Construction. NEG manages the development and construction of power generating facilities (sometimes referred to as "greenfield" development), which include natural gas-fired and coal-fired generating facilities, and facilities that use other power generating technologies, including hydroelectric power and wind. NEG considers a generating facility to be under construction once NEG or the lessor has acquired the necessary permits to begin construction, broken ground at the project site, and contracted to purchase the major machinery for the project, including the combustion turbines. In addition, NEG has a number of generating facilities in development. NEG considers a generating facility to be in development when NEG has contractual commitments or options to purchase the turbines necessary to complete the project or when NEG has made substantial progress in site selection, control of the site and permitting. The completion of planned development projects is subject to many factors, including but not limited to changes in governmental regulations, the timing of regulatory and environmental approvals or the failure to obtain such approvals, failure to obtain adequate financing on satisfactory terms, failure to obtain necessary equipment to operate, failure of 37 third party contractors to perform their contractual obligations, a competitor's development of a lower-cost generating plant, fluctuations in natural gas and electricity prices and the ability to successfully manage such price fluctuations, and the risks associated with marketing and selling power in the newly competitive energy market. As of December 31, 2000 NEG owned or had committed to lease or acquire six generating facilities currently under construction in five states, representing 3,006 MW. These projects are expected to be placed in service in 2001 and 2002 and since year end, NEG has placed 350 MW in commercial operation. In addition, NEG has five generating facilities in advanced development in five states, representing over 5000 MW, which it expects to be able to place into construction during 2001. NEG has secured contractual commitments and options for 60 new combustion turbines for large, gas-fired facilities, representing 19,808 MW of net generating capacity. Ten of these turbines, representing approximately 2,821 MW, are for generating facilities under construction as of December 31, 2000, (the Millennium, Lake Road, La Paloma, and Attala power plant projects). Most of these turbine commitments use the latest generation of combustion technology, commonly known as G technology. The Lake Road and La Paloma facilities are being constructed by Alstom Power, Inc. (Alstom) under fixed price construction contracts with guaranteed dates for commercial operations. Alstom has advised NEG that it may take up to three years to develop and implement modifications to its G technology turbines that are necessary to achieve the guaranteed level of efficiency and output. NEG expects that the Lake Road and La Paloma facilities will begin commercial operations at reduced performance and output levels because of the technology issues with Alstom's G technology turbines. NEG also encountered start-up problems with the Siemens Westinghouse G technology turbine installed at its Millennium facility. These problems have delayed the expected date of commercial operations for this facility, which began commercial operations in April 2001. NEG does not expect that the start- up problems with the Siemens Westinghouse G technology turbine installed at the Millennium facility will result in a reduction in the guaranteed level of efficiency or output. The construction contracts for each of the Millennium, Lake Road, and La Paloma projects provide for liquidated damages. However, these liquidated damages will not offset fully the financial impact associated with the delays of these turbines in achieving their expected level of performance. Contractual Control of Generating Capacity. NEG has increased its generating capacity through contractual control of the electric output of generating facilities owned by others. NEG has executed various long-term contracts representing 4,240 MW of generating capacity, which result in control of 518 MW of operating generating capacity and 3,722 MW of generating capacity in construction or development as of December 31, 2000. The primary method of achieving contractual control of generating capacity is through tolling agreements. Tolling agreements establish a contractual relationship that grants NEG the right to use a third party's generating facility to convert NEG's fuel, typically natural gas, to electricity. NEG has the right to decide the timing and amount of electricity production within agreed operating parameters. The owner of the facility typically receives a fixed capacity payment for the committed availability of its facility and a variable payment for production costs. The fixed payment is subject to reduction if the owner fails to meet specified targets for facility availability or other operating factors. The terms of the seven tolling agreements NEG has entered into as of December 31, 2000, range from 10 to 25 years commencing on the date of initial commercial operations of the generating facility. Most of the generating facilities are under construction or in development, with commercial operations expected to commence between 2001 and 2004. These tolling agreements provide NEG with control of gas-fired plants in the Mid-Atlantic, Midwestern, Southern, and Western regions of the United States. Energy Marketing and Trading. NEG's marketing and trading operations manage fuel supply procurement and sale of electrical output of NEG's owned and controlled generating facilities as an integrated portfolio with NEG's trading positions. During the year ended December 31, 2000, NEG sold approximately $283 million MW hours of power and an average of over 6.5 Bcf of natural gas per day. 38 Through over-the-counter and futures markets across North America, NEG engages in the marketing and trading of (1) electric energy, (2) capacity and ancillary services, (3) fuel and fuel services such as transport and storage, (4) emission credits, and (5) other related products. NEG markets and trades all types of fuels necessary for its owned and controlled generating facilities, including natural gas, coal, and oil. NEG uses derivative financial instruments to provide flexible pricing to its customers and suppliers and manage its purchase and sale commitments, including those related to NEG's owned and controlled generating facilities, gas pipelines, and storage facilities. NEG also uses derivative financial instruments to reduce its exposure relative to the volatility of market prices. Financial instruments are also used to hedge interest rate and currency volatility. NEG also evaluates and implements highly structured long-term and short-term transactions. These transactions include (1) management of third party energy assets, (2) short-term tolling arrangements, (3) management of the requirements of aggregated customer load through full requirement contracts, (4) restructured independent power project contracts, and (5) purchase and sale of transportation, storage and transmission rights through auctions and over- the-counter markets. NEG's energy marketing and trading operations provide the following products and services: Electricity Marketing and Trading. NEG aggregates electricity and related products from its owned and controlled generating facilities and other from generators and marketers. NEG then packages and sells such electricity and related products to electric utilities, municipalities, cooperatives, large industrials, aggregators and other marketing and retail entities. NEG also buys, sells and transports power to and from third parties under a variety of short-term contracts. NEG manages all of its power positions, whether from its owned and controlled generating facilities or from other contracts, as an integrated power portfolio. Natural Gas Marketing and Trading. NEG purchases natural gas from a variety of suppliers under daily, monthly, seasonal and long-term contracts with pricing, delivery and volume schedules to accommodate the requirements of NEG's owned and controlled generating facilities and its obligations under long-term structured transactions. NEG also buys, sells and arranges transportation to and from third parties under a variety of short-term agreements. NEG's natural gas marketing activities include contracting to buy natural gas from suppliers at various points of receipt, arranging transportation, negotiating the sale of natural gas, and matching natural gas receipt and delivery points to the customer based on geographic logistics and delivery costs. NEG sold an average of 6.5 Bcf per day of natural gas in 2000 transported on 44 pipelines throughout North America. NEG arranges for transportation of natural gas on interstate and intrastate pipelines through a variety of means, including short-term and long-term firm and interruptible agreements. NEG also enters into various short-term and long- term firm and interruptible agreements for natural gas storage in order to provide peak delivery services to satisfy winter heating and summer electric generating demands. Coal, Oil and Emissions Marketing and Trading. NEG buys, secures transportation for and manages the sulfur content of the coal and oil requirements of its owned and controlled generating facilities. NEG also purchases and sells coal, oil, and emissions credits from and to third parties. Load Management or Full Requirements Arrangements. Deregulation of the energy industry has provided many consumers with the ability to seek and receive customized energy services. Consumers are particularly interested in purchasing volumes of fuel and electricity that closely match their specific needs. In order to satisfy this consumer demand, an increasing number of companies aggregate blocks of customers, buy power at wholesale and deliver it to end-user consumers. As part of NEG's integrated generation, energy marketing and trading business, NEG enters into contracts to supply natural gas and electricity, known as load management or full requirements supply, to these load aggregator companies in the exact amount and quality purchased by their end-user customers. 39 NEG's largest load management contracts are the wholesale standard offer service agreements with affiliates of New England Power, from whom NEG purchased 4,800 MW of owned and controlled generating capacity in 1998. Under the wholesale standard offer service agreements, NEG supplies a fixed percentage of the full requirements of the retail customers of New England Power's affiliates who receive standard offer service in Massachusetts and Rhode Island. The price NEG receives for the electricity it provides under the wholesale standard offer service agreements has a fixed floor (which escalates automatically over time) and is subject to upward escalation if the price of natural gas and fuel oil exceed a specified threshold. NEG receives a fixed price for the electricity it provides under the standard offer service agreements. Standard offer service is intended to stimulate the retail electric markets in these states by gradually increasing the fixed price of electricity under this service. The fixed price increases by a specified amount each year and also increases if the prices of natural gas and fuel oil exceed a specified threshold. These retail customers may select alternative suppliers at any time. NEG's sales volumes and revenues under the wholesale standard offer service agreements totaled 13.2 million MW hours and $563.4 million in 2000. The wholesale standard offer service agreement for Massachusetts terminates on December 31, 2004, and the wholesale standard offer service agreement for Rhode Island terminates on December 31, 2009. Fuel Supply, Transport, and Electric Transmission Management. NEG enters into contracts for fuel supply, fuel transportation, and electric transmission primarily to meet the needs of its owned and controlled generating facilities and to capitalize on other trading opportunities. Risk Management Controls. NEG manages the risk associated with its marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of its management. NEG's senior management sets value-at-risk limitations and regularly reviews NEG's risk management policies and procedures. Within this framework, NEG's risk management committee oversees all of NEG's marketing and trading activities. All of NEG's risk management models are validated by third party experts, such as independent accountants and consultants with extensive experience in specific derivative applications. NEG's risk management group is structured as a separate unit in its organization. This management group is responsible for the day-to-day enforcement of the policies, procedures and limits of its trading and marketing activities and evaluating the risks inherent in proposed transactions. These key activities include evaluating and monitoring the creditworthiness of trading counterparties, setting and monitoring volumetric and loss limits on portfolio risks, establishing and monitoring trading limits on products, as well as on individual traders, validating trading transactions, and performing daily portfolio valuation reporting including mark-to-market valuation. 40 Description of Generating Facilities. The following table provides information regarding each of NEG's owned or controlled operating generating facilities, as well as those under construction as of December 31, 2000.
NEG Net Interest Date of Total in Total Primary Output Sales Commercial Generating Facility State MW MW(1) Structure Fuel Method Status Operation ------------------- -------------- -------- --------- --------------- ------------------------- ------------ ---------- New England Region Brayton Point Station............. MA 1,599 1,599 Owned Coal/Oil Competitive Market Operational 1963-1974 Salem Harbor Station............. MA 745 745 Owned Coal/Oil Competitive Market Operational 1952-1972 Bear Swamp Facility.. MA 599 599 Leased Water Competitive Market Operational 1974 Manchester St. Station............. RI 495 495 Owned Natural Gas Competitive Market Operational 1995 Connecticut River System.............. NH/VT 484 484 Owned Water Competitive Market Operational 1909-1957 Masspower............ MA 267 35 Owned Natural Gas Power Purchase Agreements Operational 1993 Pittsfield(2)........ MA 173 143 Leased Natural Gas Power Purchase Agreements Operational 1990 and Competitive Market Milford Power(2)..... MA 171 96 Contract Natural Gas Competitive Market Operational 1994 Deerfield River System.............. MA/VT 83 83 Owned Water Competitive Market Operational 1912-1927 Pawtucket Power(2)... RI 69 69 Contract Natural Gas Competitive Market Operational 1991 14 Smaller Facilities(2)....... Various 193 193 Contract Renewable/Waste Competitive Market Operational Various Millennium(3)........ MA 360 360 Owned Natural Gas Competitive Market Construction 2001 Lake Road............ CT 840 840 Leased Natural Gas Competitive Market Construction 2001 ------ ----- Subtotal............ 6,078 5,741 Mid-Atlantic and New York Region Selkirk.............. NY 345 145 Owned Natural Gas Power Purchase Agreements Operational 1992 and Competitive Market Carneys Point........ NJ 269 135 Owned Coal Power Purchase Agreements Operational 1994 Logan................ NJ 225 113 Owned Coal Power Purchase Agreement Operational 1994 Northampton.......... PA 110 55 Owned Waste Coal Power Purchase Agreements Operational 1995 Panther Creek........ PA 80 40 Owned Waste Coal Power Purchase Agreement Operational 1992 Scrubgrass........... PA 87 44 Owned Waste Coal Power Purchase Agreement Operational 1993 Madison.............. NY 12 12 Owned Wind Competitive Market Operational 2000 Liberty.............. PA 530 530 Contract Natural Gas Competitive Market Construction 2002 ------ ----- Subtotal............ 1,658 1,074 Midwest Region Georgetown........... IN 240 160 Contract Natural Gas Competitive Market Operational 2000 Ohio Peakers......... OH 141 141 Owned Natural Gas Competitive Market Operational 2001 ------ ----- Subtotal............ 381 301 Southern Region Indiantown........... FL 360 126 Owned Coal Power Purchase Agreement Operational 1995 Cedar Bay............ FL 269 135 Owned Coal Power Purchase Agreement Operational 1994 Attala............... MS 500 500 Owned Natural Gas Competitive Market Construction 2001 SRW(4)............... TX 420 250 Contract Natural Gas Competitive Market Construction 2001 ------ ----- Subtotal............ 1,549 1,011 Western Region Hermiston............ OR 474 237 Owned Natural Gas Power Purchase Agreement Operational 1996 Colstrip............. MT 40 5 Owned Waste Coal Power Purchase Agreement Operational 1990 Mountain View........ CA 44 44 Owned(5) Wind Competitive Market Construction 2001 La Paloma............ CA 1,121 1,121 Leased Natural Gas Competitive Market Construction 2002 ------ ----- Subtotal............ 1,679 1,407 ------ ----- Total............ 11,345 9,534 ====== =====
- ------- (1) NEG's net interest in an independent power project is determined by multiplying NEG's percentage of the project's expected cash flow by the project's total MW. (2) NEG controls all or a portion of the output of 17 smaller generating facilities under long-term power purchase agreements. In return for NEG's assumption of the purchase obligations under these agreements from the New England Power Company, the New England Power Company has agreed to pay an average of $111 million per year through January 2008 to offset NEG's payment obligations under these contracts. The facilities NEG controls in whole or in part through these power purchase agreements include the Milford Power Project, the Pittsfield Project, the Pawtucket Power Project, and 14 other small generating facilities with a total generation capacity of 193 MW fueled by municipal waste, water, landfill gas, or wood. The power purchase agreements terminate between 2009 and 2029. (3) Millenium achieved commercial operation in April 2001. (4) An NEG subsidiary entered into a contract with SRW Cogeneration Limited partnership dated as of July 30, 1999 pursuant to which NEG would control 250 MW of a 420 MW cogeneration facility the limited partnership is building and is to operate. The limited partnership has provided NEG with notice of its purported termination of the contract, which NEG is contesting. (5) NEG has executed a contract to purchase the Mountain View facility. The purchase has not yet closed. 41 Competition. Some of the competitive factors affecting the results of operations of NEG's owned and controlled generating facilities include new market entrants, construction by others of more efficient generating facilities and the number of years and extent of operations in a particular energy market. Other competitors operate generating facilities in the regions where NEG has invested in generation facilities. Although local permitting and siting issues often reduce the risk of a rapid growth in supply of generating capacity in any particular region, projects are likely to be built over time which will increase competition and lower the value of some of NEG's generating facilities. There is also significant competition for the development and acquisition of domestic unregulated generating facilities. NEG competes against a number of other participants in the non-utility power generation industry. Competitive factors relevant to the non-utility power industry include financial resources, development expenses, and regulatory factors. Some of NEG's competitors have greater financial resources than NEG has. NEG's energy marketing and trading operations compete with other energy merchants based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers, and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy marketing and trading business and as deregulation in the electricity markets continues to evolve, NEG anticipates that its energy, marketing and trading operations will experience greater competition and downward pressure on per-unit profit margins. Natural Gas Transmission Business NEG's natural gas transmission business currently consists of the PG&E GT- Northwest (PG&E GTN) pipeline, a 5.2% interest in the Iroquois Gas Transmission System and the North Baja pipeline under development. The following table summarizes NEG's gas transmission pipelines:
12 month In Service Capacity capacity Length Ownership Pipeline Name Location Date (MMcf/d) factor (miles) Interest - ------------- -------- ---------- -------- -------- ------- --------- PG&E GT-Northwest....... ID, OR, WA 1961 2,700 96% 1,335 100% Iroquois Gas Transmission System.... NY 1991 900 95% 375 5.2% North Baja.............. AZ, CA, 2002 500 N/A 80 100%
PG&E GT-Northwest (PG&E GTN). PG&E GTN owns and operates the PG&E GTN pipeline. This pipeline consists of over 1,300 miles of natural gas transmission mainline pipe with a capacity of 2.7 Bcf of natural gas per day. The PG&E GTN pipeline begins at the British Columbia-Idaho border, extends through northern Idaho, southeastern Washington and central Oregon, and ends on the Oregon-California border where it connects with other pipelines. This pipeline is the largest transporter of Canadian natural gas into the United States. For the year ended December 31, 2000, this pipeline transported 967 Bcf of natural gas, resulting in a 5% growth in transported volumes from the previous year. Since this pipeline commenced commercial operations in 1961, it has experienced a five-fold increase in peak system capacity. The PG&E GTN pipeline is the only interstate pipeline directly connecting the large and rapidly growing gas markets of California, Nevada, and the Pacific Northwest with the abundant natural gas supplies of the Western Canadian Sedimentary Basin and potentially the natural gas rich North Slope of Alaska and Northwest Territories of Canada. The pipeline transports over 30% of California's natural gas demand requirements and over 20% of the Pacific Northwest natural gas demand requirements. 42 The mainline system of the PG&E GTN pipeline consists of two parallel pipelines with 13 compressor stations totaling approximately 414,450 horsepower. This dual-pipeline system consists of approximately 639 miles of 36-inch mainline pipe and approximately 590 miles of 42-inch mainline pipe. The original pipeline commenced commercial operations in 1961 and was expanded throughout the 1960's and 1970, 1981, 1993, 1995 and 1998. The PG&E GTN pipeline includes two laterals, the Coyote Springs Lateral that supplies natural gas to Portland General Electric Company and the Medford Lateral that supplies natural gas to Avista Utilities. This pipeline interconnects with facilities owned by the Utility at the Oregon-California border and with interstate pipelines in northern Oregon, eastern Washington, and southern Oregon. It also delivers gas along various mainline delivery points to two local gas distribution companies of various mainline delivery points. The PG&E GTN pipeline provides firm and interruptible transportation services to third party shippers on a nondiscriminatory basis. Firm transportation services means that the customer has the highest priority rights to ship a quantity of gas between two points for the term of the applicable contract. The pipeline's long-term capacity is 100% committed to firm transportation services agreements with terms in excess of one year. The remaining terms of these agreements range between one and 26 years with a volume-weighted average of approximately 13 years. In addition, due to weather, maintenance schedules, and other conditions, additional firm capacity may become available on a short-term basis. Interruptible transportation is offered when short-term capacity is available due to a firm transportation customer not fully utilizing its committed capacity. Hub services are also offered, which allow customers the ability to park or lend volumes of gas on the pipeline. The PG&E GTN pipeline currently provides transportation services for over 65 customers, including local retail gas distribution utilities, electric utilities that utilize natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas on a wholesale and retail basis, natural gas producers, and industrial companies. The customers are responsible for securing their own gas supplies and delivering them to the pipeline system. The customers' natural gas supplies are transported either to downstream pipelines and distribution companies or directly to points of consumption. PG&E GTN's current rates were set in a rate settlement approved by the FERC in September 1996. North Baja Pipeline. NEG recently joined with Sempra Energy International and Mexico's Proxima Gas, S.A. de C.V. to develop a 215-mile pipeline that will supply natural gas to Northern Mexico and Southern California. This pipeline will begin at an interconnection with El Paso Natural Gas Company near Ehrenberg, Arizona, traverse southeastern California and northern Baja California, Mexico and terminate at an interconnection with the Rosarito Pipeline south of Tijuana. An application has been filed with the FERC for a certificate to build the 80-mile U.S. segment of this proposed $230 million project. Sempra Energy International and Proxima Gas will direct development of the 135-mile Mexico segment. This pipeline will have an initial capacity of 500 million cubic feet per day with expansion capability to 800 million cubic feet per day. NEG has signed agreements with five anchor customers to transport almost 90% of the projected daily capacity of 500,000 million cubic feet of natural gas. The average term of these agreements is 20 years. NEG is continuing discussions and negotiations with other potential customers. This pipeline is projected to be in service by the fourth quarter of 2002. In its initial design, this pipeline is intended primarily to serve electric generating needs in northern Mexico and Southern California, as well as industrial and local distribution company load along the Mexico segment. Further, NEG believes that this pipeline will also have the potential to serve delivery points along its entire route. Competition. NEG's gas transmission business competes with other pipeline companies for transportation customers on the basis of transportation rates, access to competitively priced gas supply and growing markets served by its pipelines, and the quality and reliability of transportation services. The competitiveness of a pipeline's transportation services to any market is generally determined by the total delivered natural gas price from a particular natural gas supply basin to the market served by the pipeline. 43 The PG&E GTN pipeline accesses natural gas supplies from Western Canada and serves markets in the Pacific Northwest, California, and Nevada. PG&E GTN competes with other pipelines to access natural gas supplies in Western Canada, the Rocky Mountain, the Southwest, and British Columbia. NEG's transportation volumes are also affected by the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may become available based on ample snowfall and displace demand for natural gas as a fuel for electric generation. Finally, in providing interruptible and short-term firm transportation service, NEG competes with released capacity offered by shippers holding firm contracts for NEG's capacity. 44 ENVIRONMENTAL MATTERS Environmental Matters The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. This information below reflects current estimates, which are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recoveries or contributions from third parties. PG&E Corporation, the Utility, and various NEG affiliates (including USGen New England, Inc. (USGenNE)) 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, air and water pollution, and 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. The Utility has undertaken 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 Utility's bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations generally have been recovered in rates. Although the Utility has sold most of its fossil-fueled power plants and its geothermal generation facilities in connection with electric industry restructuring, the Utility has retained liability for certain required environmental remediation of pre-closing soil or groundwater contamination for fossil and geothermal generation facilities that have been sold. See "Utility Operations--Electric Utility Operations--California Electric Industry Restructuring--Voluntary Generation Asset Divestiture" above. Environmental Protection Measures The estimated expenditures of PG&E Corporation's subsidiaries for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. It is likely that the stringency of environmental regulations will increase in the future. As a result of the Utility's divestiture of most of its fossil-fueled power plants and its geothermal generation facilities, the Utility's oxides of nitrogen (NOx) emission reduction compliance costs have been reduced significantly. 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, two of the local air districts in which the Utility owns and 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). 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 gas from the Southwest. Other air districts are considering NOx rules that would apply to the Utility's other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at many of these natural gas compressor stations. The Utility currently estimates that the total cost of complying with these various NOx rules will be up to $101 million from 2001 through 2004. The Utility is planing to replace some compressor units because proven NOx retrofit technology is not available for these units. Substantially all of these costs will be capital costs. 45 Compliance by NEG affiliates with certain future regulatory requirements limiting the total amount of NOx emissions from its fossil-fueled power plants is expected to be achieved through installation of additional controls, fuel switching, and purchase of NOx allowances. USGenNE has agreed to be bound by a number of state and regional initiatives that will require it to achieve significant reductions of sulfur dioxide (SO2) and NOx emissions by the time its older fossil-fueled power plants have been in operation for 40 years or by 2010, whichever comes first. It is expected that USGenNE can meet these requirements through utilization of allowances it currently owns, installation of additional controls, or purchase of additional allowances. (SO2 allowances are emission credits that are traded in a national market under the United States Environmental Protection Agency's (EPA) Acid Rain Program. NOx allowances are emission credits that are traded in a regional market consisting of seven Northeast states known as the Ozone Transport Region.) In October and November 1999, the EPA and several states filed suits or announced their intention to file suits against a number of coal-fired power plants in Midwestern and Eastern states. These suits relate to alleged violations of the Clean Air Act. More specifically, they allege violations of the deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements arising out of certain physical changes that may have been made at these facilities without first obtaining the required permits. In May 2000, USGenNE received a request for information pursuant to Section 114 of the Clean Air Act from the EPA seeking detailed operating and maintenance history for the Salem Harbor and Brayton Point power plants, which USGenNE acquired in 1998 from the New England Electric System (NEES). USGenNE believes that this request for information is part of the EPA's industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications, and operational changes made to coal- fired facilities over the years. If the EPA were to find that there were physical changes made in the past that were undertaken without first receiving the required permits under the Clean Air Act, then penalties may be imposed and further emission reductions might be necessary at these plants. A new ambient air quality standard was adopted by the EPA in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in NOx and SO2, although under the time schedule announced by the EPA when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the EPA, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the EPA to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard on the Utility's and NEG's facilities is uncertain at this time. If an ambient air quality standard for fine particulates is promulgated, further NOx and SO2 reductions may be required for those Utility and NEG facilities located in areas where sampling indicates the ambient air does not comply with the final standards that are adopted. Since the adoption of the United Nations Framework on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton Administration participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels. However, because of opposition to the treaty in the United States Senate, the Kyoto Protocol has not been submitted to the Senate for ratification. If the U.S. Senate ultimately ratifies the Kyoto Protocol and greenhouse gas emission reduction requirements are implemented, the resulting limitations on power plant carbon dioxide emissions could have a material adverse impact on all fossil fuel-fired facilities, including Utility and NEG facilities. 46 The EPA has announced that it will regulate steam electric generating plants under Title III of the Clean Air Act, which addresses emissions of hazardous air pollutants from specific industrial categories. Power plants are a source of mercury air emissions. The EPA recently signed a regulatory finding that commits it to propose a mercury-emissions rule applicable to fossil-fuel fired power plants by 2003 and to promulgate a final rule by 2004. According to this regulatory finding, affected facilities will have to comply with this final rule in 2007-2008. The rulemaking process will likely include significant stakeholder and public participation both before and after the emission standards are proposed. The applicable control level is uncertain, as is the cost of these future rules. In addition to the EPA, states may impose more stringent air emissions requirements. The Commonwealth of Massachusetts is considering the adoption of more stringent air emission reductions from electric generating facilities. If adopted, these requirements will impact Salem Harbor and Brayton Point. NEG has proposed an emission reduction plan that may include modernization of the Salem Harbor power plant and use of advanced technologies for emissions removal. It is also studying various advanced technologies for emissions removal for the Brayton Point power plant. NEG currently estimates that USGenNE's total capital cost for complying with the requirements described here will be approximately $300 million. 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. The Utility's fossil-fueled power plants comply in all material respects with the discharge constituents standards and the thermal standards. Additionally, pursuant to Section 316(b) of the Federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each power plant's intake structure to various governmental agencies and each plant's existing intake structure was found to meet the BTA requirements. The Diablo Canyon Power Plant employs a "once through" cooling water system which is regulated under a National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology meets the BTA requirements. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $4.5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment prior to final approval by the Central Coast Board and, once signed by the parties, will be incorporated in a consent decree to be entered in California Superior Court. For a description of another environmental regulatory matter affecting the Utility, see "Item 3--Legal Proceedings--Moss Landing Power Plant," below. NEG's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. As to the facilities for which their NPDES permit has expired, permit renewal applications are pending, and it is anticipated that all 47 three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGenNEs cost to comply with the new permit conditions could be as much as $55 million through 2005. 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 the Utility's and NEG's power plants in the future. Costs to comply with new permit conditions required to meet more stringent requirements that might be imposed cannot be estimated at the present time. Hazardous Waste Compliance and Remediation PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling, and disposal requirements promulgated by the EPA under the RCRA and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with other state hazardous waste laws and other environmental requirements. One part of this program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plants produced lampblack and tar residues, byproducts of a process that Pacific Gas and Electric Company, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility's manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites that operated in the Utility's service territory. The Utility owns all or a portion of 29 of these manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites that the Utility owns. It is estimated that the Utility's program may result in expenditures of approximately $5 million in 2001. 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 the Utility is found to be responsible for cleanup at sites it currently does not own. In addition to the manufactured gas plant sites, the Utility 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. With respect to the Casmalia site near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires these generators to perform certain site investigation and mitigation measures, and provides a release from liability for certain other site cleanup obligations. Recently, the EPA asserted that the Utility sent more waste to the site than was believed previously. The Utility is evaluating the significance of this information, which may impact the amount the Utility ultimately has to pay for this site. Although the Utility has not been formally designated a potentially responsible party (PRP) with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed the Utility and other parties to initiate measures with respect to the study and remediation of that site. In addition, Pacific Gas and Electric Company has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites the Utility no longer owns or never owned. 48 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 may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. At December 31, 2000, the Utility expected to spend $320 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants, where such costs are probable and quantifiable. (Although the Utility has sold most of its fossil-fueled power plants, the Utility has retained pre-closing environmental liability with respect to these plants.) The Utility had an accrued liability of $294 million at December 31, 2000, representing the discounted value of these costs. Environmental remediation at identified sites may be as much as $462 million if, among other things, other PRPs are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Utility is responsible. The Utility estimated the upper limit of the range of costs using assumptions least favorable to the Utility based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. USGenNE acquired the onsite environmental liability associated with its acquisition of electric generating facilities from NEES, but did not acquire any offsite liability associated with the past disposal practices at the acquired facilities. NEG has obtained pollution liability and environmental remediation insurance coverage to limit the financial risk associated with the on-site pollution liability at all of its facilities. During April 2000, an environmental group served various affiliates of NEG, including USGenNE, with a notice of intent to file a citizen's suit under RCRA. The group stated that it planned to allege that USGenNE, as the generator of fossil fuel combustion wastes at Salem Harbor and Brayton Point, has contributed and is contributing to the past and present handling, storage, treatment and disposal of wastes at those facilities which may present an imminent and substantial endangerment to the public health or the environment. During September 2000, USGenNE signed a series of agreements with the Massachusetts Department of Environmental Protection and the environmental group that address and resolve these matters. The agreements, which have been filed in federal court and are now incorporated in a consent decree, require, among other things, that USGenNE alter its existing waste water treatment facilities at both facilities by replacing certain unlined treatment basins, submit and implement a plan for the closure of such basins, and perform certain environmental testing at the facilities. These activities are now well underway. The cost of these activities is expected to be approximately $21 million. 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. Under the HWRC 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. Insurance recoveries are assigned 70% to shareholders and 30% to ratepayers until both are reimbursed for the costs of pursuing insurance recoveries. The balance of insurance recoveries is allocated 90% to shareholders and 10% to ratepayers until shareholders are reimbursed for their 10% share of cleanup costs. Any unallocated funds remaining are held for five years and then distributed 60% to ratepayers and 40% to shareholders over the next five years. The Utility can seek to recover hazardous substance cleanup costs under the HWRC in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related cleanup costs for contamination caused by events occurring after January 1, 1998. For each divested generation facility where the Utility retained environmental remediation liabilities, the plant's decommissioning cost estimate was adjusted by the Utility's estimated forecast of environmental remediation costs. (The buyers assumed the non-environmental decommissioning liability for these plants.) The CPUC ordered that excess recoveries of environmental and non-environmental decommissioning accruals related to the divested plants be used to offset other transition costs. As of December 31, 2000, the Utility has recovered 49 from ratepayers approximately $114 million for environmental decommissioning accrual related to the divested plants. This amount will earn interest at 3% per year that will be used to meet the future environmental remediation costs for the divested plants. The net decommissioning accruals recovered from ratepayers attributable to the non-environmental liability for the divested plants was approximately $53 million. Because the Utility no longer has this non-environmental decommissioning liability, it has used this excess recovery amount to reduce other transition costs. The $320 million accrued liability at December 31, 2000 mentioned above includes (1) $140 million related to the pre-closing remediation liability, discounted to present value at 7%, associated with divested generation facilities (see further discussion in the "Generation Divestiture" section of Note 2 of the Notes to the Consolidated Financial Statements of the 2000 Annual Report to Shareholders), and (2) $180 million related to remediation costs for those generation facilities that the Utility still owns. Of the $320 million environmental remediation liability, the Utility has recovered $168 million through rates, and expects to recover another $87 million in future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate. In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Utility previously had notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, the Utility's carriers neither admitted nor denied coverage, but requested additional information from the Utility. Although the Utility has received some amounts in settlements with certain of its insurers (approximately $83 million through December 31, 2000), the ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time. Insurance recoveries are subject to the HWRC mechanism discussed above. Compressor Station Litigation Several cases have been brought against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Utility's Hinkley, Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings-- Compressor Station Chromium Litigation" below, for a description of the pending litigation. Electric and Magnetic Fields In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce 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. It is expected that the CPUC and the California Department of Health Services will complete its EMF research program by December 2001. As part of its effort to educate the public about EMF, Pacific Gas and Electric Company provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings. 50 The Utility currently is not involved in third-party litigation concerning EMF. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. The Utility was a defendant in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMF. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMF and barred plaintiffs' personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case. If 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, the Utility 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 ultimately is required. Low Emission Vehicle Programs In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding, which approved approximately $42 million in funding for Pacific Gas and Electric Company's LEV program for the six-year period beginning in 1996. The CPUC's decision on electric industry restructuring found that the costs of utility LEV programs should continue to be collected by the utility for the duration of the six-year period. The Utility continues to run its LEV program as funded. Annual LEV accomplishment reports are filed with the CPUC on November 1. 51 ITEM 2. Properties. Information concerning Pacific Gas and Electric Company's electric generation units, electric and gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All of the Utility's real properties and substantially all of the Utility's personal properties are subject to the lien of an indenture that provides security to the holders of the Utility's First and Refunding Mortgage Bonds. Information concerning properties and facilities owned by PG&E National Energy Group, Inc. and other PG&E Corporation subsidiaries is included in the discussion under the heading of this report entitled "PG&E National Energy Group, Inc." ITEM 3. Legal Proceedings. See Item 1, Business, for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, PG&E Corporation and Pacific Gas and Electric Company are subject to routine litigation incidental to their business. Pacific Gas and Electric Company Bankruptcy On April 6, 2001, Pacific Gas and Electric Company filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdiction of the Bankruptcy Court. For more information about the Utility's financial condition and the factors leading up to the filing for bankruptcy protection, see "Management's Discussion and Analysis" and Notes 2 and 3 of the 2000 Annual Report to Shareholders, which portions are incorporated herein by reference and filed as Exhibit 13 to this report. Pacific Gas and Electric Company vs. California Public Utilities Commissioners On November 8, 2000, Pacific Gas and Electric Company filed a lawsuit in the United States District Court for the Northern District of California against the CPUC commissioners, asking the court to declare that the federally approved wholesale power costs the Utility has incurred to serve its customers are recoverable in retail rates. As of December 31, 2000, the uncollected wholesale power purchase costs recorded in the Utility's TRA was $6.6 billion. (As described above, the Utility recognized a fourth quarter 2000 charge to earnings of $6.9 billion ($4.1 billion after tax), reflecting the write-off of undercollected power purchase costs and other generation-related regulatory assets.) The complaint states that the wholesale power costs which the Utility has prudently incurred are paid pursuant to filed rates which the FERC has authorized and approved, and that under the United States Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility's complaint also alleges that to the extent that the Utility is denied recovery of these mandated wholesale power costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property. The Utility argues that the CPUC's decisions violate federal preemption law and the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full its reasonable procurement costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also pleads claims under the Commerce Clause, Due Process Clause, and Equal Protection Clause of the United States Constitution. On January 29, 2001, the Utility's lawsuit was transferred to the U.S. District Court for the Central District of California where a similar lawsuit filed by Southern California Edison is pending. On March 19, 2001, the court heard argument on the CPUC's motion to dismiss the case. The judge took the matter under submission. Wilson vs. PG&E Corporation and Pacific Gas and Electric Company On February 13, 2001, two complaints were filed against PG&E Corporation and Pacific Gas and Electric Company in the Superior Court of the State of California, San Francisco County: Richard D. Wilson v. Pacific 52 Gas and Electric Company et al. ("Wilson I"), and Richard D. Wilson v. Pacific Gas and Electric Company et al., ("Wilson II"). In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation violated its fiduciary duties and California Business and Professions Code Section 17200 by causing the Utility to repurchase shares of Pacific Gas and Electric Company common stock from PG&E Corporation at an aggregate price of $2.326 billion. The complaint alleges an unlawful business act or practice under Section 17200 because these repurchases allegedly violated PG&E Corporation's fiduciary duties, a first priority capital requirement allegedly imposed by the CPUC's decision approving the formation of a holding company, and also an implicit public trust imposed by AB 1890, which granted authority for the issuance of rate reduction bonds. The complaint seeks to enjoin the repurchase by the Utility of any more of its common stock from PG&E Corporation or other entities or persons unless good cause is shown, and seeks restitution from PG&E Corporation of $2.326 billion, with interest, on behalf of the Utility. The complaint also seeks an accounting, costs of suit, and attorney's fees. In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and other subsidiaries have been parties to a tax-sharing arrangement under which PG&E Corporation annually files consolidated federal and state income tax returns for, and pays, the income taxes of PG&E Corporation and participating subsidiaries. According to the plaintiff, between 1997 and 1999, PG&E Corporation collected $2.957 billion from the Utility under this tax-sharing arrangement, but paid only $2.294 billion (net of refunds) to all governments under the tax-sharing arrangement. Plaintiff alleges that these monies were held under an express and implied trust to be used by PG&E Corporation to pay the Utility's share of income taxes under the tax-sharing arrangement. Plaintiff alleges that PG&E Corporation overcharged the Utility $663 million under the tax-sharing arrangement and has declined voluntarily to return these monies to the Utility, in violation of the alleged trust, the alleged first priority capital condition, and California Business and Professions Code Section 17200. The complaint seeks to enjoin PG&E Corporation from engaging in the activities alleged in the complaint (including the tax-sharing arrangement), and seeks restitution from PG&E Corporation of $663 million, with interest, on behalf of the Utility. The complaint also seeks an accounting, costs of suit, and attorney's fees. PG&E Corporation and the Utility believe these complaints to be without merit. The Utility filed a notice of automatic stay on April 11, 2001, pursuant to the Bankruptcy Code. PG&E Corporation believes that these actions also are stayed against PG&E Corporation. PG&E Corporation and the Utility are unable to predict whether the outcome of this litigation, if it were to proceed, will have a material adverse affect on their financial condition or results of operation. Moss Landing Power Plant In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water and organic debris from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings and the Central Coast Board requested additional information from the purchaser. The Utility initiated an investigation of these activities during the time it owned the plant. The Utility notified the Central Coast Board that it had undertaken an investigation and that it would present the results to the Central Coast Board when the investigation was completed. In March 2000, the Central Coast Board requested the Utility to provide specific information regarding the "backflush" procedure used at Moss Landing. The Utility provided the requested information in April 2000. The Utility's investigation indicated that while the Utility owned Moss Landing, significant amounts of water were discharged from the cooling water intake. While the Utility's investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes that the temperature of the discharged water was higher than that of the receiving water. In December 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which the Utility would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. Settlement negotiations are continuing. 53 PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial position or results of operations. Compressor Station Chromium Litigation Pacific Gas and Electric Company is currently a defendant in nine civil actions pending in California courts. These cases are (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995 in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996 in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996 in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed on July 25, 2000 in Los Angeles Superior Court, (5) Baldonado vs. Pacific Gas and Electric Company, filed On October 25, 2000 in Los Angeles Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed on January 30, 2001 in Los Angeles Superior Court, (7) Monice v. PG&E, filed March 15, 2001, in San Bernardino County Superior Court, (8) Puckett v. PG&E, filed March 30, 2001, in Los Angeles Superior Court, and (9) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles Superior Court. PG&E has not yet been served with the complaint in Gale v. PG&E, Puckett v. PG&E, or Alderson v. PG&E. There are now approximately 1,150 plaintiffs in the compressor station chromium litigation with claims against the Utility. PG&E Corporation has been named as a defendant in Alderson v. PG&E, et al., a complaint brought on behalf of approximately 100 plaintiffs. PG&E Corporation has not yet been served with the complaint. Betz Chemical Company (Betz), the supplier of water treatment products containing chromium used at the gas compressor stations, also was named as a defendant in some of these cases. During 2000, pursuant to a settlement that Betz reached with the approximately 1,650 plaintiffs suing Betz, the Utility received a credit of up to $40 million to be allocated among the approximately 900 plaintiffs suing the Utility at the time of the Betz settlement. The credit will apply to future awards of damages against the Utility with respect to all claims and causes of actions by these plaintiffs except claims for punitive or exemplary damages. Each of the complaints alleges personal injuries and seek compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of the Utility's gas compressor stations located at Kettleman, Hinkley, and Topock, California. The plaintiffs include current and former Utility employees and their relatives, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim loss of consortium or wrongful death. The discovery referee has set the procedures for selecting 18 trial test plaintiffs and 2 alternates in the Aguayo, Acosta, and Aguilar cases (the "Aguayo Litigation"). Ten of these trial test plaintiffs were selected by plaintiffs' counsel, seven plaintiffs were selected by defense counsel, and one plaintiff and two alternates were selected at random. Although a date for the first test trial in the Aguayo Litigation has been set for July 2, 2001, in Los Angeles Superior Court, the Utility's Chapter 11 bankruptcy filing on April 6, 2001, automatically stayed all proceedings. The Utility is responding to the complaints and asserting affirmative defenses. The Utility will pursue factual defenses including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged and appropriate legal defenses including statute of limitations or exclusivity of workers' compensation laws. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged, and the Utility is attempting to gather information concerning the alleged type and duration of exposure, the nature of injuries alleged by individual plaintiffs, and the additional facts necessary to support its legal defenses, in order to better evaluate and defend this litigation. There has been heightened media attention to the chromium litigation for a variety of reasons. In a letter dated March 27, 2001, the California Department of Health Services asked the California Environmental Protection Agency's Office of Environmental Health Hazard Assessment, ("OEHHA") to establish a public health goal for chromium 6 in drinking water. In turn, OEHHA has asked the University of California to establish a blue-ribbon panel of scientists to study the potential of chromium 6 to cause cancer when ingested. These 54 regulatory developments followed in part from substantial media attention concerning the presence of chromium 6 in certain water sources in Los Angeles, where the Aguayo Litigation is pending. The chromium issues have also been mentioned in media stories concerning the California energy crisis. All of this media and regulatory attention has the potential to adversely impact the Utility's defense of these cases. PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or the Utility's future financial position or results of operations. See Note 15 of the "Notes to Consolidated Financial Statements" beginning on page 83 of the 2000 Annual Report to Shareholders, portions of which are filed as Exhibit 13 to this report. Texas Franchise Fee Litigation On December 22, 2000, NEG completed the sale of PG&E GTT to El Paso Energy Field Services, Inc., a subsidiary of El Paso Energy Corporation. The PG&E GTT entities which were sold included the defendants in several cases which have been referred to as the Texas Franchise Fee Litigation in PG&E Corporation's and the Utility's Annual Report on Form 10-K for the year ended December 31, 1999 and previous reports filed with the Securities and Exchange Commission. Only one PG&E Corporation affiliate, PG&E Energy Trading--Gas Corporation, remains as a nominal defendant in some of these cases and any potential liability of this entity is expected to be immaterial. ITEM 4. Submission of Matters to a Vote of Security Holders. Not applicable. 55 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 2000 Position ---- ------------ -------- R. D. Glynn, Jr..... 58 Chairman of the Board, Chief Executive Officer, and President T. G. Boren......... 51 Executive Vice President; Chairman, President, and Chief Executive Officer, PG&E National Energy Group, Inc. P. A. Darbee........ 48 Senior Vice President, Chief Financial Officer, and Treasurer T. W. High.......... 53 Senior Vice President, Administration and External Relations P. C. Iribe......... 50 Senior Vice President; President and Chief Operating Officer, East Region, PG&E National Energy Group, Inc. T. B. King.......... 39 Senior Vice President; President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc. L. E. Maddox........ 45 Senior Vice President; President and Chief Operating Officer, Trading, PG&E National Energy Group, Inc. G. R. Smith......... 52 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company G. B. Stanley....... 54 Senior Vice President, Human Resources B. R. Worthington... 51 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, Chairman of the Board, January 1, 1998 to present Jr. ............. Chief Executive Officer, and President Chairman of the Board, January 1, 1998 to present Pacific Gas and Electric Company President and Chief June 1, 1997 to present 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 T. G. Boren...... Executive Vice President August 1, 1999 to present Chairman, President, and July 1, 2000 to present Chief Executive Officer, PG&E National Energy Group, Inc. President, and Chief Executive Officer, PG&E National Energy Group, August 1, 1999 to June 30, 2000 Inc. President and Chief February 18, 1992 to July 31, 1999 Executive Officer, Southern Energy, Inc. Executive Vice June 1, 1999 to July 31, 1999 President, Southern Company Senior Vice President, February 16, 1998 to May 31, 1999 Southern Company Vice President, Southern July 17, 1995 to February 15, 1998 Company P. A. Darbee..... Senior Vice President, September 20, 1999 to present Chief Financial Officer, and Treasurer Vice President and Chief June 30, 1997 to September 19, 1999 Financial Officer, Advance Fibre Communications, Inc. Vice President, Chief January 10, 1994 to June 30, 1997 Financial Officer, and Controller, Pacific Bell
56
Name Position Period Held Office ---- -------- ------------------ T. W. High....... Senior Vice President, June 1, 1997 to present Administration and External Relations Senior Vice President, June 1, 1995 to May 31, 1997 Corporate Services, Pacific Gas and Electric Company P. C. Iribe...... Senior Vice President January 1, 1999 to present President and Chief April 6, 2000 to present Operating Officer, East Region, PG&E National Energy Group, Inc. President and Chief November 1, 1998 to April 5, 2000 Operating Officer, PG&E Generating Company (formerly known as U.S. Generating Company) Executive Vice President September 1, 1997 to October 31, 1998 and Chief Operating Officer, U.S. Generating Company Executive Vice May 17, 1994 to September 1, 1997 President, Marketing, Development, and Asset Management, U.S. Generating Company T. B. King....... Senior Vice President January 1, 1999 to present President and Chief April 6, 2000 to present Operating Office, West Region, PG&E National Energy Group, Inc. President and Chief November 23, 1998 to present Operating Officer, PG&E Gas Transmission Corporation President and Chief February 14, 1997 to November 22, 1998 Operating Officer, Kinder Morgan Energy Partners, L.P. Vice President, July 1, 1995 to February 14, 1997 Commercial Operations-- Midwest Region, Enron Liquid Services Corporation L. E. Maddox..... Senior Vice President June 1, 1997 to present President and Chief April 6, 2000 to present Operating Officer, Trading, PG&E National Energy Group, Inc. President and Chief May 12, 1997 to April 5, 2000 Executive Officer, PG&E Energy Trading-Gas Corporation President, PennUnion May 1995 to May 1997 Energy Services, L.L.C. G. R. Smith...... Senior Vice President January 1, 1999 to present (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 present 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 B. R. Worthington...... Senior Vice President June 1, 1997 to present and General Counsel General Counsel December 18, 1996 to May 31, 1997 Senior Vice President June 1, 1995 to June 30, 1997 and General Counsel, Pacific Gas and Electric Company
57 "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:
Name Age at December 31, 2000 Position ---- ------------------------ -------- G. R. Smith........ 52 President and Chief Executive Officer K. M. Harvey....... 42 Senior Vice President, Chief Financial Officer, and Treasurer R. J. Peters....... 46 Senior Vice President and General Counsel J. K. Randolph..... 56 Senior Vice President and Chief of Utility Operations D. D. Richard, 50 Senior Vice President, Public Jr. ............... Affairs G. M. Rueger....... 50 Senior Vice President, and Chief Nuclear Officer
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 present 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, November 1, 2000 to present Chief Financial Officer, and Treasurer Senior Vice President, January 1, 2000 to October 31, 2000 Chief Financial Officer, Controller, and Treasurer Senior Vice President, July 1, 1997 to December 31, 1999 Chief Financial Officer, and Treasurer Vice President and June 1, 1995 to June 30, 1997 Treasurer R. J. Peters......... Senior Vice President January 1, 1999 to present and General Counsel Vice President and July 1, 1997 to December 31, 1998 General Counsel Chief Counsel, January 1, 1993 to June 30, 1997 Regulatory J. K. Randolph....... Senior Vice President April 6, 2000 to present and Chief of Utility Operations Senior Vice President July 1, 1997 to April 5, 2000 and General Manager, Transmission, Distribution and Customer Service Business Unit Vice President and January 1, 1997,to June 30, 1997 General Manager, Power Generation, Business Unit Vice President, Power November 1, 1991 to December 31, 1996 Generation D. D. Richard, Jr. .. Senior Vice President, May 1, 1998 to present Public Affairs Senior Vice President, July 1, 1997 to April 30, 1998 Governmental and Regulatory Relations Senior Vice President, October 18, 2000 to present Public Affairs, PG&E Corporation Vice President, July 1, 1997 October 17, 2000 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, April 6, 2000 to present Generation and chief Nuclear Officer Senior Vice President November 1, 1991 to April 5, 2000 and General Manager, Nuclear Power Generation Business Unit
58 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 89 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 2000 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of April 9, 2001, there were 132,612 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York, Pacific, and Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation's common stock is hereby incorporated by reference from "Management's Discussion and Analysis-- Dividends" on page 20 of the 2000 Annual Report to Shareholders. Neither Pacific Gas and Electric Company nor PG&E Corporation made any sales of unregistered equity securities during 2000, the period covered by this report. 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 5 under the heading "Selected Financial Data" in the 2000 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. Pacific Gas and Electric Company's ratio of earnings to fixed charges for the year ended December 31, 2000 was a negative 7.70. Pacific Gas and Electric Company's ratio of earnings to combined fixed charges and preferred stock dividends for the year ended December 31, 2000 was a negative 7.29. The negative ratios of earnings to fixed charges and earnings to combined fixed charges and preferred stock dividends indicates a deficiency in earnings of $5,637 million and $5,673 million respectively. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding. ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated results of operations and financial condition is set forth on pages 6 through 31 under the heading "Management's Discussion and Analysis" in the 2000 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. Information responding to Item 7A appears in the 2000 Annual Report to Shareholders on pages 28-31 under the heading "Management's Discussion and Analysis--Quantitative and Qualitative Disclosures about Market Risk," and on pages 46-47, 60-62 and 68-71 under Notes 1, 4, 8 and 9 of the "Notes to the Consolidated Financial Statements" of the 2000 Annual Report to Shareholders, which information 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 appears on pages 32 through 92 of the 2000 Annual Report to Shareholders under the following headings for PG&E Corporation: "Statement of Consolidated Operations," "Consolidated Balance Sheets," "Statement of Consolidated Cash Flows," and "Statement of Consolidated Common Stock Equity;" under the following headings for Pacific Gas and Electric Company: "Statement of Consolidated Operations," "Consolidated Balance Sheets," "Statement of Consolidated Cash Flows," and 59 "Statement of Consolidated Stockholders' Equity;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes to the Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," "Independent Auditors' Report," and "Responsibility for the Consolidated Financial Statements," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. Not applicable. 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 56 through 58 in Part I of this report. Other information responding to Item 10 is included on pages 3 through 5 under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and page 40 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 2001 Annual Meetings of Shareholders, which information is hereby incorporated by reference. ITEM 11. Executive Compensation. Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 8 and 9 under the heading "Compensation of Directors" and on pages 31 through 37 under the headings "Summary Compensation Table," "Option/SAR Grants in 2000," "Aggregated Option/SAR Exercises in 2000 and Year-End Option/SAR Values," "Long-Term Incentive Plan--Awards in 2000," "Retirement Benefits," "Employment Contracts/Arrangements," and "Termination of Employment and Change In Control Provisions" in the Joint Proxy Statement relating to the 2001 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 40 under the heading "Principal Shareholders" in the Joint Proxy Statement relating to the 2001 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 Joint Proxy Statement relating to the 2001 Annual Meetings of Shareholders, which information is hereby incorporated by reference. 60 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 Report to Shareholders, which have been incorporated by reference in this report: Statements of Consolidated Operations for the Years Ended December 31, 2000, 1999, and 1998, for each of PG&E Corporation and Pacific Gas and Electric Company. Statements of Consolidated Cash Flows for the Years Ended December 31, 2000, 1999, and 1998, for each of PG&E Corporation and Pacific Gas and Electric Company. Consolidated Balance Sheets at December 31, 2000 and 1999 for each of PG&E Corporation and Pacific Gas and Electric Company. Statement of Consolidated Common Stock Equity for the Years Ended December 31, 2000, 1999, and 1998, for PG&E Corporation. Statement of Consolidated Stockholders' Equity for the Years Ended December 31, 2000, 1999, and 1998, for Pacific Gas and Electric Company. Notes to Consolidated Financial Statements. Quarterly Consolidated Financial Data (Unaudited). Independent Auditors' Report (Deloitte & Touche LLP). 2. Independent Auditors' Report (Deloitte & Touche LLP) included at page 69 of this Form 10-K. 3. Report of Independent Public Accountants (Arthur Andersen LLP) included at page 70 of this Form 10-K. 4. Report of Independent Public Accountants (Arthur Andersen LLP) included at page 71 of this Form 10-K. 5. Financial statement schedules: I--Condensed Financial Information of Parent for the Years Ended December 31, 2000 and 1999. II--Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2000, 1999 and 1998. 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. 6. Exhibits required to be filed by Item 601 of Regulation S-K: 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1) 3.2 Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 3.3 By-Laws of PG&E Corporation amended as of February 21, 2001 3.4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1)
61 3.5 By-Laws of Pacific Gas and Electric Company amended as of February 21, 2001 4.1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2- 1324, Exhibits B-1, B-2, 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) In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of PG&E Corporation or Pacific Gas and Electric Company agrees to furnish to the Commission any instruments respecting long-term debt not required to be filed by application of such item 4.2 Form of Rights Agreement dated as of December 22, 2000 between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C 10. The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit No. 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00- 02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 10.1 Stock Purchase Agreement By and Between PG&E National Energy Group, Inc. and El Paso Field Services Company, dated as of January 27, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1999 (File No. 1-12609), Exhibit No. 10.1) 10.2 Credit Agreement between PG&E Corporation, General Electric Capital Corporation and Lehman Commercial Paper, Inc. dated March 1, 2001 *10.3 PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.2) *10.4 Description of Compensation Arrangement between PG&E Corporation and Thomas G. Boren (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2) *10.5 Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1- 12609), Exhibit 10.3) *10.6 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated November 4, 1998
62 *10.7 Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E. Maddox dated April 25, 1997 *10.8 Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10) *10.9 Description of Relocation Arrangement Between PG&E Corporation and Lyn E. Maddox *10.10 PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000 *10.10.1 Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 *10.10.2 Letter regarding retention award to Gordon R. Smith dated January 22, 2001 *10.10.3 Letter regarding retention award to Peter A. Darbee dated January 22, 2001 *10.10.4 Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 *10.10.5 Letter regarding retention award to G. Brent Stanley dated January 22, 2001 *10.10.6 Letter regarding retention award to Daniel D. Richard dated January 22, 2001 *10.10.7 Letter regarding retention award to James K Randolph dated February 27, 2001 *10.10.8 Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 *10.10.9 Letter regarding retention award to Kent Harvey dated February 27, 2001 *10.10.10 Letter regarding retention award to Roger J. Peters dated February 27, 2001 *10.10.11 Letter regarding retention award to Thomas G. Boren dated February 27, 2001 *10.10.12 Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 *10.10.13 Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 *10.10.14 Letter regarding retention award to Thomas B. King dated February 27, 2001 *10.11 Agreement and Release between PG&E Corporation and Thomas W. High dated December 8, 2000 *10.12 PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2) *10.13 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1999 (File No. 1- 12609), Exhibit 10.7) *10.14 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2001 *10.15 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, effective January 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1998 (File No. 1-12609), Exhibit 10.7) *10.16 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
63 *10.17 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1- 2348), Exhibit 10.16) *10.18 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to incorporated by reference to PG&E Corporation Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit No. 10.13) *10.19 PG&E Corporation Long-Term Incentive Program, as amended February 16, 2000, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan (incorporated by reference to incorporated by reference to PG&E Corporation Form 10-K for the year ended December 31, 1999, (File No. 1-12609), Exhibit No. 10.12) *10.20 PG&E Corporation Executive Stock Ownership Program, amended as of September 19, 2000 *10.21 PG&E Corporation Officer Severance Policy, amended as of July 21, 1999 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1- 12609), Exhibit 10.1) *10.22 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) *10.23 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2) 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. 2000 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company--portions of the Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis," "Independent Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Statement of Consolidated Operations," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity," financial statements of Pacific Gas and Electric Company entitled "Statement of Consolidated Operations," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Stockholders' Equity," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data (Unaudited)" are included only (Except for those portions that are expressly incorporated herein by reference, such Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein.) 21. Subsidiaries of the Registrant 23.1 Independent Auditors' Consent (Deloitte & Touche LLP) 23.2 Consent of Arthur Andersen LLP
64 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
- -------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder. (b) Reports on Form 8-K Reports on Form 8-K(1) during the quarter ended December 31, 2000 and through the date hereof: 1. October 25, 2000 Item 5. Other Events-- B. Third Quarter 2000 Consolidated Earnings C. Pacific Gas and Electric Company's Wholesale Power Purchase Costs D. Transition Cost Recovery E. Earnings Outlook 2. November 22, 2000 Item 5. Other Events-- A. Valuation and Disposition of Pacific Gas and Electric Company's Hydroelectric Generating Assets B. Recovery of Wholesale Power Purchase Costs C. Pacific Gas and Electric Company's Rate Stabilization Plan D. Federal Energy Regulatory Commission Order E. Pacific Gas and Electric Company's Federal Complaint 3. December 8, 2000 Item 5. Other Events-- A. Valuation and Disposition of Pacific Gas and Electric Company's Hydroelectric Generating Assets B. Pacific Gas and Electric Company's Rate Stabilization Plan C. CPUC's Post-transition Period Ratemaking Decision 4. December 18, 2000 Item 5. Other Events-- A. Recent Regulatory Actions Addressing the California Energy Market B. Pacific Gas and Electric Company's Wholesale Power Purchase Costs C. Liquidity and Financial Impacts 65 5. December 22, 2000 Item 5. Other Events-- A. California Energy Crisis B. PG&E Corporation Shareholder Rights Plan 6. December 29, 2000 Item 5. Other Events--California Energy Crisis 7. January 4, 2001 Item 5. Other Events--California Energy Crisis 8. January 5, 2001 Item 5. Other Events-- California Public Utilities Commission Decision Issued 9. January 10, 2001 Item 5. Other Events-- A. Current Financial Condition B. Impending Natural Gas Shortage C. ISO's Requested Tariff Amendment to Creditworthiness Standards 10. January 10, 2001 Item 5. Other Events--Suspension of PG&E Corporation and Pacific Gas and Electric Company Dividends 11. January 17, 2001 Item 5. Other Events-- A. Ratings Downgrades B. Liquidity Impacts and Financial Condition 12. February 1, 2001 Item 5. Other Events-- A. Wholesale Power Payments B. Liquidity Impacts and Financial Condition C. Federal Lawsuit D. Rate Stabilization Plan Proceeding E. Consulting Report F. CPUC Emergency Action 13. February 14, 2001 Item 5. Other Events-- A. Assembly Bill 1X B. Liquidity Impacts and Financial Condition C. Federal Lawsuit 14. February 28, 2001 Item 5. Other Events-- A. Recent Regulatory Action B. Liquidity C. Wilson vs. PG&E Corporation and Pacific Gas and Electric Company 66 15. March 2, 2001--Filed by PG&E Corporation only Item 5. Other Events--PG&E Corporation debt restructure 16. March 9, 2001 Item 5. Other Events A. Recent Regulatory Action B. 2001 Cost of Capital Proceeding 17. March 16, 2001 Item 5. Other Events--Liquidity and Financial Condition 18. March 23, 2001 Item 5. Other Events A. Recent Legislative and Regulatory Actions B. Accounting Treatment C. Bank Forbearance Agreement 19. March 30, 2001 Item 5. Other Events A. Recent Regulatory Actions B. Accounting Treatment C. Liquidity and Financial Condition 20. April 6, 2001 (as amended)--Filed by PG&E Corporation only Item 5. Other Events--Pacific Gas and Electric Company Bankruptcy 21. April 6, 2001 (as amended)--Filed by Pacific Gas and Electric Company only Item 3. Other Events--Bankruptcy or Receivership. - -------- (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). 67 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 16th day of April, 2001. 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, JR. Chairman of the Board, April 16, 2001 Chief Executive Officer, and President (PG&E Corporation) *GORDON R. SMITH President and Chief April 16, 2001 Executive Officer (Pacific Gas and Electric Company) B. Principal Financial Officers *PETER A. DARBEE Senior Vice President, April 16, 2001 Chief Financial Officer, and Treasurer (PG&E Corporation) *KENT M. HARVEY Senior Vice President, April 16, 2001 Chief Financial Officer, and Treasurer (Pacific Gas and Electric Company) C. Principal Accounting Officers *CHRISTOPHER P. JOHNS Vice President and April 16, 2001 Controller (PG&E Corporation) *DINYAR B. MISTRY Vice President-Controller April 16, 2001 (Pacific Gas and Electric Company) D. Directors *DAVID ANDREWS *DAVID A. COULTER *C. LEE COX *WILLIAM S. DAVILA *ROBERT D. GLYNN, JR. Directors of PG&E *DAVID M. LAWRENCE, M.D. Corporation and *MARY S. METZ Pacific Gas and Electric April 16, 2001 *CARL E. REICHARDT Company, *GORDON R. SMITH except as noted (Director of Pacific Gas and Electric Company only) *BARRY LAWSON WILLIAMS /s/ Gary P. Encinas *By __________________________________ (Gary P. Encinas, Attorney-in-Fact)
68 INDEPENDENT AUDITORS' REPORT To the Shareholders and the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company: We have audited the consolidated financial statements of PG&E Corporation and subsidiaries and Pacific Gas and Electric Company and subsidiaries as of and for the years ended December 31, 2000 and 1999 and have issued our report thereon dated April 6, 2001, which report includes an explanatory paragraph concerning the ability of Pacific Gas and Electric Company to continue as a going concern; such consolidated financial statements are included in your 2000 Annual Report to shareholders and are incorporated herein by reference. Our audits also included the financial statement schedules of PG&E Corporation and Pacific Gas and Electric Company, listed in Item 14(a)5. These financial statement schedules are the responsibility of the management of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP San Francisco, California April 6, 2001 69 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and 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 for the year ended December 31, 1998 included in the PG&E Corporation and Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 8, 1999. Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The Condensed Financial Information of Parent for the Year Ended December 31, 1998 and the Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Year Ended December 31, 1998 are the responsibility of the management of PG&E Corporation and of Pacific Gas and Electric Company. These schedules are 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. ARTHUR ANDERSEN LLP San Francisco, California February 8, 1999 70 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 statements of consolidated operations, cash flows, and common stock equity of PG&E Corporation (a California corporation) and subsidiaries and the statements of consolidated operations, cash flows, and stockholders' equity of Pacific Gas and Electric Company (a California corporation) and subsidiaries for the year ended December 31, 1998. These financial statements are the responsibility of the management of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the 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 results of operations and cash flows of PG&E Corporation and subsidiaries and Pacific Gas and Electric and subsidiaries for the year ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San Francisco, California February 8, 1999 71 SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETS
December 31, ---------------- 2000 1999 ------- ------- (in millions) Assets: Cash and cash equivalents..................................... $ 351 $ 155 Advances to affiliates........................................ 295 299 Note receivable from subsidiary............................... 308 -- Other current assets.......................................... 6 -- ------- ------- Total current assets....................................... 960 454 Equipment..................................................... 15 16 Accumulated depreciation...................................... (6) (3) ------- ------- Net equipment................................................. 9 13 Investments in subsidiaries................................... 3,439 6,931 Other investments............................................. 64 52 Deferred income taxes......................................... -- 396 Other deferred charges........................................ 1 -- ------- ------- Total Assets............................................... $ 4,473 $ 7,846 ======= ======= Liabilities and Stockholders' Equity: Current Liabilities: Short-term borrowings........................................ $ 931 $ 526 Accounts payable--related parties............................ 59 76 Accounts payable--trade...................................... 13 10 Note payable to subsidiary................................... 75 -- Accrued taxes................................................ 108 117 Dividends payable............................................ 109 110 Other........................................................ 25 112 ------- ------- Total current liabilities.................................. 1,320 951 Noncurrent Liabilities: Deferred income taxes........................................ 9 -- Other........................................................ 10 5 ------- ------- Total noncurrent liabilities............................... 19 5 Stockholders' Equity: Common stock................................................. 5,971 5,906 Common stock held by subsidiary.............................. (690) (690) Reinvested earnings.......................................... (2,147) 1,674 ------- ------- Total stockholders' equity................................. 3,134 6,890 ------- ------- Total Liabilities and Stockholders' Equity................. $ 4,473 $ 7,846 ======= =======
72 SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT--(Continued) CONDENSED STATEMENTS OF INCOME For the Years Ended December 31, 2000, 1999, and 1998
2000 1999 1998 -------- ------- ------ (in millions except per share amounts) Administrative service revenue .................... $ 111 $ 82 $ 64 Equity in earnings (losses) of subsidiaries........ (3,316) 853 736 Operating expenses................................. (111) (86) (63) Loss on assets held for sale....................... -- (1,275) -- Interest expense................................... (27) (30) (52) Other income....................................... 22 16 5 -------- ------- ------ Income (Loss) Before Income Taxes.................. (3,321) (440) 690 Less: Income Taxes................................. (4) (447) (83) -------- ------- ------ Income (Loss) from continuing operations........... (3,317) 7 773 Discontinued operations............................ (40) (98) (52) Cumulative effect of a change in an accounting principle......................................... -- 12 -- -------- ------- ------ Net income (loss) before intercompany elimination.. (3,357) (79) 721 Eliminations of intercompany (profit) loss......... (7) 6 (2) -------- ------- ------ Net income (loss).................................. $ (3,364) $ (73) $ 719 ======== ======= ====== Weighted Average Common Shares Outstanding, Basic and Diluted....................................... 362 368 382 Earnings (Loss) Per Common Share, Basic and Diluted........................................... $ (9.29) $ (0.20) $ 1.88 ======== ======= ====== CONDENSED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2000, 1999, and 1998 2000 1999 1998 -------- ------- ------ (in millions) Cash Flows From Operating Activities: Net income (loss).................................. $ (3,364) $ (73) $ 719 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Equity in earnings of subsidiaries................ 3,316 (853) (736) Deferred taxes.................................... 20 (415) 19 Loss on assets held for sale...................... -- 1,275 -- Distributions from consolidated subsidiaries...... 475 527 561 Other-net......................................... 232 77 (688) -------- ------- ------ Net cash provided by operating activities.......... $ 679 $ 538 $ (125) Cash Flows From Investing Activities: Capital expenditures.............................. 1 (8) (8) Investment in subsidiaries........................ (555) (722) (575) Loans to subsidiaries............................. (308) -- -- Return of capital by Utility (share repurchases).. 275 926 1,600 Other-net......................................... (9) (12) -- -------- ------- ------ Net cash provided (used) by investing activities... $ (596) $ 184 $1,017 Cash Flows From Financing Activities: Common stock issued............................... 65 54 63 Common stock repurchased.......................... (2) (3) (1,158) Loans from subsidiary............................. 75 -- -- Short-term debt issued (redeemed)-net............. 405 (157) 683 Dividends paid.................................... (436) (465) (470) Other-net......................................... 6 (5) (2) -------- ------- ------ Net cash provided (used) by financing activities... $ 113 $ (576) $ (884) Net Change in Cash & Cash Equivalents.............. 196 146 8 Cash & Cash Equivalents at January 1............... 155 9 1 -------- ------- ------ Cash & Cash Equivalents at December 31............. $ 351 $ 155 $ 9 ======== ======= ======
73 PG&E CORPORATION SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2000, 1999, and 1998
Column A Column B Column C Column D Column E Additions ------------------- Balance at Charged to Charged Balance at Beginning Costs and to Other End of Description of Period Expenses Accounts Deductions Period ----------- ---------- ---------- -------- ---------- ---------- (in thousands) Valuation and qualifying accounts deducted from assets: 2000: Allowance for uncollectible accounts (2)................... $65,128 $ 47,980 $ 1,484 $44,092(1) $ 70,500 ======= ========== ======= ======= ========== Provision for loss on generation-related regulatory assets and undercollected purchased power costs (3)................... $ -- $6,939,000 $ -- $ -- $6,939,000 ======= ========== ======= ======= ========== 1999: Allowance for uncollectible accounts (2)................... $58,577 $ 25,243 $ (183) $18,509(1) $ 65,128 ======= ========== ======= ======= ========== 1998: Allowance for uncollectible accounts (2)................... $72,912 $ 10,978 $(2,893) $22,420(1) $ 58,577 ======= ========== ======= ======= ==========
- -------- (1) Deductions consist principally of write-offs, net of collections of receivables previously written off. (2) Allowance for uncollectible accounts are deducted from "Accounts receivable Customers, net" and "Accounts receivable Energy Marketing." (3) Provision was deducted from "Regulatory Assets." 74 PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2000, 1999, and 1998
Column A Column B Column C Column D Column E Additions ------------------- Balance at Charged to Charged Balance at Beginning Costs and to Other End of Description of Period Expenses Accounts Deductions Period ----------- ---------- ---------- -------- ---------- ---------- (in thousands) Valuation and qualifying accounts deducted from assets: 2000: Allowance for uncollectible accounts (2)................... $46,421 $ 19,008 $1,484 $15,344(1) $ 51,569 ======= ========== ====== ======= ========== Provision for loss on generation-related regulatory assets and undercollected purchased power costs (3)................... $ -- $6,939,000 $ -- $ -- $6,939,000 ======= ========== ====== ======= ========== 1999: Allowance for uncollectible accounts (2)................... $47,347 $ 17,011 $ 44 $17,981(1) $ 46,421 ======= ========== ====== ======= ========== 1998: Allowance for uncollectible accounts (2)................... $59,608 $ 10,007 $ 152 $22,420(1) $ 47,347 ======= ========== ====== ======= ==========
- -------- (1) Deductions consist principally of write-offs, net of collections of receivables previously written off. (2) Allowance for uncollectible accounts are deducted from "Accounts receivable Customers, net." (3) Provision was deducted from "Regulatory Assets." 75 EXHIBIT INDEX
Exhibit No. Description of Exhibit ----------- ---------------------- 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-12609), Exhibit 3.1) 3.2 Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 3.3 By-Laws of PG&E Corporation amended as of February 21, 2001 3.4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1) 3.5 By-Laws of Pacific Gas and Electric Company amended as of February 21, 2001 4.1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2- 1324, Exhibits B-1, B-2, 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) In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of PG&E Corporation or Pacific Gas and Electric Company agrees to furnish to the Commission any instruments respecting long-term debt not required to be filed by application of such item 4.2 Form of Rights Agreement dated as of December 22, 2000 between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C 10. The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit No. 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00- 02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 10.1 Stock Purchase Agreement By and Between PG&E National Energy Group, Inc. and El Paso Field Services Company, dated as of January 27, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1999 (File No. 1-12609), Exhibit No. 10.1) 10.2 Credit Agreement between PG&E Corporation, General Electric Capital Corporation and Lehman Commercial Paper, Inc. dated March 1, 2001 *10.3 PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.2)
Exhibit No. Description of Exhibit ----------- ---------------------- *10.4 Description of Compensation Arrangement between PG&E Corporation and Thomas G. Boren (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2) *10.5 Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1- 12609), Exhibit 10.3) *10.6 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated November 4, 1998 *10.7 Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E. Maddox dated April 25, 1997 *10.8 Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10) *10.9 Description of Relocation Arrangement Between PG&E Corporation and Lyn E. Maddox *10.10 PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000 *10.10.1 Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 *10.10.2 Letter regarding retention award to Gordon R. Smith dated January 22, 2001 *10.10.3 Letter regarding retention award to Peter A. Darbee dated January 22, 2001 *10.10.4 Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 *10.10.5 Letter regarding retention award to G. Brent Stanley dated January 22, 2001 *10.10.6 Letter regarding retention award to Daniel D. Richard dated January 22, 2001 *10.10.7 Letter regarding retention award to James K Randolph dated February 27, 2001 *10.10.8 Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 *10.10.9 Letter regarding retention award to Kent Harvey dated February 27, 2001 *10.10.10 Letter regarding retention award to Roger J. Peters dated February 27, 2001 *10.10.11 Letter regarding retention award to Thomas G. Boren dated February 27, 2001 *10.10.12 Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 *10.10.13 Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 *10.10.14 Letter regarding retention award to Thomas B. King dated February 27, 2001 *10.11 Agreement and Release between PG&E Corporation and Thomas W. High dated December 8, 2000 *10.12 PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2) *10.13 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1999 (File No. 1-12609), Exhibit 10.7) *10.14 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2001 *10.15 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, effective January 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1998 (File No. 1-12609), Exhibit 10.7)
Exhibit No. Description of Exhibit ----------- ---------------------- *10.16 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16) *10.17 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16) *10.18 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to incorporated by reference to PG&E Corporation Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit No. 10.13) *10.19 PG&E Corporation Long-Term Incentive Program, as amended February 16, 2000, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan (incorporated by reference to incorporated by reference to PG&E Corporation Form 10-K for the year ended December 31, 1999 (File No. 1-12609), Exhibit No. 10.12) *10.20 PG&E Corporation Executive Stock Ownership Program, amended as of September 19, 2000 *10.21 PG&E Corporation Officer Severance Policy, amended as of July 21, 1999 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1) *10.22 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) *10.23 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2) 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. 2000 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company--portions of the Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis," "Independent Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity," financial statements of Pacific Gas and Electric Company entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Stockholders' Equity," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data (Unaudited)" are included only. (Except for those portions that are expressly incorporated herein by reference, such Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein.) 21. Subsidiaries of the Registrant 23.1 Independent Auditors' Consent (Deloitte & Touche LLP) 23.2 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
EX-3.2 2 dex32.txt CERTIFICATE OF DETERMINATION FOR PG&E EXHIBIT 3.2 CERTIFICATE OF DETERMINATION OF PREFERENCES -------------------------------- Pursuant to Section 401 of the California General Corporation Law -------------------------------- ROBERT D. GLYNN, JR. and LESLIE H. EVERETT certify that: 1. They are the Chairman of the Board, Chief Executive Officer, and President, and the Vice President and Corporate Secretary, respectively, of PG&E Corporation, a California corporation. 2. Pursuant to authority conferred upon the Board of Directors of the Corporation by its Restated Articles of Incorporation (the "Articles"), and, -------- pursuant to the provisions of Section 401 of the California General Corporation Law, said Board of Directors, at a duly called meeting held on December 20, 2000, at which a quorum was present and acted throughout, adopted the following resolutions, which resolutions remain in full force and effect on the date hereof creating a series of 5,000,000 shares of Preferred Stock having a par value of $100 per share, designated as Series A Preferred Stock (the "Series A -------- Preferred Stock") out of the class of 85,000,000 shares of preferred stock (the - --------------- "Preferred Stock"): --------------- RESOLVED, that pursuant to the authority vested in the Board of Directors in accordance with the provisions of the Articles, the Board of Directors does hereby create, authorize and provide for the issuance of the Series A Preferred Stock having the voting powers, designation, relative, participating, optional and other special rights, preferences and qualifications, limitations and restrictions thereof that are set forth as follows: Section 1. Designation and Amount. The shares of such series shall ---------------------- be designated as "Series A Preferred Stock" and the number of shares constituting such series shall be 5,000,000. Section 2. Dividends and Distributions. (A) Subject to the prior --------------------------- and superior rights of the holders of any shares of any other series of Preferred Stock or any other shares of preferred stock of the Corporation ranking prior and superior to the shares of Series A Preferred Stock with respect to dividends, each holder of one one-hundredth (1/100) of a share (a "Unit") of Series A Preferred Stock shall be entitled to receive, when, as and ---- if declared by the Board of Directors out of funds legally available for that purpose, (i) quarterly dividends payable in cash on the last day of March, June, September and December in each year (each such date being a "Quarterly Dividend ------------------ Payment Date"), commencing on the first Quarterly Dividend Payment Date after - ------------ the first issuance of such Unit of Series A Preferred Stock, in an amount per Unit (rounded to the nearest cent) equal to the greater of (a) $.01 or (b) subject to the provision for adjustment hereinafter set forth, the aggregate per share amount of all cash dividends declared on shares of the Common Stock since the immediately preceding Quarterly Dividend Payment Date, or, with respect to the first Quarterly Dividend Payment Date, since the first issuance of a Unit of Series A Preferred Stock, and (ii) subject to the provision for adjustment hereinafter set forth, quarterly distributions (payable in kind) on each Quarterly Dividend Payment Date in an amount per Unit equal to the aggregate per share amount of all non-cash dividends or other distributions (other than a dividend payable in shares of Common Stock or a subdivision of the outstanding shares of Common Stock, by reclassification or otherwise) declared on shares of Common Stock since the immediately preceding Quarterly Dividend Payment Date, or with respect to the first Quarterly Dividend Payment Date, since the first issuance of a Unit of Series A Preferred Stock. In the event that the Corporation shall at any time after December 20, 2000 (the "Rights Declaration ------------------ Date") (i) declare any dividend on outstanding shares of Common Stock payable in - ---- shares of Common Stock, (ii) subdivide outstanding shares of Common Stock or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case the amount to which the holder of a Unit of Series A Preferred Stock was entitled immediately prior to such event pursuant to the preceding sentence shall be adjusted by multiplying such amount by a fraction the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. (B) The Corporation shall declare a dividend or distribution on Units of Series A Preferred Stock as provided in paragraph (A) above immediately after it declares a dividend or distribution on the shares of Common Stock (other than a dividend payable in shares of Common Stock); provided, however, that, in the -------- ------- event no dividend or distribution shall have been declared on the Common Stock during the period between any Quarterly Dividend Payment Date and the next subsequent Quarterly Dividend Payment Date, a dividend of $.01 per Unit on the Series A Preferred Stock shall nevertheless be payable on such subsequent Quarterly Dividend Payment Date. (C) Dividends shall begin to accrue and shall be cumulative on each outstanding Unit of Series A Preferred Stock from the Quarterly Dividend Payment Date next preceding the date of issuance of such Unit of Series A Preferred Stock, unless the date of issuance of such Unit is prior to the record date for the first Quarterly Dividend Payment Date, in which case, dividends on such Unit shall begin to accrue from the date of issuance of such Unit, or unless the date of issuance is a Quarterly Dividend Payment Date or is a date after the record date for the determination of holders of Units of Series A Preferred Stock entitled to receive a quarterly dividend and before such Quarterly Dividend Payment Date, in either of which events such dividends shall begin to accrue and be cumulative from such Quarterly Dividend Payment Date. Accrued but unpaid dividends shall not bear interest. Dividends paid on Units of Series A Preferred Stock in an amount less than the aggregate amount of all such dividends at the time accrued and payable on such Units shall be allocated pro rata on a Unit-by- Unit basis among all Units of Series A Preferred Stock at the time outstanding. The Board of Directors may fix a record date for the determination of holders of Units of Series A Preferred Stock entitled to receive payment of a dividend or distribution declared thereon, which record date shall be no more than 30 days prior to the date fixed for the payment thereof. Section 3. Voting Rights. The holders of Units of Series A Preferred ------------- Stock shall have the following voting rights: (A) Subject to the provision for adjustment hereinafter set forth, each Unit of Series A Preferred Stock shall entitle the holder thereof to one vote on all ma tters submitted for a vote of the shareholders of the Corporation. In the event the Corporation shall at any time after the Rights Declaration Date (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock or (iii) combine the outstanding shares of Common Stock into a smaller number of shares, then in each such case the number of votes per Unit to which holders of Units of Series A Preferred Stock were entitled immediately prior to such event shall be adjusted by multiplying such number by a fraction the numerator of which shall be the number of shares of Common Stock outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. (B) Except as otherwise provided herein or by law, the holders of Units of Series A Preferred Stock and the holders of shares of Common Stock shall vote together as one class on all matters submitted to a vote of shareholders of the Corporation. (C) (i) If, at any time, dividends on any Units of Series A Preferred Stock shall be in arrears in an amount equal to six quarterly dividends thereon, then during the period (a "default period") from the occurrence of such event -------------- until such time as all accrued and unpaid dividends for all previous quarterly dividend periods and for the current quarterly dividend period on all Units of Series A Preferred Stock then outstanding shall have been declared and paid or set apart for payment, all holders of Units of Series A Preferred Stock, voting separately as a class, shall have the right to elect two Directors. (ii) During any default period, such voting rights of the holders of Units of Series A Preferred Stock may be exercised initially at a special meeting called pursuant to subparagraph (iii) of this Section 3(C) or at any annual meeting of shareholders, and thereafter at annual meetings of shareholders, provided that such voting rights may not be exercised at any meeting unless one-third of the outstanding Units of Preferred Stock shall be present at such meeting in person or by proxy. The absence of a quorum of the holders of Common Stock shall not affect the exercise by the holders of Units of Series A Preferred Stock of such rights. At any meeting at which the holders of Units of Series A Preferred Stock shall exercise such voting rights initially during an existing default period, they shall have the right, voting separately as a class, to elect Directors to fill up to two vacancies in the Board of Directors, if any such vacancies may then exist, or, if such right is exercised at an annual meeting, to elect two Directors. After the holders of Units of Series A Preferred Stock shall have exercised their right to elect Directors during any default period, the number of Directors shall not be increased or decreased except as approved by a vote of the holders of Units of Series A Preferred Stock as herein provided or pursuant to the rights of any equity securities ranking senior to the Series A Preferred Stock. (iii) Unless the holders of Series A Preferred Stock shall, during an existing default period, have previously exercised their right to elect Directors, the Board of Directors may order, or any shareholder or shareholders owning in the aggregate not less than 10% of the total number of the Units of Series A Preferred Stock outstanding may request, the calling of a special meeting of the holders of Units of Series A Preferred Stock, which meeting shall thereupon be called by the Secretary of the Corporation. Notice of such meeting and of any annual meeting at which holders of Units of Series A Preferred Stock are entitled to vote pursuant to this paragraph (C)(iii) shall be given to each holder of record of Units of Series A Preferred Stock by mailing a copy of such notice to him at his last address as the same appears on the books of the Corporation. Such meeting shall be called for a time not earlier than 20 days and not later then 60 days after such order or request, or, in default of the calling of such meeting within 60 days after such order or request, such meeting may be called on similar notice by any shareholder or shareholders owning in the aggregate not less than 10% of the total number of outstanding Units of Series A Preferred Stock. Notwithstanding the provisions of this paragraph (C)(iii), no such special meeting shall be called during the 60 days immediately preceding the date fixed for the next annual meeting of the shareholders. (iv) During any default period, the holders of shares of Common Stock and Units of Series A Preferred Stock, and other classes or series of stock of the Corporation, if applicable, shall continue to be entitled to elect all the Directors until holders of the Units of Series A Preferred Stock shall have exercised their right to elect, voting as a separate class, two Directors, after the exercise of which right (x) the Directors so elected by the holders of Units of Series A Preferred Stock shall continue in office until their successors shall have been elected by such holders or until the expiration of the default period, and (y) any vacancy in the Board of Directors may (except as provided in paragraph (C)(ii) of this Section 3) be filled by vote of a majority of the remaining Directors theretofore elected by the holders of the class of capital stock which elected the Director whose office shall have become vacant. References in this paragraph (C) to Directors elected by the holders of a particular class of capital stock shall include Directors elected by such Directors to fill vacancies as provided in clause (y) of the foregoing sentence. (v) Immediately upon the expiration of a default period, (x) the right of the holders of Units of Series A Preferred Stock as a separate class to elect Directors shall cease, (y) the term of any Directors elected by the holders of Units of Series A Preferred Stock as a separate class shall terminate, and (z) the number of Directors shall be such number as may be provided for in the Articles or Bylaws of the Company (the "Bylaws"). Any ------ vacancies in the Board of Directors effected by the provisions of clauses (y) and (z) in the preceding sentence may be filled by a majority of the remaining Directors. (vi) The provisions of this paragraph (C) shall govern the election of Directors by holders of Units of Preferred Stock during any default period notwithstanding any provisions of the Articles or the Bylaws to the contrary. (D) Except as set forth herein, holders of Units of Series A Preferred Stock shall have no special voting rights and their consents shall not be required (except to the extent they are entitled to vote with holders of shares of Common Stock as set forth herein) for taking any corporate action. Section 4. Certain Restrictions. (A) Whenever quarterly dividends -------------------- or other dividends or distributions payable on Units of Series A Preferred Stock as provided in Section 2 are in arrears, thereafter and until all accrued and unpaid dividends and distributions, whether or not declared, on outstanding Units of Series A Preferred Stock shall have been paid in full, the Corporation shall not: (i) declare or pay dividends on, make any other distributions on, or redeem or purchase or otherwise acquire for consideration any shares of junior stock; (ii) declare or pay dividends on or make any other distributions on any shares of parity stock, except dividends paid ratably on Units of Series A Preferred Stock and shares of all such parity stock on which dividends are payable or in arrears in proportion to the total amounts to which the holders of such Units and all such shares are then entitled; (iii) redeem or purchase or otherwise acquire for consideration shares of any parity stock, provided, however, that the Corporation may at -------- ------- any time redeem, purchase or otherwise acquire shares of any such parity stock in exchange for shares of any junior stock; (iv) purchase or otherwise acquire for consideration any Units of Series A Preferred Stock, except in accordance with a purchase offer made in writing or by publication (as determined by the Board of Directors) to all holders of such Units. (B) The Corporation shall not permit any subsidiary of the Corporation to purchase or otherwise acquire for consideration any shares of stock of the Corporation unless the Corporation could, under paragraph (A) of this Section 4, purchase or otherwise acquire such shares at such time and in such manner. Section 5. Reacquired Shares. Any Units of Series A Preferred Stock ----------------- purchased or otherwise acquired by the Corporation in any manner whatsoever shall be retired and cancelled promptly after the acquisition thereof. All such Units shall, upon their cancellation, become authorized but unissued Units of Preferred Stock and may be reissued as part of a new series of Preferred Stock to be created by resolution or resolutions of the Board of Directors, subject to the conditions and restrictions on issuance set forth herein. Section 6. Liquidation, Dissolution or Winding Up. (A) Upon any -------------------------------------- voluntary or involuntary liquidation, dissolution or winding up of the Corporation, no distribution shall be made (i) to the holders of shares of junior stock unless the holders of Units of Series A Preferred Stock shall have received, subject to adjustment as hereinafter provided in paragraph (B), the greater of either (a) $1.00 per Unit plus an amount equal to accrued and unpaid dividends and distributions thereon, whether or not earned or declared, up until the date of such payment, or (b) the amount equal to the aggregate per share amount to be distributed to holders of shares of Common Stock, or (ii) to the holders of shares of parity stock, unless simultaneously therewith distributions are made ratably on Units of Series A Preferred Stock and all other shares of such parity stock in proportion to the total amounts to which the holders of Units of Series A Preferred Stock are entitled under clause (i)(a) of this sentence and to which the holders of shares of such parity stock are entitled, in each case upon such liquidation, dissolution or winding up. (B) In the event the Corporation shall, at any time after the Rights Declaration Date, (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case the aggregate amount to which holders of Units of Series A Preferred Stock were entitled immediately prior to such event pursuant to clause (i)(b) of paragraph (A) of this Section 6 shall be adjusted by multiplying such amount by a fraction the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. Section 7. Consolidation, Merger, etc. In case the Corporation shall -------------------------- enter into any consolidation, merger, combination or other transaction in which the shares of common stock are exchanged for or converted into other stock or securities, cash and/or any other property, then in any such case Units of Series A Preferred Stock shall at the same time be similarly exchanged for or converted into an amount per Unit (subject to the provision for adjustment hereinafter set forth) equal to the aggregate amount of stock, securities, cash and/or any other property (payable in kind), as the case may be, into which or for which each share of Common Stock is converted or exchanged. In the event the Corporation shall at any time after the Rights Declaration Date (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding Common Stock into a smaller number of shares, then in each such case the amount set forth in the immediately preceding sentence with respect to the exchange or conversion of Units of Series A Preferred Stock shall be adjusted by multiplying such amount by a fraction the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. Section 8. Redemption. The Units of Series A Preferred Stock shall ---------- not be redeemable. Section 9. Ranking. The Units of Series A Preferred Stock shall ------- rank junior to all other series of the Preferred Stock and to any other class of preferred stock that hereafter may be issued by the Corporation as to the payment of dividends and the distribution of assets, unless the terms of any such series or class shall provide otherwise. Section 10. Amendment. The Articles, including, without limitation, --------- this resolution, shall not hereafter be amended, either directly or indirectly, or through merger or consolidation with any other corporation or corporations in any manner that would alter or change the powers, preferences or special rights of the Series A Preferred Stock so as to affect them adversely without the affirmative vote of the holders of a majority or more of the outstanding Units of Series A Preferred Stock, voting separately as a class. Section 11. Fractional Shares. The Series A Preferred Stock may be ----------------- issued in Units or other fractions of a share, which Units or fractions shall entitle the holder, in proportion to such holder's fractional shares, to exercise voting rights, receive dividends, participate in distributions and to have the benefit of all other rights of holders of Series A Preferred Stock. Section 12. Certain Definitions. As used herein with respect to the ------------------- Series A Preferred Stock, the following terms shall have the following meanings: (A) The term "Common Stock" shall mean the class of stock designated ------------ as the common stock, no par value per share, of the Corporation at the date hereof or any other class of stock resulting from successive changes or reclassification of such common stock. (B) The term "junior stock" (i) as used in Section 4 shall mean the ------------ Common Stock and any other class or series of capital stock of the Corporation hereafter authorized or issued over which the Series A Preferred Stock has preference or priority as to the payment of dividends and (ii) as used in Section 6 shall mean the Common Stock and any other class or series of capital stock of the Corporation over which the Series A Preferred Stock has preference or priority in the distribution of assets upon any liquidation, dissolution or winding up of the Corporation. (C) The term "parity stock" (i) as used in Section 4, shall mean any ------------ class or series of stock of the Corporation hereafter authorized or issued ranking pari passu with the Series A Preferred Stock as to the payment of ---- ----- dividends and (ii) as used in Section 6, shall mean any class or series of capital stock ranking pari passu with the Series A Preferred Stock in the ---- ----- distribution of assets upon any liquidation, dissolution or winding up of the Corporation. 3. The number of shares constituting the Series A Preferred Stock is 5,000,000. 4. None of the Series A Preferred Stock has been issued. We further declare under penalty of perjury under the laws of the State of California that the matters set forth in this Certificate are true and correct of our own knowledge. Date: December 22, 2000 ROBERT D. GLYNN, JR. --------------------------------------------- Robert D. Glynn, Jr. Chairman of the Board, Chief Executive Officer, and President LESLIE H. EVERETT --------------------------------------------- Leslie H. Everett Vice President and Corporate Secretary EX-3.3 3 dex33.txt BY-LAWS OF PG&E CORPORATION EXHIBIT 3.3 Bylaws of PG&E Corporation amended as of February 21, 2001 ------------------------------- 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 or without 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. At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting. To be properly brought before an annual meeting, business must be (i) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (ii) otherwise properly brought before the annual meeting by a shareholder. For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Corporation. To be timely, the shareholder's written notice must be received at the principal executive office of the Corporation not less than forty-five days before the date corresponding to the mailing date of the notice and proxy materials for the prior year's annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder's written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder's written notice to be timely must be so received not later than the close of business on the tenth day following the date on which public disclosure of the date of the annual meeting is made or given to shareholders. To be proper, the shareholder's written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting, (b) the name and address of the shareholder as they appear on the Corporation's books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. In addition, if the shareholder's written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Corporation beneficially owned by each such person, and (d) such other information concerning each such person as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such person as a Director, and must be accompanied by a consent, signed by each such person, to serve as a Director of the Corporation if elected. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section. 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. 2 5. Shareholder Action by Written Consent. Subject to Section 603 of the California Corporations Code, any action which, under any provision of the California Corporations Code, may be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Any party seeking to solicit written consent from shareholders to take corporate action must deliver a notice to the Corporate Secretary of the Corporation which requests the Board of Directors to set a record date for determining shareholders entitled to give such consent. Such written request must set forth as to each matter the party proposes for shareholder action by written consents (a) a brief description of the matter and (b) the class and number of shares of the Corporation that are beneficially owned by the requesting party. Within ten days of receiving the request in the proper form, the Board shall set a record date for the taking of such action by written consent in accordance with California Corporations Code Section 701 and Article IV, Section 1 of these Bylaws. If the Board fails to set a record date within such ten-day period, the record date for determining shareholders entitled to give the written consent for the matters specified in the notice shall be the day on which the first written consent is given in accordance with California Corporations Code Section 701. Each written consent delivered to the Corporation must set forth (a) the action sought to be taken, (b) the name and address of the shareholder as they appear on the Corporation's books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, (d) the name and address of the proxyholder authorized by the shareholder to give such written consent, if applicable, and (d) any material interest of the shareholder or proxyholder in the action sought to be taken. Consents to corporate action shall be valid for a maximum of sixty days after the date of the earliest dated consent delivered to the Corporation. Consents may be revoked by written notice (i) to the Corporation, (ii) to the shareholder or shareholders soliciting consents or soliciting revocations in opposition to action by consent proposed by the Corporation (the "Soliciting Shareholders"), or (iii) to a proxy solicitor or other agent designated by the Corporation or the Soliciting Shareholders. Within three business days after receipt of the earliest dated consent solicited by the Soliciting Shareholders and delivered to the Corporation in the manner provided in California Corporations Code Section 603 or the determination by the Board of Directors of the Corporation that the Corporation should seek corporate action by written consent, as the case may be, the Corporate Secretary shall engage nationally recognized independent inspectors of elections for the purpose of performing a ministerial review of the validity of the consents and revocations. The cost of retaining inspectors of election shall be borne by the Corporation. 3 Consents and revocations shall be delivered to the inspectors upon receipt by the Corporation, the Soliciting Shareholders or their proxy solicitors, or other designated agents. As soon as consents and revocations are received, the inspectors shall review the consents and revocations and shall maintain a count of the number of valid and unrevoked consents. The inspectors shall keep such count confidential and shall not reveal the count to the Corporation, the Soliciting Shareholder or their representatives, or any other entity. As soon as practicable after the earlier of (i) sixty days after the date of the earliest dated consent delivered to the Corporation in the manner provided in California Corporations Code Section 603, or (ii) a written request therefor by the Corporation or the Soliciting Shareholders (whichever is soliciting consents), notice of which request shall be given to the party opposing the solicitation of consents, if any, which request shall state that the Corporation or Soliciting Shareholders, as the case may be, have a good faith belief that the requisite number of valid and unrevoked consents to authorize or take the action specified in the consents has been received in accordance with these Bylaws, the inspectors shall issue a preliminary report to the Corporation and the Soliciting Shareholders stating: (a) the number of valid consents, (b) the number of valid revocations, (c) the number of valid and unrevoked consents, (d) the number of invalid consents, (e) the number of invalid revocations, and (f) whether, based on their preliminary count, the requisite number of valid and unrevoked consents has been obtained to authorize or take the action specified in the consents. Unless the Corporation and the Soliciting Shareholders shall agree to a shorter or longer period, the Corporation and the Soliciting Shareholders shall have forty-eight hours to review the consents and revocations and to advise the inspectors and the opposing party in writing as to whether they intend to challenge the preliminary report of the inspectors. If no written notice of an intention to challenge the preliminary report is received within forty-eight hours after the inspectors' issuance of the preliminary report, the inspectors shall issue to the Corporation and the Soliciting Shareholders their final report containing the information from the inspectors' determination with respect to whether the requisite number of valid and unrevoked consents was obtained to authorize and take the action specified in the consents. If the Corporation or the Soliciting Shareholders issue written notice of an intention to challenge the inspectors' preliminary report within forty-eight hours after the issuance of that report, a challenge session shall be scheduled by the inspectors as promptly as practicable. A transcript of the challenge session shall be recorded by a certified court reporter. Following completion of the challenge session, the inspectors shall as promptly as practicable issue their final report to the Soliciting Shareholders and the Corporation, which report shall contain the information included in the preliminary report, plus all changes in the vote totals as a result of the challenge and a certification of whether the requisite number of valid and unrevoked consents was obtained to authorize or take the action specified in the consents. A copy of the final report of the inspectors shall be included in the book in which the proceedings of meetings of shareholders are recorded. Unless the consent of all shareholders entitled to vote have been solicited in writing, the Corporation shall give prompt notice to the shareholders in accordance with 4 California Corporations Code Section 603 of the results of any consent solicitation or the taking of the corporate action without a meeting and by less than unanimous written consent. Article II. DIRECTORS. 1. Number. As stated in paragraph I of Article Third of this Corporation's Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13). The exact number of directors shall be nine (9) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Committees. The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, designate and appoint one or more committees as the Board deems appropriate, each consisting of two or more directors, to serve at the pleasure of the Board; provided, however, that, as required by this Corporation's Articles of Incorporation, the members of the Executive Committee (should the Board of Directors designate an Executive Committee) must be appointed by the affirmative vote of two-thirds of the authorized number of directors. Any such committee, including the Executive Committee, shall have the authority to act in the manner and to the extent provided in the resolution of the Board of Directors designating such committee and may have all the authority of the Board of Directors, except with respect to the matters set forth in California Corporations Code Section 311. 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Corporate Secretary. Such notice shall be delivered personally or by telephone to each Director at least four 5 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 or any committee thereof shall consist of one-third of the authorized number of directors or committee members, or two, whichever is larger. 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 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 6 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. 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 7 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. 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. 8 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. 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. 9 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. 10 EX-3.5 4 dex35.txt BY-LAWS OF PACIFIC GAS & ELECTRIC COMPANY EXHIBIT 3.5 Bylaws of Pacific Gas and Electric Company amended as of February 21, 2001 ------------------------------- 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 or without 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. At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting. To be properly brought before an annual meeting, business must be (i) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (ii) otherwise properly brought before the annual meeting by a shareholder. For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Corporation. To be timely, the shareholder's written notice must be received at the principal executive office of the Corporation not less than forty-five days before the date corresponding to the mailing date of the notice and proxy materials for the prior year's annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder's written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder's written notice to be timely must be so received not later than the close of business on the tenth day following the date on which public disclosure of the date of the annual meeting is made or given to shareholders. To be proper, the shareholder's written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting, (b) the name and address of the shareholder as they appear on the Corporation's books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. In addition, if the shareholder's written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Corporation beneficially owned by each such person, and (d) such other information concerning each such person as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such person as a Director, and must be accompanied by a consent, signed by each such person, to serve as a Director of the Corporation if elected. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section. 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. 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. 2 5. No Cumulative Voting. No shareholder of the Corporation shall be entitled to cumulate his or her voting power. Article II. DIRECTORS. 1. Number. The Board of Directors of this Corporation shall consist of such number of directors, not less than nine (9) nor more than seventeen (17). The exact number of directors shall be ten (10) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Committees. The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, designate and appoint one or more committees as the Board deems appropriate, each consisting of two or more directors, to serve at the pleasure of the Board; provided, however, that, as required by this Corporation's Articles of Incorporation, the members of the Executive Committee (should the Board of Directors designate an Executive Committee) must be appointed by the affirmative vote of two-thirds of the authorized number of directors. Any such committee, including the Executive Committee, shall have the authority to act in the manner and to the extent provided in the resolution of the Board of Directors designating such committee and may have all the authority of the Board of Directors, except with respect to the matters set forth in California Corporations Code Section 311. 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first- class mail or telegram, postage prepaid, at least two days in advance of such meeting. 3 6. Quorum. A quorum for the transaction of business at any meeting of the Board of Directors or any committee thereof shall consist of one-third of the authorized number of directors or committee members, or two, whichever is larger. 7. Action by Consent. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. Meetings by Conference Telephone. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. Article III. OFFICERS. 1. Officers. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, one or more Vice Presidents, a Secretary and one or more Assistant Secretaries, a Treasurer and one or more Assistant Treasurers, a General Counsel, a General Attorney (whenever the Board of Directors in its discretion fills this office), and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. Chairman of the Board. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the President, shall exercise his duties and responsibilities. 3. Vice Chairman of the Board. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4 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. 5 The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 9. General Counsel. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 10. Controller. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. He shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors. 6 Article IV. MISCELLANEOUS. 1. Record Date. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. Transfers of Stock. Upon surrender to the Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. Lost Certificates. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. Article V. AMENDMENTS. 1. Amendment by Shareholders. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. Amendment by Directors. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. 7 EX-4.2 5 dex42.txt FORM OF RIGHTS AGREEMENT EXHIBIT 4.2 Form of Rights Agreement PG&E CORPORATION and MELLON INVESTOR SERVICES LLC Rights Agent Rights Agreement Dated as of December 22, 2000 TABLE OF CONTENTS -----------------
Page ---- SECTION 1. Certain Definitions........................................... 1 SECTION 2. Appointment of Rights Agent................................... 5 SECTION 3. Issue of Rights Certificates.................................. 5 SECTION 4. Form of Rights Certificates................................... 7 SECTION 5. Countersignature and Registration............................. 8 SECTION 6. Transfer, Split Up, Combination and Exchange of Rights Certificates; Mutilated, Destroyed, Lost or Stolen Rights Certificates.................................................. 8 SECTION 7. Exercise of Rights; Purchase Price; Expiration Date of Rights..................................................... 9 SECTION 8. Cancellation and Destruction of Rights Certificates........... 11 SECTION 9. Reservation and Availability of Capital Stock................. 11 SECTION 10. Preferred Stock Record Date.................................. 12 SECTION 11. Adjustment of Purchase Price, Number and Kind of Shares or Number of Rights.......................................... 13 SECTION 12. Certificate of Adjusted Purchase Price or Number of Shares... 21 SECTION 13. Consolidation, Merger or Sale or Transfer of Assets or Earning Power................................................ 21 SECTION 14. Fractional Rights and Fractional Shares...................... 24 SECTION 15. Rights of Action............................................. 25 SECTION 16. Agreement of Rights Holders.................................. 25 SECTION 17. Rights Certificate Holder Not Deemed a Shareholder........... 26 SECTION 18. Concerning the Rights Agent.................................. 26 SECTION 19. Merger or Consolidation or Change of Name of Rights Agent.... 27 SECTION 20. Duties of Rights Agent....................................... 27 SECTION 21. Change of Rights Agent....................................... 30 SECTION 22. Issuance of New Rights Certificates.......................... 31 SECTION 23. Redemption and Termination................................... 31
i SECTION 24. Notice of Certain Events...................................... 32 SECTION 25. Notices....................................................... 32 SECTION 26. Supplements and Amendments.................................... 33 SECTION 27. Successors.................................................... 34 SECTION 28. Determinations and Actions by the Board of Directors, etc..... 34 SECTION 29. Benefits of this Agreement.................................... 34 SECTION 30. Severability.................................................. 35 SECTION 31. Governing Law................................................. 35 SECTION 32. Counterparts.................................................. 35 SECTION 33. Descriptive Headings.......................................... 35 SECTION 34. Exchange...................................................... 35
ii RIGHTS AGREEMENT RIGHTS AGREEMENT, dated as of December 22, 2000 (this "Agreement"), between PG&E CORPORATION, a California corporation (the "Company"), and MELLON INVESTOR SERVICES LLC, a New Jersey limited liability company (the "Rights Agent"). WHEREAS, effective December 20, 2000 (the "Rights Dividend Declaration Date"), the Board of Directors of the Company authorized and declared a distribution of one Right (each, a "Right") for each share of Common Stock, no par value per share, of the Company (the "Company Common Stock") outstanding at the Close of Business (as defined below) on January 2, 2001 (the "Record Date"), and has authorized the issuance of one Right (as such number may hereinafter be adjusted pursuant hereto) for each share of Company Common Stock issued between the Record Date and, except as otherwise provided in Section 22, the Distribution Date, each Right initially representing the right to purchase upon the terms and subject to the conditions hereinafter set forth one Unit (as defined below) of Series A Preferred Stock (as defined below); WHEREAS, the Company desires to set forth certain terms and conditions governing the Rights; and WHEREAS, the Company desires to appoint the Rights Agent to act as rights agent hereunder, in accordance with the terms and conditions hereof; NOW, THEREFORE, in consideration of the premises and the mutual agreements herein set forth, the parties hereby agree as follows: SECTION 1. Certain Definitions. For purposes of this Agreement, the following terms have the meanings indicated: (a) "Acquiring Person" shall mean any Person who or which, alone or together with all Affiliates and Associates of such Person, shall be the Beneficial Owner of 15% or more of the shares of Company Common Stock then outstanding, but shall not include (i) the Company, any Subsidiary of the Company, any employee benefit plan maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity or (ii) any such Person who has become and is such a Beneficial Owner solely because (A) of a change in the aggregate number of shares of the Company Common Stock since the last date on which such Person acquired Beneficial Ownership of any shares of the Company Common Stock or (B) it acquired such Beneficial Ownership in the good faith belief that such acquisition would not (1) cause such Beneficial Ownership to be equal to or exceed 15% of the shares of the Company Common Stock then outstanding and such Person relied in good faith in computing the percentage of its Beneficial Ownership on publicly filed reports or documents of the Company that are inaccurate or out-of-date or (2) otherwise cause a Distribution Date or the adjustment provided for in Section 11(a)(iii) to occur. Notwithstanding clause (ii)(B) of the prior sentence, if any Person that is not an Acquiring Person due to such clause (ii)(B) does not reduce its percentage of Beneficial Ownership of the Company Common Stock to less than 15% by the Close of Business on the fifth Business Day after notice from the Company (the date on which such notice is first mailed or sent or delivered being the first day) that such person's Beneficial Ownership of the Company Common Stock is equal to or exceeds 15%, such Person shall, at the end of such five Business Day period, become an Acquiring Person (and such clause (ii)(B) shall no longer apply to such Person). For purposes of this definition, the determination whether any Person acted in "good faith" shall be conclusively determined by the Board of Directors of the Company, acting by a vote of those directors of the Company whose approval would be required to redeem the Rights under Section 23 hereof. (b) "Adjustment Shares" has the meaning set forth in Section 11(a)(iii). (c) "Adjustment Spread" has the meaning set forth in Section 34(a)(ii). (d) "Affiliate" and "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 of the Exchange Act Regulations as in effect on the date of this Agreement. (e) "Agreement" has the meaning set forth in the preamble to this Agreement. (f) A Person shall be deemed the "Beneficial Owner" of, and shall be deemed to "beneficially own", and shall be deemed to have "Beneficial Ownership" of, any securities: (i) of which such Person or any of such Person's Affiliates or Associates is considered to be a "beneficial owner" under Rule 13d-3 of the Exchange Act Regulations as in effect on the date of this Agreement; provided, however, that a Person shall not be deemed the "Beneficial Owner" of, or to "beneficially own", or to have "Beneficial Ownership" of, any securities under this subparagraph (i) as a result of an agreement, arrangement or understanding to vote such securities if such agreement, arrangement or understanding (A) arises solely from a revocable proxy given in response to a proxy or consent solicitation made pursuant to, and in accordance with, the applicable provisions of the Exchange Act and the Exchange Act Regulations, and (B) is not reportable by such Person on Schedule 13D under the Exchange Act (or any comparable or successor report); (ii) that are beneficially owned, directly or indirectly, by any other Person (or any Affiliate or Associate of such other Person) with which such Person (or any of such Person's Affiliates or Associates) has any agreement, arrangement or understanding (whether or not in writing), for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in the proviso to subparagraph (i) of this paragraph (f)) or disposing of such securities; or (iii) that such Person or any of such Person's Affiliates or Associates, directly or indirectly, has the right to acquire (whether such right is exercisable immediately or only after the passage of time or upon the satisfaction of 2 conditions) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that under this paragraph (f) a Person shall not be deemed the "Beneficial Owner" of, or to "beneficially own", or to have "Beneficial Ownership" of, (A) securities tendered pursuant to a tender or exchange offer made in accordance with Exchange Act Regulations by such Person or any of such Person's Affiliates or Associates until such tendered securities are accepted for purchase or exchange, (B) securities that may be issued upon exercise of Rights at any time prior to the occurrence of a Triggering Event or (C) securities that may be issued upon exercise of Rights from and after the occurrence of a Triggering Event, which Rights were acquired by such Person or any of such Person's Affiliates or Associates prior to the Distribution Date or pursuant to Section 3(c) or Section 22 or pursuant to Section 11(i) in connection with an adjustment made with respect to any such Rights. (g) "Business Day" shall mean any day other than a Saturday, Sunday or a day on which banking institutions in the State of California or the State of New Jersey are authorized or obligated by law or executive order to close. (h) "Close of Business" on any given date shall mean 5:00 p.m., California time, on such date; provided, however, that if such date is not a Business Day it shall mean 5:00 p.m., California time, on the next succeeding Business Day. (i) "Common Stock" of any Person other than the Company shall mean the capital stock of such Person with the greatest voting power, or, if such Person shall have no capital stock, the equity securities or other equity interest having power to control or direct the management of such Person. (j) "Company" has the meaning set forth in the preamble to this Agreement. (k) "Company Common Stock" has the meaning set forth in the recitals to this Agreement. (l) "Current Value" has the meaning set forth in Section 11(a)(iv). (m) "Depositary Agent" has the meaning set forth in Section 7(c). (n) "Distribution Date" has the meaning set forth in Section 3(a). (o) "Equivalent Preferred Stock" has the meaning set forth in Section 11(b). (p) "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended. (q) "Exchange Act Regulations" shall mean the General Rules and Regulations promulgated under the Exchange Act. 3 (r) "Expiration Date" has the meaning set forth in Section 7(a). (s) "Final Expiration Date" has the meaning set forth in Section 7(a). (t) "Person" shall mean any individual, partnership, limited liability company, firm, corporation, joint venture, association, trust, unincorporated organization or other entity, as well as any syndicate or group deemed to be a person under Section 14(d)(2) of the Exchange Act. (u) "Preferred Stock" shall mean the Series A Preferred Stock, par value $100 per share, of the Company having the voting powers, designation, preferences and relative, participating, optional or other special rights and qualifications, limitations and restrictions described in the Certificate of Determination set forth as Exhibit C hereto. (v) "Preferred Stock Equivalents" has the meaning set forth in Section 11(a)(iv). (w) "Principal Party" has the meaning set forth in Section 13(b). (x) "Purchase Price" has the meaning set forth in Section 7(b). (y) "Record Date" has the meaning set forth in the recitals to this Agreement. (z) "Redemption Price" has the meaning set forth in Section 23(a). (aa) "Registered Common Stock" has the meaning set forth in Section 13(b)(ii). (bb) "Registration Date" has the meaning set forth in Section 9(c). (cc) "Registration Statement" has the meaning set forth in Section 9(c). (dd) "Right" has the meaning set forth in the recitals to this Agreement. (ee) "Rights Agent" has the meaning set forth in the preamble to this Agreement. (ff) "Rights Certificates" has the meaning set forth in Section 3(a). (gg) "Rights Dividend Declaration Date" has the meaning set forth in the recitals to this Agreement. (hh) "Section 11(a)(iii) Event" has the meaning set forth in Section 11(a)(iii). (ii) "Section 11(a)(iv) Trigger Date" has the meaning set forth in Section 11(a)(iv). (jj) "Section 13 Event" has the meaning set forth in Section 13(a). 4 (kk) "Section 34(a)(i) Exchange Ratio" has the meaning set forth in Section 34(a)(i). (ll) "Section 34(a)(ii) Exchange Ratio" has the meaning set forth in Section 34(a)(ii). (mm) "Securities Act" shall mean the Securities Act of 1933, as amended. (nn) "Spread" has the meaning set forth in Section 11(a)(iv). (oo) "Stock Acquisition Date" shall mean the first date of public announcement (including, without limitation, the filing of any report pursuant to Section 13(d) of the Exchange Act) by the Company or an Acquiring Person that an Acquiring Person has become such. (pp) "Subsidiary" of any Person shall mean any corporation or other Person of which a majority of the voting power of the voting equity securities or equity interest is beneficially owned, directly or indirectly, by such Person, or otherwise controlled by such Person. (qq) "Summary of Rights" has the meaning set forth in Section 3(b). (rr) "Trading Day" has the meaning set forth in Section 11(d)(i). (ss) "Triggering Event" shall mean any Section 11(a)(iii) Event or any Section 13 Event. (tt) "Unit" has the meaning set forth in Section 7(b). SECTION 2. Appointment of Rights Agent. The Company hereby appoints the Rights Agent to act as agent for the Company in accordance with the terms and conditions hereof, and the Rights Agent hereby accepts such appointment. With the consent of the Rights Agent, the Company may from time to time appoint such Co-Rights Agents as it may deem necessary or desirable. The Rights Agent shall have no duty to supervise, and in no event shall be liable for, the acts or omissions of any such co-Rights Agent. SECTION 3. Issue of Rights Certificates. (a) Until the earlier of (i) the Close of Business on the tenth day after the Stock Acquisition Date and (ii) the Close of Business on the tenth Business Day (or such later date as may be determined by action of the Company's Board of Directors prior to such time as any Person becomes an Acquiring Person, and of which the Company will give the Rights Agent prompt written notice) after the date that a tender or exchange offer by any Person (other than the Company, any Subsidiary of the Company, any employee benefit plan maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity) is first published or sent or given within the meaning of Rule 14d-4(a) of the Exchange Act Regulations or any successor rule, if upon consummation thereof such Person would be the Beneficial Owner of 15% or more of the shares of Company Common Stock then outstanding (the earlier of (i) and (ii) above being the "Distribution Date"), (x) the Rights will be evidenced (subject to the provisions of paragraph (b) 5 of this Section 3) by the certificates for shares of Company Common Stock registered in the names of the holders of shares of Company Common Stock as of and subsequent to the Record Date (which certificates for shares of Company Common Stock shall be deemed also to be certificates for Rights) and not by separate certificates, and (y) the Rights will be transferable only in connection with the transfer of the underlying shares of Company Common Stock (including a transfer to the Company). As soon as practicable after the Distribution Date, the Company shall promptly notify in writing the Rights Agent of the occurrence of the Distribution Date and, if the Rights Agent is no longer the Company's transfer agent, provide the Rights Agent with the names and addresses of all record holders of Commmon shares (together with all other necessary information), and the Rights Agent will send by first-class, insured, postage prepaid mail, to each record holder of shares of Company Common Stock as of the Close of Business on the Distribution Date, at the address of such holder shown on the records of the Company, one or more rights certificates, in substantially the form attached hereto as Exhibit A (the "Rights Certificates"), evidencing one Right for each share of Company Common Stock so held, subject to adjustment as provided herein. In the event that an adjustment in the number of Rights per share of Company Common Stock has been made pursuant to Section 11(p), at the time of distribution of the Rights Certificates, the Company may make the necessary and appropriate rounding adjustments (in accordance with Section 14(a)) so that Rights Certificates evidencing only whole numbers of Rights are distributed and cash is paid in lieu of any fractional Rights. As of and after the Distribution Date, the Rights will be evidenced solely by such Rights Certificates. (b) As promptly as practicable following the Record Date, the Company will send a copy of a Summary of Rights to Purchase Preferred Stock, in a form that may be appended to certificates that evidence shares of Company Common Stock, in substantially the form attached hereto as Exhibit B (the "Summary of Rights"), by first-class, postage prepaid mail, to each record holder of shares of Company Common Stock as of the Close of Business on the Record Date, at the address of such holder shown on the records of the Company. (c) Rights shall, without any further action, be issued in respect of all shares of Company Common Stock that are issued (including any shares of Company Common Stock held in treasury) after the Record Date but prior to the earlier of the Distribution Date and the Expiration Date. Certificates evidencing such shares of Company Common Stock issued after the Record Date shall bear the following legend or such similar legend as the Company may deem appropriate and as is not inconsistent with the provisions of this Agreement: "This certificate also evidences and entitles the holder hereof to certain Rights as set forth in the Rights Agreement, dated as of December 22, 2000 (the "Rights Agreement"), between PG&E Corporation (the "Company") and Mellon Investor Services LLC (the "Rights Agent"), the terms of which are hereby incorporated herein by reference and a copy of which is on file at the office of the Rights Agent designated for such purpose. Under certain circumstances, as set forth in the Rights Agreement, such Rights will be evidenced by separate certificates and will no longer be evidenced by this certificate. The Company will mail to the holder of this certificate a copy of the Rights Agreement, as in effect on the date of mailing, without charge promptly after receipt of a written request therefor. Under certain circumstances set forth in the Rights Agreement, Rights issued to, or held by, any Person who is, was or becomes an Acquiring Person or any Affiliate or Associate thereof (as such terms are defined in the Rights 6 Agreement), whether currently held by or on behalf of such Person or by any subsequent holder, may become null and void." With respect to certificates evidencing shares of Company Common Stock (whether or not such certificates include the foregoing legend or have appended to them the Summary of Rights), until the earlier of the Distribution Date and the Expiration Date, the Rights associated with the shares of Company Common Stock evidenced by such certificates shall be evidenced by such certificates alone and registered holders of the shares of Company Common Stock shall also be the registered holders of the associated Rights, and the transfer of any of such certificates shall also constitute the transfer of the Rights associated with the shares of Company Common Stock evidenced by such certificates. SECTION 4. Form of Rights Certificates. (a) The Rights Certificates (and the forms of election to purchase, assignment and certificate to be printed on the reverse thereof) shall each be substantially in the form attached hereto as Exhibit A and may have such marks of identification or designation and such legends, summaries or endorsements printed thereon as the Company may deem appropriate (which do not affect the duties or responsibilities of the Rights Agent) and as are not inconsistent with the provisions of this Agreement, or as may be required to comply with any applicable law or any rule or regulation thereunder or with any rule or regulation of any stock exchange on which the Rights may from time to time be listed or to conform to usage. Subject to the provisions of Section 11 and Section 22, the Rights Certificates, whenever distributed, shall be dated as of the Record Date and on their face shall entitle the holders thereof to purchase such number of Units of Preferred Stock as shall be set forth therein at the price set forth therein, but the amount and type of securities, cash or other assets that may be acquired upon the exercise of each Right and the Purchase Price thereof shall be subject to adjustment as provided herein. (b) Any Rights Certificate issued pursuant hereto that evidences Rights beneficially owned by: (i) an Acquiring Person or any Associate or Affiliate of an Acquiring Person, (ii) a transferee of an Acquiring Person (or of any such Associate or Affiliate) that becomes a transferee after the Acquiring Person becomes such, or (iii) a transferee of an Acquiring Person (or of any such Associate or Affiliate) that becomes a transferee prior to or concurrently with the Acquiring Person becoming such and that receives such Rights pursuant to either (A) a transfer (whether or not for consideration) from the Acquiring Person (or any such Associate or Affiliate) to holders of equity interests in such Acquiring Person (or such Associate or Affiliate) or to any Person with whom such Acquiring Person (or such Associate or Affiliate) has any continuing agreement, arrangement or understanding regarding either the transferred Rights, shares of Company Common Stock or the Company or (B) a transfer that a majority of the Company's Board of Directors has determined to be part of a plan, arrangement or understanding that has as a primary purpose or effect the avoidance of Section 7(e), shall, upon the written direction of a majority of the Company's Board of Directors, contain (to the extent the Rights Agent has notice thereof and to the extent feasible) the following legend or such similar legend as the Company may deem appropriate and as is not inconsistent with the provisions of this Agreement: "The Rights evidenced by this Rights Certificate are or were beneficially owned by a Person who was or became an Acquiring Person or an Affiliate or 7 Associate of an Acquiring Person (as such terms are defined in the Rights Agreement). Accordingly, this Rights Certificate and the Rights evidenced hereby may become null and void in the circumstances specified in Section 7(e) of such Agreement." SECTION 5. Countersignature and Registration. (a) Rights Certificates shall be executed on behalf of the Company by its Chairman of the Board, the President or any of its Senior Vice Presidents, under its corporate seal reproduced thereon attested by its Secretary or one of its Assistant Secretaries. The signature of any one or more of these officers on the Rights Certificates may be manual or facsimile. Rights Certificates bearing the manual or facsimile signatures of the individuals who were at any time the proper officers of the Company shall bind the Company, notwithstanding that such individuals or any of them have ceased to hold such offices prior to the countersignature of such Rights Certificates or did not hold such offices at the date of such Rights Certificates. No Rights Certificate shall be entitled to any benefit under this Agreement or be valid for any purpose unless there appears on such Rights Certificate a countersignature duly executed by the Rights Agent by manual signature of an authorized signatory, and such countersignature upon any Rights Certificate shall be conclusive evidence, and the only evidence, that such Rights Certificate has been duly countersigned as required hereunder. In case any officer of the Company who shall have signed any of the Rights Certificates shall cease to be such officer of the Company before countersignature by the Rights Agent and issuance and delivery by the Company, such Rights Certificates, nevertheless, may be countersigned by the Rights Agent and issued and delivered by the Company with the same force and effect as though the person who signed such Rights Certificates on behalf of the Company had not ceased to be such officer of the Company. (b) Following the Distribution Date and receipt by the Rights Agent of the written notice referred to in Section 3(a), the Rights Agent will keep or cause to be kept, at its office designated for surrender of Rights Certificates upon exercise or transfer, books for registration and transfer of the Rights Certificates issued hereunder. Such books shall show the name and address of each holder of the Rights Certificates, the number of Rights evidenced on its face by each Rights Certificate and the date of each Rights Certificate. SECTION 6. Transfer, Split Up, Combination and Exchange of Rights Certificates; Mutilated, Destroyed, Lost or Stolen Rights Certificates. (a) Subject to the provisions of Sections 4(b), 7(e) and 14, at any time after the Close of Business on the Distribution Date, and at or prior to the Close of Business on the Expiration Date, any Rights Certificate or Certificates may be transferred, split up, combined or exchanged for another Rights Certificate or Certificates, entitling the registered holder to purchase a like number of Units of Preferred Stock (or, following a Triggering Event, other securities, cash or other assets, as the case may be) as the Rights Certificate or Certificates surrendered then entitled such holder to purchase. Any registered holder desiring to transfer, split up, combine or exchange any Rights Certificate or Certificates shall make such request in writing delivered to the Rights Agent, and shall surrender the Rights Certificate or Certificates to be transferred, split up, combined or exchanged at the office of the Rights Agent designated for such purpose. Neither the Rights Agent nor the Company shall be obligated to take any action whatsoever with respect to the transfer of any such surrendered Rights Certificate until the registered holder shall have properly completed and executed the certificate set forth in the form of assignment on the reverse side of 8 such Rights Certificate and shall have provided such additional evidence of the identity of the Beneficial Owner (or former Beneficial Owner) of the Rights evidenced by such Rights Certificate or Affiliates or Associates thereof as the Company or the Rights Agent shall reasonably request; whereupon the Rights Agent shall, subject to the provisions of Sections 4(b), 7(e) and 14, countersign and deliver to the Person entitled thereto a Rights Certificate or Rights Certificates, as the case may be, as so requested. The Company may require payment of a sum sufficient to cover any tax or governmental charge that may be imposed in connection with any transfer, split up, combination or exchange of Rights Certificates. The Rights Agent shall have no duty or obligation under this Section 6 or any other similar provision of this Agreement unless and until it is satisfied that all such taxes and/or governmental charges have been paid. (b) If a Rights Certificate shall be mutilated, destroyed, lost or stolen, upon request by the registered holder of the Rights evidenced thereby and upon payment to the Company and the Rights Agent of all reasonable expenses incident thereto, there shall be issued, in exchange for and upon cancellation of the mutilated Rights Certificate, or in substitution for the lost, stolen or destroyed Rights Certificate, a new Rights Certificate, in substantially the form of the prior Rights Certificate, of like tenor and evidencing the equivalent number of Rights, but, in the case of loss, theft or destruction, only upon receipt of evidence satisfactory to the Company and the Rights Agent of such loss, theft or destruction of such Rights Certificate and, if requested by the Company or the Rights Agent, indemnity also satisfactory to it. SECTION 7. Exercise of Rights; Purchase Price; Expiration Date of Rights. (a) Prior to the earlier of (i) the Close of Business on the tenth anniversary hereof (the "Final Expiration Date") and (ii) the time at which the Rights are redeemed as provided in Section 23 (the earlier of (i) and (ii) being the "Expiration Date"), the registered holder of any Rights Certificate may, subject to the provisions of Sections 7(e) and 9(c), exercise the Rights evidenced thereby in whole or in part at any time after the Distribution Date upon surrender of the Rights Certificate, with the form of election to purchase and the certificate on the reverse side thereof duly executed, to the Rights Agent at the office of the Rights Agent designated for such purpose, together with payment of the aggregate Purchase Price (as hereinafter defined) for the number of Units of Preferred Stock (or, following a Triggering Event, other securities, cash or other assets, as the case may be) for which such surrendered Rights are then exercisable. (b) The purchase price for each one one-hundredth of a share (each such one one-hundredth of a share being a "Unit") of Preferred Stock upon exercise of Rights shall be $95, subject to adjustment from time to time as provided in Sections 11 and 13(a) (such purchase price, as so adjusted, being the "Purchase Price"), and shall be payable in accordance with paragraph (c) below. (c) As promptly as practicable following the occurrence of the Distribution Date, the Company shall deposit with a Person in good standing organized under the laws of the United States or any State of the United States, that is authorized under such laws to exercise shareholder services business, corporate trust or stock transfer powers and is subject to supervision or examination by federal or state authority (such institution being the "Depositary Agent"), certificates evidencing the shares of Preferred Stock that may be acquired upon exercise of the Rights and shall cause such Depositary Agent to enter into an agreement pursuant to which the Depositary Agent shall issue receipts evidencing interests in the shares of Preferred Stock so 9 deposited. Upon receipt of written notice that the Distribution Date has occurred and receipt of a Rights Certificate evidencing exercisable Rights, with the form of election to purchase and the certificate duly executed, accompanied by payment, with respect to each Right so exercised, of the Purchase Price for the Units of Preferred Stock (or, following a Triggering Event, other securities, cash or other assets, as the case may be) to be purchased thereby as set forth below and an amount equal to any applicable tax or governmental charge or evidence satisfactory to the Company of payment of such tax or governmental charge, the Rights Agent shall, subject to Section 20(k), thereupon promptly (i) requisition from the Depositary Agent depositary receipts or certificates evidencing such number of Units of Preferred Stock as are to be purchased and the Company will direct the Depositary Agent to comply with such request, (ii) requisition from the Company the amount of cash, if any, to be paid in lieu of fractional shares in accordance with Section 14, (iii) after receipt of such depositary receipts or certificates, cause the same to be delivered to or upon the order of the registered holder of such Rights Certificate, registered in such name or names as may be designated by such holder, and (iv) after receipt thereof, deliver such cash, if any, to or upon the order of the registered holder of such Rights Certificate. In the event that the Company is obligated to issue Company Common Stock, other securities of the Company, pay cash and/or distribute other property pursuant to Section 11(a), the Company will make all arrangements necessary so that such Company Common Stock, other securities, cash and/or other property are available for distribution by the Rights Agent, if and when necessary to comply with this Agreement. Subject to Section 34, the payment of the Purchase Price (as such amount may be reduced pursuant to Section 11(a)(iv)) may be made in cash or by certified or bank check payable to the order of the Company, or by wire transfer of immediately available funds to the account of the Company (provided that notice of such wire transfer shall be given by the holder of the related Right to the Rights Agent). (d) In case the registered holder of any Rights Certificate shall exercise less than all the Rights evidenced thereby, a new Rights Certificate evidencing the Rights remaining unexercised shall be issued by the Rights Agent and delivered to, or upon the order of, the registered holder of such Rights Certificate, registered in such name or names as may be designated by such holder, subject to the provisions of Section 14 hereof. (e) Notwithstanding anything in this Agreement to the contrary, from and after the first occurrence of any Section 11(a)(iii) Event or Section 13 Event, any Rights beneficially owned by (i) an Acquiring Person or an Associate or Affiliate of an Acquiring Person, (ii) a transferee of an Acquiring Person (or of any such Associate or Affiliate) that becomes a transferee after the Acquiring Person becomes such, or (iii) a transferee of an Acquiring Person (or of any such Associate or Affiliate) that becomes a transferee prior to or concurrently with the Acquiring Person becoming such and that receives such Rights pursuant to either (A) a transfer (whether or not for consideration) from the Acquiring Person (or any such Associate or Affiliate) to holders of equity interests in such Acquiring Person (or such Associate or Affiliate) or to any Person with whom such Acquiring Person (or such Associate or Affiliate) has any continuing agreement, arrangement or understanding regarding the transferred Rights, shares of Company Common Stock or the Company or (B) a transfer that a majority of the Company's Board of Directors has determined to be part of a plan, arrangement or understanding that has as a primary purpose or effect the avoidance of this Section 7(e), shall be null and void without any further action, and no holder of such Rights shall have any rights whatsoever with respect to such Rights, whether under any provision of this Agreement or otherwise. The 10 Company shall use all reasonable efforts to ensure that the provisions of this Section 7(e) and Section 4(b) are complied with, but neither the Company nor the Rights Agent shall have any liability to any holder of Rights or any other Person as a result of the Company's failure to make any determination under this Section 7(e) or Section 4(b) with respect to an Acquiring Person or its Affiliates, Associates or transferees. (f) Notwithstanding anything in this Agreement or any Rights Certificate to the contrary, neither the Rights Agent nor the Company shall be obligated to undertake any action with respect to a registered holder upon the occurrence of any purported exercise by such registered holder unless such registered holder shall have (i) properly completed and executed the certificate following the form of election to purchase set forth on the reverse side of the Rights Certificate surrendered for such exercise and (ii) provided such additional evidence of the identity of the Beneficial Owner (or former Beneficial Owner) of the Rights evidenced by such Rights Certificate or Affiliates or Associates thereof as the Company shall request. SECTION 8. Cancellation and Destruction of Rights Certificates. All Rights Certificates surrendered for the purpose of exercise, transfer, split up, combination or exchange shall, if surrendered to the Company or any of its agents, be delivered to the Rights Agent for cancellation or in cancelled form, or, if surrendered to the Rights Agent, shall be cancelled by it, and no Rights Certificates shall be issued in lieu thereof except as expressly permitted by this Agreement. The Company shall deliver to the Rights Agent for cancellation and retirement, and the Rights Agent shall so cancel and retire, any Rights Certificates acquired by the Company otherwise than upon the exercise thereof. The Rights Agent shall deliver all cancelled Rights Certificates to the Company, or shall, at the written request of the Company, destroy such cancelled Rights Certificates, and in such case shall deliver a certificate of destruction thereof to the Company. SECTION 9. Reservation and Availability of Capital Stock. (a) The Company shall at all times prior to the Expiration Date cause to be reserved and kept available, out of its authorized and unissued shares of Preferred Stock, the number of shares of Preferred Stock that, as provided in this Agreement, will be sufficient to permit the exercise in full of all outstanding Rights. Upon the occurrence of any events resulting in an increase in the aggregate number of shares of Preferred Stock (or other equity securities of the Company) issuable upon exercise of all outstanding Rights above the number then reserved, the Company shall make appropriate increases in the number of shares so reserved. (b) If the shares of Preferred Stock to be issued and delivered upon the exercise of the Rights may be listed on any national securities exchange, the Company shall during the period from the Distribution Date through the Expiration Date use its best efforts to cause all securities reserved for such issuance to be listed on such exchange upon official notice of issuance upon such exercise. (c) The Company shall use its best efforts (i) as soon as practicable following the occurrence of a Section 11(a)(iii) Event and a determination by the Company in accordance with Section 11(a)(iv) of the consideration to be delivered by the Company upon exercise of the Rights or, if so required by law, as soon as practicable following the Distribution Date (such date being the "Registration Date"), to file a registration statement on an appropriate form under the 11 Securities Act with respect to the securities that may be acquired upon exercise of the Rights (the "Registration Statement"), (ii) to cause the Registration Statement to become effective as soon as practicable after such filing, (iii) to cause the Registration Statement to continue to be effective (and to include a prospectus complying with the requirements of the Securities Act) until the earlier of (A) the date as of which the Rights are no longer exercisable for the securities covered by the Registration Statement and (B) the Expiration Date and (iv) to take as soon as practicable following the Registration Date such action as may be required to ensure that any acquisition of securities upon exercise of the Rights complies with any applicable state securities or "blue sky" laws. If the Registration Statement does not become effective prior to the Close of Business on the 45th Business Day following the occurrence of a Section 11(a)(iii) Event, the Company shall, unless otherwise determined by a majority of the Company's Board of Directors, on the 46th Business Day following the occurrence of such Section 11(a)(iii) Event, be obligated to exercise the option described in Section 34 and shall promptly notify the Rights Agent in writing of such exercise. (d) The Company shall take such action as may be necessary to ensure that all shares of Preferred Stock (and, following the occurrence of a Triggering Event, any other securities that may be delivered upon exercise of Rights) shall be, at the time of delivery of the certificates or depositary receipts for such securities, duly and validly authorized and issued and fully paid and non- assessable. (e) The Company shall pay any tax or governmental charge imposed in connection with the issuance or delivery of the Rights Certificates or upon the exercise of Rights; provided, however, that the Company shall not be required to pay any such tax imposed in connection with the issuance or delivery of Units of Preferred Stock, or any certificates or depositary receipts for such Units of Preferred Stock (or, following the occurrence of a Triggering Event, any other securities, cash or assets, as the case may be) to any Person other than the registered holder of the Rights Certificates evidencing the Rights surrendered for exercise. The Company shall not be required to issue or deliver any certificates or depositary receipts for Units of Preferred Stock (or, following the occurrence of a Triggering Event, any other securities, cash or assets, as the case may be) to, or in a name other than that of, the registered holder of the Rights Certificate upon the exercise of any Rights evidenced thereby until any such tax or governmental charge shall have been paid (any such tax or governmental charge being payable by the holder of such Rights Certificate at the time of surrender) or until it has been established to the Company's satisfaction that no such tax or governmental charge is due. SECTION 10. Preferred Stock Record Date. Each Person in whose name any certificate or depositary receipt for Units of Preferred Stock (or, following the occurrence of a Triggering Event, other securities) is issued upon the exercise of Rights shall for all purposes be deemed to have become the holder of record of the Units of Preferred Stock (or, following the occurrence of a Triggering Event, other securities) evidenced thereby on, and such certificate or depositary receipt shall be dated, the date upon which the Rights Certificate evidencing such Rights was duly surrendered and payment of the Purchase Price (and any applicable taxes or governmental charges) was made; provided, however, that if the date of such surrender and payment is a date upon which the Preferred Stock (or, following the occurrence of a Triggering Event, other securities) transfer books of the Company are closed, such Person shall be deemed 12 to have become the record holder of such securities on, and such certificate or depositary receipt shall be dated, the next succeeding Business Day on which the Preferred Stock (or, following the occurrence of a Triggering Event, other securities) transfer books of the Company are open; and further provided, however, that if delivery of Units of Preferred Stock is delayed as a result of a failure to register such Units of Preferred Stock pursuant to Section 9(c), such Persons shall be deemed to have become the record holders of such Units of Preferred Stock only when such Units first become deliverable. Prior to the exercise of the Rights evidenced thereby, the holder of a Rights Certificate shall not be entitled to any rights of a shareholder of the Company with respect to securities for which the Rights shall be exercisable, including, without limitation, the right to vote, to receive dividends or other distributions or to exercise any preemptive rights, and shall not be entitled to receive any notice of any proceedings of the Company, except as provided herein. SECTION 11. Adjustment of Purchase Price, Number and Kind of Shares or Number of Rights. The Purchase Price, the number and kind of securities covered by each Right and the number of Rights outstanding are subject to adjustment from time to time as provided in this Section 11. (a) (i) In the event the Company shall at any time after the date of this Agreement (A) declare a dividend on the Preferred Stock payable in shares of Preferred Stock, (B) subdivide the outstanding Preferred Stock, (C) combine the outstanding Preferred Stock into a smaller number of shares or (D) issue any shares of its capital stock in a reclassification of the Preferred Stock (including any such reclassification in connection with a consolidation or merger in which the Company is the continuing or surviving corporation), except as otherwise provided in this Section 11(a), the Purchase Price in effect at the time of the record date for such dividend or of the effective date of such subdivision, combination or reclassification, and the number and kind of shares of Preferred Stock or capital stock, as the case may be, issuable on such date upon exercise of the Rights, shall be proportionately adjusted so that the holder of any Right exercised after such time shall be entitled to receive, upon payment of the Purchase Price then in effect, the aggregate number and kind of shares of Preferred Stock or capital stock, as the case may be, which, if such Right had been exercised immediately prior to such date, such holder would have owned upon such exercise and been entitled to receive by virtue of such dividend, subdivision, combination or reclassification. If an event occurs that would require an adjustment under both this Section 11(a)(i) and Section 11(a)(iii), the adjustment provided for in this Section 11(a)(i) shall be in addition to, and shall be made prior to, any adjustment required pursuant to Section 11(a)(iii). (ii) Upon the declaration of a dividend in connection with any spin- off or other similar transaction effected by the Company (whether occurring before or after a Distribution Date), the Purchase Price in effect at the time of the record date therefor, and the number and kind of shares of Preferred Stock or capital stock, as the case may be, issuable at such time upon exercise of the Rights, may be adjusted by action of a majority of the Company's Board of Directors, after receiving advice from a nationally recognized investment banking firm, in a manner that reflects the impact on the Company Common Stock of such spin-off or other similar transaction. If an event occurs that the Company's Board of Directors determines would require an adjustment under both this Section 11(a)(ii) and Section 11(a)(iii), the adjustment 13 provided for in this Section 11(a)(ii) shall be in addition to, and shall be made prior to, any adjustment required pursuant to Section 11(a)(iii). (iii) In the event: (A) any Acquiring Person or any Associate or Affiliate of any Acquiring Person, at any time after the date of this Agreement, directly or indirectly, shall (1) merge into the Company or otherwise combine with the Company and the Company shall be the continuing or surviving corporation of such merger or combination and Company Common Stock shall remain outstanding and unchanged, (2) in one transaction or a series of transactions, transfer any assets to the Company or to any of its Subsidiaries in exchange (in whole or in part) for shares of Company Common Stock, for other equity securities of the Company or any such Subsidiary, or for securities exercisable for or convertible into shares of equity securities of the Company or any of its Subsidiaries (whether Company Common Stock or otherwise) or otherwise obtain from the Company or any of its Subsidiaries, with or without consideration, any additional shares of such equity securities or securities exercisable for or convertible into such equity securities (other than pursuant to a pro rata distribution to all holders of Company Common Stock), (3) sell, purchase, lease, exchange, mortgage, pledge, transfer or otherwise acquire or dispose of, in one transaction or a series of transactions, to, from or with the Company or any of its Subsidiaries or any employee benefit plan maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity, assets (including securities) on terms and conditions less favorable to the Company or such Subsidiary or plan than those that could have been obtained in arm's-length negotiations with an unaffiliated third party, other than pursuant to a transaction set forth in Section 13(a), (4) sell, purchase, lease, exchange, mortgage, pledge, transfer or otherwise acquire or dispose of, in one transaction or a series of transactions, to, from or with the Company or any of the Company's Subsidiaries or any employee benefit plan maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity (other than transactions, if any, consistent with those engaged in, as of the date hereof, by the Company and such Acquiring Person or such Associate or Affiliate), assets (including securities) having an aggregate fair market value of more than $5,000,000, other than pursuant to a transaction set forth in Section 13(a), (5) sell, purchase, lease, exchange, mortgage, pledge, transfer or otherwise acquire or dispose of, in one transaction or a series of transactions, to, from or with the Company or any of its Subsidiaries or any employee benefit plan maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity, any material trademark or material service mark, other than pursuant to a transaction set forth in Section 13(a), (6) receive, or any designee, agent or representative of such Acquiring Person or any Affiliate or Associate of such Acquiring Person shall receive, any compensation from the Company or any of its Subsidiaries other than compensation for full-time employment as a regular employee at rates in accordance with the Company's (or its Subsidiaries') past practices, or (7) receive the benefit, directly or indirectly (except proportionately as a holder of Company Common Stock or as required by law or governmental regulation), of any loans, advances, guarantees, pledges or other financial assistance or any tax credits or other tax advantage provided by the Company or any of its Subsidiaries or any employee benefit plan 14 maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity; or (B) any Person shall become an Acquiring Person, unless the event causing such Person to become an Acquiring Person is a transaction set forth in Section 13(a); or (C) during such time as there is an Acquiring Person, there shall be any reclassification of securities (including any reverse stock split), or recapitalization of the Company, or any merger or consolidation of the Company with any of its Subsidiaries or any other transaction or series of transactions involving the Company or any of its Subsidiaries, other than a transaction or transactions to which the provisions of Section 13(a) apply (whether or not with or into or otherwise involving an Acquiring Person), which has the effect, directly or indirectly, of increasing by more than 1% the proportionate share of the outstanding shares of any class of equity securities of the Company or any of its Subsidiaries that is directly or indirectly beneficially owned by any Acquiring Person or any Associate or Affiliate of any Acquiring Person; then, immediately upon the date of the occurrence of an event described in Section 11(a)(iii)(A), (B) or (C) (a "Section 11(a)(iii) Event"), proper provision shall be made so that each holder of a Right (except as provided below and in Section 7(e)) shall thereafter have the right to receive, upon exercise thereof at the then-current Purchase Price in accordance with the terms of this Agreement, in lieu of the number of Units of Preferred Stock for which a Right was exercisable immediately prior to the first occurrence of a Section 11(a)(iii) Event, such number of Units of Preferred Stock as shall equal the result obtained by (x) multiplying the then-current Purchase Price by the then number of Units of Preferred Stock for which a Right was exercisable immediately prior to the first occurrence of a Section 11(a)(iii) Event (such product thereafter being, for all purposes of this Agreement other than Section 13, the "Purchase Price"), and (y) dividing that product by 50% of the then-current market price (determined pursuant to Section 11(d)) per Unit of Preferred Stock on the date of such first occurrence (such Units of Preferred Stock being the "Adjustment Shares"). (iv) In the event that the number of shares of Preferred Stock that are authorized by the Company's Articles of Incorporation but not outstanding or reserved for issuance for purposes other than upon exercise of the Rights is not sufficient to permit the exercise in full of the Rights in accordance with the foregoing subparagraph (iii) of this Section 11(a), the Company, by the vote of a majority of the Company's Board of Directors, shall: (A) determine the excess of (1) the value of the Adjustment Shares issuable upon the exercise of a Right (the "Current Value") over (2) the Purchase Price (such excess being the "Spread"), and (B) with respect to each Right, make adequate provision to substitute for such Adjustment Shares, upon payment of the applicable Purchase Price, (1) cash, (2) a reduction in the Purchase Price, (3) Company Common Stock or other equity securities of the Company (including, without limitation, shares, or units of shares, of preferred stock (such other shares being "Preferred Stock Equivalents")), (4) debt securities of the Company, (5) other assets or (6) any combination of the foregoing, having an aggregate value equal to the Current Value, where such aggregate value has been determined by a majority of the Company's Board of Directors, after receiving advice from a nationally recognized investment banking firm; provided, however, that if the Company shall not have made adequate provision to deliver value 15 pursuant to clause (B) above within thirty days following the later of (x) the first occurrence of a Section 11(a)(iii) Event and (y) the date on which the Company's right of redemption pursuant to Section 23(a) expires (the later of (x) and (y) being referred to herein as the "Section 11(a)(iv) Trigger Date"), then the Company shall be obligated to deliver, upon the surrender for exercise of a Right and without requiring payment of the Purchase Price, Units of Preferred Stock (to the extent available) and then, if necessary, cash, which Units of Preferred Stock and/or cash shall have an aggregate value equal to the Spread. To the extent that the Company determines that some action need be taken pursuant to the first sentence of this Section 11(a)(iv), the Company shall provide, subject to Section 7(e), that such action shall apply uniformly to all outstanding Rights. For purposes of this Section 11(a)(iv), the value of a Unit of Preferred Stock shall be the current market price (as determined pursuant to Section 11(d)) per Unit of Preferred Stock on the Section 11(a)(iv) Trigger Date and the value of any preferred stock equivalent shall be deemed to have the same value as the Preferred Stock on such date. (b) In case the Company shall fix a record date for the issuance of rights, options or warrants to all holders of Preferred Stock entitling them to subscribe for or purchase (for a period expiring within forty-five calendar days after such record date) shares of Preferred Stock (or shares having substantially the same rights, privileges and preferences as shares of Preferred Stock ("Equivalent Preferred Stock")) or securities convertible into Preferred Stock or Equivalent Preferred Stock at a price per share of Preferred Stock or per share of Equivalent Preferred Stock (or having a conversion price per share, if a security convertible into Preferred Stock or Equivalent Preferred Stock) less than the current market price (as determined pursuant to Section 11(d)) per share of Preferred Stock on such record date, the Purchase Price to be in effect after such record date shall be determined by multiplying the Purchase Price in effect immediately prior to such record date by a fraction, the numerator of which shall be the sum of the number of shares of Preferred Stock outstanding on such record date plus the number of shares of Preferred Stock which the aggregate offering price of the total number of shares of Preferred Stock and/or Equivalent Preferred Stock so to be offered (and/or the aggregate initial conversion price of the convertible securities so to be offered) would purchase at such current market price, and the denominator of which shall be the number of shares of Preferred Stock outstanding on such record date plus the number of additional shares of Preferred Stock and/or Equivalent Preferred Stock to be offered for subscription or purchase (or into which the convertible securities so to be offered are initially convertible). In case such subscription price may be paid by delivery of consideration part or all of which may be in a form other than cash, the value of such consideration shall be as determined in good faith by a majority of the Company's Board of Directors, whose determination shall be described in a statement filed with the Rights Agent and shall be binding on the Rights Agent and the holders of the Rights. Shares of Preferred Stock owned by or held for the account of the Company or any Subsidiary shall not be deemed outstanding for the purpose of any such computation. Such adjustment shall be made successively whenever such a record date is fixed, and in the event that such rights or warrants are not so issued, the Purchase Price shall be adjusted to be the Purchase Price that would then be in effect if such record date had not been fixed. (c) In case the Company shall fix a record date for a distribution to all holders of shares of Preferred Stock (including any such distribution made in connection with a consolidation or merger in which the Company is the continuing corporation) of evidences of indebtedness, cash (other than a regular quarterly cash dividend out of the earnings or retained 16 earnings of the Company), assets (other than a dividend payable in shares of Preferred Stock, but including any dividend payable in stock other than Preferred Stock) or subscription rights or warrants (excluding those referred to in Section 11(b)), the Purchase Price to be in effect after such record date shall be determined by multiplying the Purchase Price in effect immediately prior to such record date by a fraction, the numerator of which shall be the current market price (as determined pursuant to Section 11(d)) per share of Preferred Stock on such record date less the fair market value (as determined in good faith by a majority of the Company's Board of Directors, whose determination shall be described in a statement filed with the Rights Agent and shall be binding on the Rights Agent and the holder of the Rights) of the cash, assets or evidences of indebtedness so to be distributed or of such subscription rights or warrants distributable in respect of a share of Preferred Stock and the denominator of which shall be such current market price (as determined pursuant to Section 11(d)) per share of Preferred Stock. Such adjustments shall be made successively whenever such a record date is fixed, and in the event that such distribution is not so made, the Purchase Price shall be adjusted to be the Purchase Price that would have been in effect if such record date had not been fixed. (d) (i) For the purpose of any computation hereunder, the "current market price" per share of Company Common Stock or Common Stock on any date shall be deemed to be the average of the daily closing prices per share of such shares for the ten consecutive Trading Days immediately prior to, but not including, such date; provided, however, if prior to the expiration of such requisite ten Trading Day period the issuer announces either (A) a dividend or distribution on such shares payable in such shares or securities convertible into such shares (other than the Rights) or (B) any subdivision, combination or reclassification of such shares, then, following the ex-dividend date for such dividend or the record date for such subdivision, as the case may be, the "current market price" shall be properly adjusted to take into account such event. The closing price for each day shall be, if the shares are listed and admitted to trading on a national securities exchange, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal national securities exchange on which such shares are listed or admitted to trading or, if such shares are not listed or admitted to trading on any national securities exchange, the last quoted price or, if not so quoted, the average of the high bid and low asked prices in the over-the-counter market, as reported by The Nasdaq Stock Market Consolidated Quotations Service or such other system then in use, or, if on any such date such shares are not quoted by any such organization, the average of the closing bid and asked prices as furnished by a professional market maker making a market in such shares selected by a majority of the Company's Board of Directors. If, on any such date no market maker is making a market in such shares, the fair value of such shares on such date as determined in good faith by a majority of the Company's Board of Directors shall be used. If such shares are not publicly held or not so listed or traded, "current market price" per share shall mean the fair value per share as determined in good faith by a majority of the Company's Board of Directors, whose determination shall be described in a statement filed with the Rights Agent and shall be conclusive for all purposes. The term "Trading Day" shall mean, if such shares are listed or admitted to trading on any national securities exchange, a day on which the principal national securities exchange on which such shares are listed or admitted to trading is open for the transaction of business or, if such shares are not so listed or admitted, a Business Day. (ii) For the purpose of any computation hereunder, the "current market price" per share of Preferred Stock shall be determined in the same manner as set forth above for 17 Company Common Stock in clause (i) of this Section 11(d) (other than the fourth sentence thereof). If the current market price per share of Preferred Stock cannot be determined in the manner provided above or if the Preferred Stock is not publicly held or listed or traded in a manner described in clause (i) of this Section 11(d), the "current market price" per share of Preferred Stock shall be conclusively deemed to be an amount equal to 100 (as such amount may be appropriately adjusted for such events as stock splits, stock dividends and recapitalizations with respect to Company Common Stock occurring after the date of this Agreement) multiplied by the current market price per share of Company Common Stock. If neither Company Common Stock nor Preferred Stock is publicly held or so listed or traded, "current market price" per share of the Preferred Stock shall mean the fair value per share as determined in good faith by a majority of the Company's Board of Directors, whose determination shall be described in a statement filed with the Rights Agent and shall be binding on the Rights Agent and the holders of the Rights. For all purposes of this Agreement, the "current market price" of a Unit of Preferred Stock shall be equal to the "current market price" of one share of Preferred Stock divided by 100. (e) Anything herein to the contrary notwithstanding, no adjustment in the Purchase Price shall be required unless such adjustment would require an increase or decrease of at least 1% in the Purchase Price; provided, however, that any adjustments which by reason of this Section 11(e) are not required to be made shall be carried forward and taken into account in any subsequent adjustment. All calculations under this Section 11 shall be made to the nearest cent or to the nearest one-hundredth of a share of Company Common Stock or Common Stock or other share or ten-thousandth of a share of Preferred Stock, as the case may be. Notwithstanding the first sentence of this Section 11(e), any adjustment required by this Section 11 shall be made no later than the earlier of (i) three years from the date of the transaction that mandates such adjustment and (ii) the Expiration Date. (f) If, as a result of an adjustment made pursuant to Section 11(a)(iii) or 13(a), the holder of any Right thereafter exercised shall become entitled to receive any shares of capital stock other than Preferred Stock, thereafter the number of such other shares so receivable upon exercise of any Right and the Purchase Price thereof shall be subject to adjustment from time to time in a manner and on terms as nearly equivalent as practicable to the provisions with respect to the Preferred Stock contained in Sections 11(a), (b), (c), (d), (e), (g), (h), (i), (j), (k), (l) and (m), and the provisions of Sections 7, 9, 10, 13 and 14 with respect to the Preferred Stock shall apply on like terms to any such other shares. (g) All Rights originally issued by the Company subsequent to any adjustment made to the Purchase Price hereunder shall evidence the right to purchase, at the adjusted Purchase Price, the number of Units of Preferred Stock (or other securities or amount of cash or combination thereof) that may be acquired from time to time hereunder upon exercise of the Rights, all subject to further adjustment as provided herein. (h) Unless the Company shall have exercised its election as provided in Section 11(i), upon each adjustment of the Purchase Price as a result of the calculations made in Sections 11(b) and (c), each Right outstanding immediately prior to the making of such adjustment shall thereafter evidence the right to purchase, at the adjusted Purchase Price, that number of Units of Preferred Stock (calculated to the nearest one ten-thousandth of a Unit) 18 obtained by (i) multiplying (x) the number of Units of Preferred Stock covered by a Right immediately prior to this adjustment by (y) the Purchase Price in effect immediately prior to such adjustment of the Purchase Price and (ii) dividing the product so obtained by the Purchase Price in effect immediately after such adjustment of the Purchase Price. (i) The Company may elect on or after the date of any adjustment of the Purchase Price to adjust the number of Rights, in lieu of any adjustment in the number of Units of Preferred Stock that may be acquired upon the exercise of a Right. Each of the Rights outstanding after the adjustment in the number of Rights shall be exercisable for the number of Units of Preferred Stock for which a Right was exercisable immediately prior to such adjustment. Each Right held of record prior to such adjustment of the number of Rights shall become that number of Rights (calculated to the nearest ten-thousandth) obtained by dividing the Purchase Price in effect immediately prior to adjustment of the Purchase Price by the Purchase Price in effect immediately after adjustment of the Purchase Price. The Company shall make a public announcement (with prompt written notice thereof to the Rights Agent) of its election to adjust the number of Rights, indicating the record date for the adjustment, and, if known at the time, the amount of the adjustment to be made. This record date may be the date on which the Purchase Price is adjusted or any day thereafter, but, if the Rights Certificates have been issued, shall be at least ten days later than the date of such public announcement. If Rights Certificates have been issued, upon each adjustment of the number of Rights pursuant to this Section 11(i), the Company shall, as promptly as practicable, cause to be distributed to holders of record of Rights Certificates on such record date Rights Certificates evidencing, subject to Section 14, the additional Rights to which such holders shall be entitled as a result of such adjustment, or, at the option of the Company, shall cause to be distributed to such holders of record in substitution and replacement for the Rights Certificates held by such holders prior to the date of adjustment, and upon surrender thereof, if required by the Company, new Rights Certificates evidencing all the Rights to which such holders shall be entitled after such adjustment. Rights Certificates to be so distributed shall be issued, executed and countersigned in the manner provided for herein (and may bear, at the option of the Company, the adjusted Purchase Price) and shall be registered in the names of the holders of record of Rights Certificates on the record date specified in the public announcement. (j) Irrespective of any adjustment or change in the Purchase Price or the number of Units of Preferred Stock issuable upon the exercise of the Rights, the Rights Certificates theretofore and thereafter issued may continue to express the Purchase Price per Unit and the number of Units of Preferred Stock that were expressed in the Initial Rights Certificates issued hereunder without prejudice to any such adjustment or change. (k) Before taking any action that would cause an adjustment reducing the Purchase Price below the then-par value of the number of Units of Preferred Stock issuable upon exercise of the Rights, the Company shall take any corporate action that may, in the opinion of its counsel, be necessary in order that the Company may validly and legally issue such fully paid and non-assessable number of Units of Preferred Stock at such adjusted Purchase Price. (l) In any case in which this Section 11 shall require that an adjustment in the Purchase Price be made effective as of a record date for a specified event, the Company may elect to defer (and shall promptly notify the Rights Agent of any such election) until the 19 occurrence of such event the issuance to the holder of any Right exercised after such record date of that number of Units of Preferred Stock and shares of other capital stock or securities of the Company, if any, issuable upon such exercise over and above the number of Units of Preferred Stock and shares of other capital stock or securities of the Company, if any, issuable upon such exercise on the basis of the Purchase Price in effect prior to such adjustment; provided, however, that the Company shall deliver to such holder a due bill or other appropriate instrument evidencing such holder's right to receive such additional shares (fractional or otherwise) or securities upon the occurrence of the event requiring such adjustment. (m) Anything in this Section 11 to the contrary notwithstanding, the Company shall be entitled to make such reductions in the Purchase Price, in addition to those adjustments expressly required by this Section 11, as and to the extent that in their good faith judgment a majority of the Company's Board of Directors shall determine to be advisable in order that any (i) consolidation or subdivision of the Preferred Stock, (ii) issuance wholly for cash of any shares of Preferred Stock at less than the current market price, (iii) issuance wholly for cash or shares of Preferred Stock or securities that by their terms are convertible into or exchangeable for shares of Preferred Stock, (iv) stock dividends or (v) issuance of rights, options or warrants referred to in this Section 11, hereafter made by the Company to holders of its Preferred Stock, shall not be taxable to such holders or shall reduce the taxes payable by such holders. (n) The Company shall not, at any time after the Distribution Date, (i) consolidate with any other Person (other than a Subsidiary of the Company in a transaction that complies with Section 11(o)), (ii) merge with or into any other Person (other than a Subsidiary of the Company in a transaction that complies with Section 11(o)), or (iii) sell or transfer (or permit any Subsidiary to sell or transfer), in one transaction, or a series of transactions, assets or earning power aggregating more than 50% of the assets or earning power of the Company and its Subsidiaries (taken as a whole) to any other Person or Persons (other than the Company and/or any of its Subsidiaries in one or more transactions each of which complies with Section 11(o) and other than in connection with any public offering of the capital stock of any of the Company's subsidiaries or any spin-off or other similar transaction), if (x) at the time of or immediately after such consolidation, merger or sale there are any rights, warrants or other instruments or securities outstanding or agreements in effect that would substantially diminish or otherwise eliminate the benefits intended to be afforded by the Rights or (y) prior to, simultaneously with or immediately after such consolidation, merger or sale, the Person that constitutes, or would constitute, the "Principal Party" for purposes of Section 13(a) shall have distributed or otherwise transferred to its shareholders or other Persons holding an equity interest in such Person Rights previously owned by such Person or any of its Affiliates and Associates; provided, however, that this Section 11(n) shall not affect the ability of any Subsidiary of the Company to consolidate with, merge with or into, or sell or transfer assets or earning power to, any other Subsidiary of the Company. (o) After the Distribution Date, the Company shall not, except as permitted by Section 23 or Section 26, take (or permit any Subsidiary to take) any action if at the time such action is taken it is reasonably foreseeable that such action will diminish substantially or otherwise eliminate the benefits intended to be afforded by the Rights. 20 (p) Anything in this Agreement to the contrary notwithstanding, in the event that the Company shall at any time after the Rights Dividend Declaration Date and prior to the Distribution Date (i) declare a dividend on the outstanding shares of Company Common Stock payable in shares of Company Common Stock, (ii) subdivide the outstanding shares of Company Common Stock, (iii) combine the outstanding shares of Company Common Stock into a smaller number of shares, or (iv) issue any shares of its capital stock in a reclassification of Company Common Stock (including any such reclassification in connection with a consolidation or merger in which the Company is the continuing or surviving corporation), the number of Rights associated with each share of Company Common Stock then outstanding, or issued or delivered thereafter but prior to the Distribution Date, shall be proportionately adjusted so that the number of Rights thereafter associated with each share of Company Common Stock following any such event shall equal the result obtained by multiplying the number of Rights associated with each share of Company Common Stock immediately prior to such event by a fraction the numerator of which shall be the total number of shares of Company Common Stock outstanding immediately prior to the occurrence of the event and the denominator of which shall be the total number of shares of Company Common Stock outstanding immediately following the occurrence of such event. SECTION 12. Certificate of Adjusted Purchase Price or Number of Shares. Whenever an adjustment is made as provided in Section 11 or Section 13, the Company shall (a) promptly prepare a certificate setting forth such adjustment and a brief statement of the facts and computations accounting for such adjustment, (b) promptly file with the Rights Agent, and with each transfer agent for the Preferred Stock and the Company Common Stock, a copy of such certificate, and (c) mail a brief summary thereof to each holder of a Rights Certificate (or, if prior to the Distribution Date, to each holder of a certificate evidencing shares of Company Common Stock) in accordance with Section 25. The Rights Agent shall be fully protected in relying on any such certificate and on any adjustment therein contained, and shall have no duty with respect to and shall not be deemed to have knowledge of any such adjustment unless and until it shall have received such certificate. SECTION 13. Consolidation, Merger or Sale or Transfer of Assets or Earning Power. (a) In the event that, following the Stock Acquisition Date, directly or indirectly, either (x) the Company shall consolidate with, or merge with and into, any other Person (other than a Subsidiary of the Company in a transaction that complies with Section 11(o)), and the Company shall not be the continuing or surviving corporation of such consolidation or merger, (y) any Person (other than a Subsidiary of the Company in a transaction that complies with Section 11(o)) shall consolidate with, or merge with or into, the Company, and the Company shall be the continuing or surviving corporation of such consolidation or merger and, in connection with such consolidation or merger, all or part of the outstanding shares of Company Common Stock shall be converted into or exchanged for stock or other securities of any other Person or cash or any other property, or (z) the Company shall sell or otherwise transfer (or one or more of its Subsidiaries shall sell or otherwise transfer) to any Person or Persons (other than the Company or any of its Subsidiaries in one or more transactions each of which complies with Section 11(o) and other than in connection with any public offering of the capital stock of any of the Company's subsidiaries or any spin-off or other similar transaction), in one or more transactions, assets or earning power aggregating more than 50% of the assets or earning power of the Company and its Subsidiaries, taken as a whole (any such event described in clause (x), 21 (y) or (z) being a "Section 13 Event"), then, and in each such case, proper provision shall be made so that: (i) each holder of a Right, except as provided in Section 7(e), shall thereafter have the right to receive, upon the exercise thereof at the then-current Purchase Price, such number of validly authorized and issued, fully paid and non-assessable shares of Common Stock of the Principal Party, which shares shall not be subject to any liens, encumbrances, rights of first refusal, transfer restrictions or other adverse claims, as shall be equal to the result obtained by (1) multiplying the then-current Purchase Price by the number of Units of Preferred Stock for which a Right is exercisable immediately prior to the first occurrence of a Section 13 Event (or, if a Section 11(a)(iii) Event has occurred prior to the first occurrence of a Section 13 Event, multiplying the number of such Units for which a Right would be exercisable hereunder but for the occurrence of such Section 11(a)(iii) Event by the Purchase Price that would be in effect hereunder but for such first occurrence) and (2) dividing that product (which, following the first occurrence of a Section 13 Event, shall be the "Purchase Price" for all purposes of this Agreement) by 50% of the current market price (determined pursuant to Section 11(d)) per share of the Common Stock of such Principal Party on the date of consummation of such Section 13 Event; (ii) such Principal Party shall thereafter be liable for, and shall assume, by virtue of such Section 13 Event, all the obligations and duties of the Company pursuant to this Agreement; (iii) the term "Company" shall, for all purposes of this Agreement, thereafter be deemed to refer to such Principal Party, it being specifically intended that the provisions of Section 11 shall apply only to such Principal Party following the first occurrence of a Section 13 Event; (iv) such Principal Party shall take such steps (including, but not limited to, the reservation of a sufficient number of shares of its Common Stock) in connection with the consummation of any such transaction as may be necessary to ensure that the provisions of this Agreement shall thereafter be applicable to its shares of Common Stock thereafter deliverable upon the exercise of the Rights; and (v) the provisions of Section 11(a)(iii) shall be of no further effect following the first occurrence of any Section 13 Event. (b) "Principal Party" shall mean: (i) in the case of any transaction described in clause (x) or (y) of the first sentence of Section 13(a), (A) the Person that is the issuer of any securities into which shares of Company Common Stock are converted in such merger or consolidation, or, if there is more than one such issuer, the issuer of Common Stock that has the highest aggregate current market price (determined pursuant to Section 11(d)) and (B) if no securities are so issued, the Person that is the other party to such merger or consolidation, or, if there is more than one such Person, the Person the Common Stock of which has the highest aggregate current market price (determined pursuant to Section 11(d)); and (ii) in the case of any transaction described in clause (z) of the first sentence of Section 13(a), the Person that is the party receiving the largest portion of the assets or earning power transferred pursuant to such transaction or transactions, or, if each Person that is a party to such transaction or transactions receives the same portion of the assets or earning power transferred pursuant to such transaction or transactions or if the Person receiving the largest portion of the assets or earning power cannot be determined, whichever Person the Common Stock of which has the highest aggregate current market price (determined pursuant to Section 11(d)); provided, however, that in any such case, (1) if the Common Stock of such Person is not at such time and has not been 22 continuously over the preceding twelve-month period registered under Section 12 of the Exchange Act ("Registered Common Stock"), or such Person is not a corporation, and such Person is a direct or indirect Subsidiary of another Person that has Registered Common Stock outstanding, "Principal Party" shall refer to such other Person; (2) if the Common Stock of such Person is not Registered Common Stock or such Person is not a corporation, and such Person is a direct or indirect Subsidiary of another Person but is not a direct or indirect Subsidiary of another Person that has Registered Common Stock outstanding, "Principal Party" shall refer to the ultimate parent entity of such first-mentioned Person; (3) if the Common Stock of such Person is not Registered Common Stock or such Person is not a corporation, and such Person is directly or indirectly controlled by more than one Person, and one or more of such other Persons has Registered Common Stock outstanding, "Principal Party" shall refer to whichever of such other Persons is the issuer of the Registered Common Stock having the highest aggregate current market price (determined pursuant to Section 11(d)); and (4) if the Common Stock of such Person is not Registered Common Stock or such Person is not a corporation, and such Person is directly or indirectly controlled by more than one Person, and none of such other Persons have Registered Common Stock outstanding, "Principal Party" shall refer to whichever ultimate parent entity is the corporation having the greatest shareholders' equity or, if no such ultimate parent entity is a corporation, shall refer to whichever ultimate parent entity is the entity having the greatest net assets. (c) The Company shall not consummate any such consolidation, merger, sale or transfer unless the Principal Party shall have a sufficient number of authorized shares of its Common Stock that have not been issued or reserved for issuance to permit the exercise in full of the Rights in accordance with this Section 13, and unless prior thereto the Company and such Principal Party shall have executed and delivered to the Rights Agent a supplemental agreement providing for the terms set forth in paragraphs (a) and (b) of this Section 13 and further providing that the Principal Party will: (i) (A) file on an appropriate form, as soon as practicable following the execution of such agreement, a registration statement under the Securities Act with respect to the Common Stock that may be acquired upon exercise of the Rights, (B) cause such registration statement to remain effective (and to include a prospectus complying with the requirements of the Securities Act) until the Expiration Date, and (C) as soon as practicable following the execution of such agreement take such action as may be required to ensure that any acquisition of such Common Stock upon the exercise of the Rights complies with any applicable state securities or "blue sky" laws; and (ii) deliver to holders of the Rights historical financial statements for the Principal Party and each of its Affiliates that comply in all respects with the requirements for registration on Form 10 under the Exchange Act. (d) In case the Principal Party that is to be a party to a transaction referred to in this Section 13 has a provision in any of its authorized securities or in its Articles of Incorporation or By-laws or other instrument governing its corporate affairs, which provision would have the effect of (i) causing such Principal Party to issue, in connection with, or as a consequence of, the consummation of a transaction referred to in this Section 13, shares of 23 Common Stock of such Principal Party at less than the then-current market price per share (determined pursuant to Section 11(d)) or securities exercisable for, or convertible into, Common Stock of such Principal Party at less than such then-current market price (other than to holders of Rights pursuant to this Section 13) or (ii) providing for any special payment, tax or similar provisions in connection with the issuance of the Common Stock of such Principal Party pursuant to the provisions of this Section 13, then, in such event, the Company shall not consummate any such transaction unless prior thereto the Company and such Principal Party shall have executed and delivered to the Rights Agent a supplemental agreement providing that the provision in question of such Principal Party shall have been cancelled, waived or amended, or that the authorized securities shall be redeemed, so that the applicable provision will have no effect in connection with, or as a consequence of, the consummation of the proposed transaction. (e) The provisions of this Section 13 shall similarly apply to successive mergers or consolidations or sales or other transfers. In the event that a Section 13 Event shall occur at any time after the occurrence of a Section 11(a)(iii) Event, the Rights that have not theretofore been exercised shall thereafter become exercisable in the manner described in Section 13(a). SECTION 14. Fractional Rights and Fractional Shares. (a) The Company shall not be required to issue fractions of Rights or to distribute Rights Certificates that evidence fractional Rights. In lieu of such fractional Rights, there shall be paid to the Persons to which such fractional Rights would otherwise be issuable, an amount in cash equal to such fraction of the market value of a whole Right. For purposes of this Section 14(a), the market value of a whole Right shall be the closing price of the Rights for the Trading Day immediately prior to the date on which such fractional Rights would have been otherwise issuable. The closing price of the Rights for any day shall be, if the Rights are listed or admitted to trading on a national securities exchange, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal national securities exchange on which the Rights are listed or admitted to trading or, if the Rights are not listed or admitted to trading on any national securities exchange, the last quoted price or, if not so quoted, the average of the high bid and low asked prices in the over-the-counter market, as reported by The Nasdaq Stock Market Consolidated Quotations Service or such other system then in use or, if on any such date the Rights are not quoted by any such organization, the average of the closing bid and asked prices as furnished by a professional market maker making a market in the Rights selected by a majority of the Company's Board of Directors. If on any such date no such market maker is making a market in the Rights, the fair value of the Rights on such date as determined in good faith by a majority of the Company's Board of Directors shall be used and such determination shall be described in a statement filed with the Rights Agent and shall be conclusive for all purposes. (b) The Company shall not be required to issue fractions of shares of Preferred Stock (other than fractions that are integral multiples of one one- hundredth of a share of Preferred Stock) upon exercise of the Rights or to distribute certificates that evidence such fractional shares of Preferred Stock (other than fractions that are integral multiples of one one-hundredth of a share of Preferred Stock). In lieu of such fractional shares of Preferred Stock that are not integral multiples of one one-hundredth of a share, the Company may pay to the registered holders of Rights Certificates at the time such Rights are exercised as herein provided 24 an amount in cash equal to the same fraction of the then-current market price of a share of Preferred Stock on the day of exercise, determined in accordance with Section 11(d). (c) The holder of a Right by the acceptance of such Right expressly waives his right to receive any fractional Rights or any fractional shares upon exercise of a Right, except as permitted by this Section 14. (d) Whenever a payment for fractional Rights or fractional shares is to be made by the Rights Agent, the Company shall (i) promptly prepare and deliver to the Rights Agent a certificate setting forth the prices and/or formulas utilized in calculating such payments, and (ii) provide sufficient monies to the Rights Agent in the form of fully collected funds to make such payments. The Rights Agent shall be fully protected in relying upon such a certificate and shall have no duty with respect to, and shall not be deemed to have knowledge of any payment for fractional Rights or fractional shares under any Section of this Agreement relating to the payment of fractional Rights or fractional shares unless and until the Rights Agent shall have received such a certificate and sufficient monies. SECTION 15. Rights of Action. All rights of action in respect of this Agreement, other than rights of action vested in the Rights Agent pursuant to Section 18 and Section 20 hereof, are vested in the respective registered holders of the Rights Certificates (and, prior to the Distribution Date, the registered holders of certificates evidencing shares of Company Common Stock); and any registered holder of a Rights Certificate (or, prior to the Distribution Date, of a certificate evidencing shares of Company Common Stock), without the consent of the Rights Agent or of the holder of any other Rights Certificate (or, prior to the Distribution Date, of a certificate evidencing shares of Company Common Stock), may, on such registered holder's own behalf and for such registered holder's own benefit, enforce, and may institute and maintain any suit, action or proceeding against the Company or any other Person to enforce, or otherwise act in respect of, such registered holder's right to exercise the Rights evidenced by such Rights Certificate in the manner provided in such Rights Certificate and in this Agreement. Without limiting the foregoing or any remedies available to the holders of Rights, it is specifically acknowledged that the holders of Rights would not have an adequate remedy at law for any breach of this Agreement and shall be entitled to specific performance of the obligations hereunder and injunctive relief against actual or threatened violations of the obligations hereunder of any Person subject to this Agreement. SECTION 16. Agreement of Rights Holders. Every holder of a Right by accepting the same consents and agrees with the Company and the Rights Agent and with every other holder of a Right that: (a) prior to the Distribution Date, the Rights will be transferable only in connection with the transfer of Company Common Stock; (b) after the Distribution Date, the Rights Certificates are transferable only on the registry books of the Rights Agent if surrendered at the office of the Rights Agent designated for such purposes, duly endorsed or accompanied by a proper instrument of transfer and with the appropriate forms and certificates duly executed; 25 (c) subject to Section 6(a) and Section 7(f), the Company and the Rights Agent may deem and treat the Person in whose name a Rights Certificate (or, prior to the Distribution Date, the associated Company Common Stock certificate) is registered as the absolute owner thereof and of the Rights evidenced thereby (notwithstanding any notations of ownership or writing on the Rights Certificates or the associated Company Common Stock certificate made by anyone other than the Company or the Rights Agent) for all purposes whatsoever, and neither the Company nor the Rights Agent, subject to the last sentence of Section 7(e), shall be affected by any notice to the contrary; and (d) notwithstanding anything in this Agreement to the contrary, neither the Company nor the Rights Agent shall have any liability to any holder of a Right or any other Person as a result of its inability to perform any of its obligations under this Agreement by reason of any preliminary or permanent injunction or other order, decree, judgment or ruling (whether interlocutory or final) issued by a court of competent jurisdiction or by a governmental, regulatory or administrative agency or commission, or any statute, rule, regulation or executive order promulgated or enacted by any governmental authority, prohibiting or otherwise restraining performance of such obligation; provided, however, the Company must use its best efforts to have any such order, decree, judgment or ruling lifted or otherwise overturned as promptly as practicable. SECTION 17. Rights Certificate Holder Not Deemed a Shareholder. No holder, as such, of any Rights Certificate shall be entitled to vote, receive dividends or be deemed for any purpose the holder of the number of shares of Preferred Stock or any other securities of the Company that may at any time be issuable on the exercise of the Rights evidenced thereby, nor shall anything contained herein or in any Rights Certificate be construed to confer upon the holder of any Rights Certificate, as such, any of the rights of a shareholder of the Company or any right to vote for the election of directors or upon any matter submitted to shareholders at any meeting thereof, or to give or withhold consent to any corporate action, or, except as provided in Section 24, to receive notice of meetings or other actions affecting shareholders, or to receive dividends or subscription rights, or otherwise. SECTION 18. Concerning the Rights Agent. (a) The Company agrees to pay to the Rights Agent reasonable compensation for all services rendered by it hereunder and, from time to time, on demand of the Rights Agent, its reasonable expenses, including reasonable fees and disbursements of its counsel, incurred in connection with the preparation, delivery, execution, administration and amendment of this Agreement and the exercise and performance of its duties hereunder. The Company shall indemnify the Rights Agent for, and hold it harmless against, any loss, liability, damage, judgment, fine, penalty, claim, demand, settlement, cost or expense, incurred without gross negligence, bad faith or willful misconduct (each as finally determined by a court of competent jurisdiction) on the part of the Rights Agent, for any action taken, suffered or omitted by the Rights Agent in connection with the acceptance and administration of this Agreement or the exercise and performance of its duties hereunder, including, without limitation, the costs and expenses of defending against any claim of liability hereunder. The indemnity provided herein shall survive the termination of this Agreement, the termination and the expiration of the Rights, and the resignation or removal of the Rights Agent. The costs and expenses incurred in enforcing this right of indemnification shall be paid by the Company. 26 (b) The Rights Agent shall be protected and shall incur no liability for or in respect of any action taken, suffered or omitted by it in connection with the acceptance and administration of this Agreement in reliance upon any Rights Certificate or certificate or depositary receipt for Preferred Stock or for other securities of the Company, instrument of assignment or transfer, power of attorney, endorsement, affidavit, letter, notice, direction, consent, certificate, statement or other paper or document believed by it to be genuine and to have been signed, executed and, where necessary, verified or acknowledged by the proper Person or Persons. The Rights Agent shall not be deemed to have any duty or notice unless and until the Company has provided the Rights Agent with written notice. SECTION 19. Merger or Consolidation or Change of Name of Rights Agent. (a) Any Person into which the Rights Agent or any successor Rights Agent may be merged or with which it may be consolidated, or any Person resulting from any merger or consolidation to which the Rights Agent or any successor Rights Agent shall be a party, or any Person succeeding to the corporate trust or shareholder services business of the Rights Agent or any successor Rights Agent, shall be the successor to the Rights Agent under this Agreement without the execution or filing of any document or any further act on the part of any of the parties hereto; provided that such Person would be eligible for appointment as a successor Rights Agent under the provisions of Section 21. In case at the time such successor Rights Agent shall succeed to the agency created by this Agreement, any of the Rights Certificates shall have been countersigned but not delivered, any such successor Rights Agent may adopt the countersignature of a predecessor Rights Agent and deliver such Rights Certificates so countersigned; and in case at that time any of the Rights Certificates shall not have been countersigned, any successor Rights Agent may countersign such Rights Certificates either in the name of the predecessor or in the name of the successor Rights Agent; and in all such cases such Rights Certificates shall have the full force provided in the Rights Certificates and in this Agreement. (b) In case at any time the name of the Rights Agent shall be changed and at such time any of the Rights Certificates shall have been countersigned but not delivered, the Rights Agent may adopt the countersignature under its prior name and deliver Rights Certificates so countersigned; and in case at that time any of the Rights Certificates shall not have been countersigned, the Rights Agent may countersign such Rights Certificates either in its prior name or in its changed name; and in all such cases such Rights Certificates shall have the full force provided in the Rights Certificates and in this Agreement. SECTION 20. Duties of Rights Agent. The Rights Agent only undertakes the duties and obligations expressly imposed by this Agreement (and no implied duties or obligations) upon the following terms and conditions, by all of which the Company and the holders of Rights Certificates, by their acceptance thereof, shall be bound: (a) The Rights Agent may consult with legal counsel (who may be legal counsel for the Company), and the advice or opinion of such counsel shall be full and complete authorization and protection to the Rights Agent, and the Rights Agent shall incur no liability for or in respect of any action taken, suffered or omitted by it in good faith and in accordance with such advice or opinion. 27 (b) Whenever in the performance of its duties under this Agreement the Rights Agent shall deem it necessary or desirable that any fact or matter (including, without limitation, the identity of any Acquiring Person and the determination of "current market price") be proved or established by the Company prior to taking, suffering or omitting any action hereunder, such fact or matter (unless other evidence in respect thereof be specified herein) may be deemed to be conclusively proved and established by a certificate signed by the Chairman of the Board, the President, any Vice President, the Treasurer, any Assistant Treasurer, the Secretary or any Assistant Secretary of the Company and delivered to the Rights Agent and such certificate shall be full authorization and protection to the Rights Agent, and the Rights Agent shall incur no liability for or in respect of any action taken, suffered or omitted by it under the provisions of this Agreement in reliance upon such certificate. (c) The Rights Agent shall be liable hereunder only for its own gross negligence, bad faith or willful misconduct (each as finally determined by a court of competent jurisdiction). Anything in this Agreement to the contrary notwithstanding, in no event shall the Rights Agent be liable for special, indirect, incidental or consequential loss or damage of any kind whatsoever (including, without limitation, loss profits), even if the Rights Agent has been advised of the possibility of such loss or damage. (d) The Rights Agent shall not be liable for or by reason of any of the statements of fact or recitals contained in this Agreement or in the Rights Certificates or be required to verify the same (except as to its countersignature on such Rights Certificates), but all such statements and recitals are and shall be deemed to have been made by the Company only. (e) The Rights Agent shall not have any liability for or be under any responsibility for the validity of this Agreement or the execution and delivery hereof (except the due execution and delivery hereof by the Rights Agent) or for the validity or execution of any Rights Certificate (except its countersignature thereof); nor shall it be responsible for any breach by the Company of any covenant or failure by the Company to satisfy conditions contained in this Agreement or in any Rights Certificate; nor shall it be responsible for any adjustment required under the provisions of Section 11 or Section 13 or for the manner, method or amount of any such adjustment or the ascertaining of the existence of facts that would require any such adjustment (except with respect to the exercise of Rights evidenced by Rights Certificates after receipt by the Rights Agent of the certificate describing any such adjustment contemplated by Section 12); nor shall it by any act hereunder be deemed to make any representation or warranty as to the authorization or reservation of any shares of Preferred Stock or any other securities to be issued pursuant to this Agreement or any Rights Certificate or as to whether any shares of Preferred Stock or any other securities will, when so issued, be validly authorized and issued, fully paid and non- assessable. (f) The Company shall perform, execute, acknowledge and deliver or cause to be performed, executed, acknowledged and delivered all such further acts, instruments and assurances as may reasonably be required by the Rights Agent for the performance by the Rights Agent of its duties under this Agreement. 28 (g) The Rights Agent is hereby authorized and directed to accept instructions with respect to the performance of its duties hereunder from the Chairman of the Board, the President, any Vice President, the Secretary, any Assistant Secretary, the Treasurer or any Assistant Treasurer of the Company, and to apply to such officers for advice or instructions in connection with its duties, and such instructions shall be full authorization and protection to the Rights Agent, and the Rights Agent shall incur no liability for or in respect of any action taken, suffered or omitted to be taken by it in good faith in accordance with the advice or instructions of any such officer. The Rights Agent shall be fully protected and authorized in relying upon the most recent instructions received by any such officer. Any application by the Rights Agent for written instructions from the Company may, at the option of the Rights Agent, set forth in writing any action proposed to be taken, suffered or omitted by the Rights Agent under this Rights Agreement and the date on and/or after which such action shall be taken, suffered or such omission shall be effective. The Rights Agent shall not be liable for any action taken or suffered by, or omission of, the Rights Agent in accordance with a proposal included in any such application on or after the date specified in such application (which date shall not be less than five Business Days after the date any such officer of the Company actually receives such application, unless any such officer shall have consented in writing to an earlier date) unless, prior to taking or suffering any such action (or the effective date in the case of an omission), the Rights Agent shall have received written instructions in response to such application specifying the action to be taken, suffered or omitted. (h) The Rights Agent and any shareholder, affiliate, director, officer or employee of the Rights Agent may buy, sell or deal in any of the Rights or other securities of the Company or become pecuniarily interested in any transaction in which the Company may be interested, or contract with or lend money to the Company or otherwise act as fully and freely as though it were not Rights Agent under this Agreement. Nothing herein shall preclude the Rights Agent from acting in any other capacity for the Company or for any other Person. (i) The Rights Agent may execute and exercise any of the rights or powers hereby vested in it or perform any duty hereunder either itself or by or through its attorneys or agents, and the Rights Agent shall not be answerable or accountable for any act, default, neglect, or misconduct of any such attorneys or agents or for any loss to the Company or any other Person resulting from any such act, default, neglect or misconduct, absent gross negligence, bad faith or willful misconduct (each as finally determined by a court of competent jurisdiction) in the selection and continued employment thereof. (j) No provision of this Agreement shall require the Rights Agent to expend or risk its own funds or otherwise incur any financial liability in the performance of any of its duties or in the exercise of its rights hereunder if the Rights Agent shall have reasonable grounds for believing that repayment of such funds or adequate indemnification against such risk or liability is not reasonably assured to it. (k) If, with respect to any Rights Certificate surrendered to the Rights Agent for exercise or transfer, the certificate attached to the form of assignment or form of election to purchase, as the case may be, has either not been properly completed, not 29 signed or indicates an affirmative response to clause 1 and/or 2 thereof, the Rights Agent shall not take any further action with respect to such requested exercise or transfer without first consulting with the Company. If such certificate has been properly completed and signed and shows a negative response to clauses 1 and 2 of such certificate, unless previously instructed otherwise in writing by the Company, the Rights Agent may assume without further inquiry that the Rights Certificate is not owned by a Person described in Section 4(b) or Section 7(e) and shall not be charged with any knowledge to the contrary. SECTION 21. Change of Rights Agent. The Rights Agent or any successor Rights Agent may resign and be discharged from its duties under this Agreement upon thirty days' prior notice in writing mailed to the Company, and to each transfer agent of the Preferred Stock and the Company Common Stock, by registered or certified mail, and to the holders of the Rights Certificates (or certificates for the Company Common Stock prior to the Distribution Date) by first-class mail. The Company may remove the Rights Agent or any successor Rights Agent upon thirty days' prior notice in writing, mailed to the Rights Agent or successor Rights Agent, as the case may be, and to each transfer agent of the Preferred Stock and the Company Common Stock, by registered or certified mail, and to the holders of the Rights Certificates (or certificates for the Company Common Stock prior to the Distribution Date) by first-class mail. If the Rights Agent shall resign or be removed or shall otherwise become incapable of acting, the Company shall appoint a successor to the Rights Agent. If the Company shall fail to make such appointment within a period of thirty days after giving notice of such removal or after it has been notified in writing of such resignation or incapacity by the resigning or incapacitated Rights Agent or by the holder of a Rights Certificate or, prior to the Distribution Date, the holder of a certificate for the Company Common Stock (who shall, with such notice, submit such holder's Rights Certificate or certificate for Company Common Stock, as the case may be, for inspection by the Company), then any registered holder of any Rights Certificate or, prior to the Distribution Date, the holder of a certificate for the Company Common Stock may apply to any court of competent jurisdiction for the appointment of a new Rights Agent. Any successor Rights Agent, whether appointed by the Company or by such a court, shall be (a) a Person organized and doing business under the laws of the United States or any state of the United States in good standing, shall be authorized to do business in the State of California, shall be authorized under such laws to conduct the shareholder services business, exercise corporate trust or stock transfer powers, shall be subject to supervision or examination by federal or state authorities and shall have at the time of its appointment as Rights Agent a combined capital and surplus of at least $50,000,000 or (b) an Affiliate of a Person described in clause (a). After appointment, the successor Rights Agent shall be vested with the same powers, rights, duties and responsibilities as if it had been originally named as Rights Agent without further act or deed; but the predecessor Rights Agent shall deliver and transfer to the successor Rights Agent any property at the time held by it hereunder, and execute and deliver any further assurance, conveyance, act or deed necessary for the purpose. Not later than the effective date of any such appointment, the Company shall file notice thereof in writing with the predecessor Rights Agent and each transfer agent of the Preferred Stock and the Company Common Stock, and mail a notice thereof in writing to the registered holders of the Rights Certificates (or certificates for the Company Common Stock prior to the Distribution Date). Failure to give any notice provided for 30 in this Section 21, however, or any defect therein, shall not affect the legality or validity of the resignation or removal of the Rights Agent or the appointment of the successor Rights Agent. SECTION 22. Issuance of New Rights Certificates. Notwithstanding any of the provisions of this Agreement or the Rights to the contrary, the Company may, at its option, issue new Rights Certificates evidencing Rights in such form as may be approved by a majority of the Company's Board of Directors to reflect any adjustment or change made in accordance with the provisions of this Agreement in the Purchase Price or the number or kind or class of shares or other securities or property that may be acquired upon exercise of the Rights. In addition, in connection with the issuance or sale of shares of Company Common Stock following the Distribution Date and prior to the Expiration Date, the Company (a) shall, with respect to shares of Company Common Stock so issued or sold pursuant to the exercise of stock options or under any employee plan or arrangement, or upon the exercise, conversion or exchange of securities hereinafter issued by the Company, and (b) may, in any other case, if deemed necessary or appropriate by a majority of the Company's Board of Directors, issue Rights Certificates evidencing the appropriate number of Rights in connection with such issuance or sale; provided, however, that (i) no such Rights Certificate shall be issued if, and to the extent that, the Company shall be advised by counsel that such issuance would create a significant risk of material adverse tax consequences to the Company or the Person to whom such Rights Certificate would be issued and (ii) no such Rights Certificate shall be issued if, and to the extent that, appropriate adjustment shall otherwise have been made in lieu of the issuance thereof. SECTION 23. Redemption and Termination. (a) Subject to Section 28, the Company may, at its option, by action of a majority of the Company's Board of Directors, at any time prior to the earlier of (i) the Close of Business on the tenth Day following the Stock Acquisition Date or (ii) the Final Expiration Date, redeem all but not less than all of the then-outstanding Rights at a redemption price of $.01 per Right, as such amount may be appropriately adjusted to reflect any spin-off or other similar transaction or any stock split, stock dividend or similar transaction occurring after the date hereof (such redemption price being the "Redemption Price"), and the Company may, at its option, by action of a majority of the Company's Board of Directors, pay the Redemption Price either in shares of Company Common Stock (based on the current market price, determined in accordance with Section 11(d), of the shares of Company Common Stock at the time of redemption) or cash. Subject to the foregoing, the redemption of the Rights may be made effective at such time, on such basis and with such conditions as the Board of Directors in its sole discretion may establish. (b) Immediately upon the action of a majority of the Company's Board of Directors ordering the redemption of the Rights, evidence of which shall be filed with the Rights Agent, and without any further action and without any notice, the right to exercise the Rights will terminate and the only right thereafter of the holders of Rights shall be to receive the Redemption Price for each Right so held. Promptly after the action of a majority of the Company's Board of Directors ordering the redemption of the Rights, the Company shall give prompt written notice of such redemption to the Rights Agent and the holders of the then-outstanding Rights by mailing such notice to all such holders at each holder's last address as it appears upon the registry books of the Rights Agent or, prior to the Distribution Date, on the registry books of the transfer agent for Company Common Stock. Any notice that is mailed in the manner herein provided shall be 31 deemed given, whether or not the holder receives the notice. Each such notice of redemption will state the method by which the payment of the Redemption Price will be made. SECTION 24. Notice of Certain Events. (a) In case the Company shall propose, at any time after the Distribution Date, (i) to pay any dividend payable in stock of any class to the holders of Preferred Stock or to make any other distribution to the holders of Preferred Stock (other than a regular quarterly cash dividend out of earnings or retained earnings of the Company), (ii) to offer to the holders of Preferred Stock rights or warrants to subscribe for or to purchase any additional shares of Preferred Stock or shares of stock of any class or any other securities, rights or options, (iii) to effect any reclassification of the Preferred Stock (other than a reclassification involving only the subdivision of outstanding shares of Preferred Stock), (iv) to effect any consolidation or merger into or with any other Person (other than a Subsidiary of the Company in a transaction that complies with Section 11(o) other than in connection with any public offering of the capital stock of any of the Company's subsidiaries or any spin-off or other similar transaction), or to effect any sale or other transfer (or to permit one or more of its Subsidiaries to effect any sale or other transfer), in one or more transactions, of more than 50% of the assets or earning power of the Company and its Subsidiaries (taken as a whole) to any other Person or Persons (other than the Company and/or any of its Subsidiaries in one or more transactions each of which complies with Section 11(o)) or (v) to effect the liquidation, dissolution or winding up of the Company, then, in each such case, the Company shall give to the Rights Agent and to each holder of a Rights Certificate (or, prior to the Distribution Date, to each holder of certificates for Company Common Stock), to the extent feasible and in accordance with Section 25, a notice of such proposed action, which shall specify the record date for the purposes of such stock dividend, distribution of rights or warrants, or the date on which such reclassification, consolidation, merger, sale, transfer, liquidation, dissolution or winding up is to take place and the date of participation therein by the holders of the shares of Preferred Stock, if any such date is to be fixed, and such notice shall be so given in the case of any action covered by clause (i) or (ii) above at least 20 days prior to the record date for determining holders of the shares of Preferred Stock for purposes of such action, and in the case of any such other action, at least 20 days prior to the date of the taking of such proposed action or the date of participation therein by the holders of the shares of Preferred Stock, whichever shall be the earlier; provided, however, no such notice shall be required pursuant to this Section 24 if any Subsidiary of the Company effects a consolidation or merger with or into, or effects a sale or other transfer of assets or earning power to, any other Subsidiary of the Company. (b) In case any of the events set forth in Section 11(a)(iii) shall occur, then, in any such case, the Company shall as soon as practicable thereafter give to the Rights Agent and to each holder of a Rights Certificate, to the extent feasible and in accordance with Section 25, a notice of the occurrence of such event, which shall specify the event and the consequences of the event to holders of Rights under Section 11(a)(iii). SECTION 25. Notices. All notices and other communications provided for hereunder shall, unless otherwise stated herein, be in writing and mailed or sent or delivered (including by facsimile transmission), if to the Company, at its address at: PG&E Corporation One Market, Spear Tower 32 Suite 2400 San Francisco, CA 94105 Attention: Corporate Secretary Telecopy No.: (415) 267-7257 with a copy to: PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, CA 94105 Attention: Bruce Worthington, Esq. Senior Vice President and General Counsel Telecopy No.: (415) 267-7257 and if to the Rights Agent, at its address at: Mellon Investor Services LLC 235 Montgomery Street, 23rd Floor San Francisco, CA 94104 Attention: Relationship Manager Telecopy No.: (415) 743-1423 with a copy to: Mellon Investor Services LLC 85 Challenger Road Ridgefield Park, NJ 07660 Attention: General Counsel Notices or demands authorized or required by this Agreement to be given or made by the Company or the Rights Agent to the holder of any Rights Certificate (or, if prior to the Distribution Date, to the holder of certificates evidencing shares of Company Common Stock) shall be sufficiently given or made if sent by first-class mail, postage prepaid, addressed to such holder at the address of such holder as shown on the registry books of the Rights Agent or, prior to the Distribution Date, on the registry books of the transfer agent for the Company Common Stock. SECTION 26. Supplements and Amendments. Prior to the Distribution Date and subject to the penultimate sentence of this Section 26, the Company and the Rights Agent shall, if the Company so directs, supplement or amend any provision of this Agreement without the approval of any holders of certificates evidencing shares of Company Common Stock. From and after the Distribution Date and subject to the penultimate sentence of this Section 26, the Company and the Rights Agent shall, if the Company so directs, supplement or amend this Agreement without the approval of any holders of Rights Certificates as contemplated by 33 Section 11(a)(ii) or in order (a) to cure any ambiguity, (b) to correct or supplement any provision contained herein that may be defective or inconsistent with any other provisions herein, (c) to shorten or lengthen any time period hereunder or (d) to change or supplement the provisions hereunder in any manner which the Company may deem necessary or desirable and which shall not adversely affect the interests of the holders of Rights Certificates (other than an Acquiring Person or an Affiliate or Associate of an Acquiring Person); provided, however, that this Agreement may not be supplemented or amended to lengthen, pursuant to clause (c) of this sentence, (i) subject to Section 30, a time period relating to when the Rights may be redeemed at such time as the Rights are not then redeemable or (ii) any other time period unless such lengthening is for the purpose of protecting, enhancing or clarifying the rights of, and/or the benefits to, the holders of Rights. Upon the delivery of a certificate from an appropriate officer of the Company or, so long as any Person is an Acquiring Person hereunder, from the majority of the Company's Board of Directors, that states that the proposed supplement or amendment is in compliance with the terms of this Section 26, the Rights Agent shall execute such supplement or amendment. Prior to the Distribution Date, the interests of the holders of Rights shall be deemed coincident with the interests of the holders of Company Common Stock. SECTION 27. Successors. All the covenants and provisions of this Agreement by or for the benefit of the Company or the Rights Agent shall bind and inure to the benefit of their respective successors and assigns hereunder. SECTION 28. Determinations and Actions by the Board of Directors, etc. For all purposes of this Agreement, any calculation of the number of shares of Company Common Stock outstanding at any particular time, including for purposes of determining the particular percentage of such outstanding shares of Company Common Stock of which any Person is the Beneficial Owner, shall be made in accordance with the last sentence of Rule 13d-3(d)(1)(i) of the Exchange Act Regulations as in effect on the date hereof. Except as otherwise specifically provided herein, the Board of Directors of the Company shall have the exclusive power and authority to administer this Agreement and to exercise all rights and powers specifically granted to the Board of Directors of the Company or to the Company, or as may be necessary or advisable in the administration of this Agreement, including, without limitation, the right and power (i) to interpret the provisions of this Agreement and (ii) to make all determinations deemed necessary or advisable for the administration of this Agreement. All such actions, calculations, interpretations and determinations (including, for purposes of clause (y) below, all omissions with respect to the foregoing) that are done or made by the Board of Directors in good faith shall (x) be final, conclusive and binding on the Company, the Rights Agent, the holders of the Rights and all other parties, and (y) not subject the Board of Directors of the Company or any member thereof to any liability to the holders of the Rights. The Rights Agent shall always be entitled to assume that the Company's Board of Directors acted in good faith and shall be protected and incur no liability in reliance theron. SECTION 29. Benefits of this Agreement. Nothing in this Agreement shall be construed to give to any Person other than the Company, the Rights Agent and the registered holders of the Rights Certificates (and, prior to the Distribution Date, registered holders of shares of Company Common Stock) any legal or equitable right, remedy or claim under this Agreement. This Agreement shall be for the sole and exclusive benefit of the Company, the Rights Agent and the registered holders of the Rights Certificates (and, prior to the Distribution Date, registered holders of shares of Company Common Stock). 34 SECTION 30. Severability. If any term, provision, covenant or restriction of this Agreement is held by a court of competent jurisdiction or other authority to be invalid, void or unenforceable, the remainder of the terms, provisions, covenants and restrictions of this Agreement shall remain in full force and effect and shall in no way be affected, impaired or invalidated; provided, however, that notwithstanding anything in this Agreement to the contrary, if any such term, provision, covenant or restriction is held by such court or authority to be invalid, void or unenforceable and a majority of the Company's Board of Directors determines in its good faith judgment that severing the invalid language from this Agreement would adversely affect the purpose or effect of this Agreement and the Rights shall not then be redeemable, the right of redemption set forth in Section 23 shall be reinstated and shall not expire until the Close of Business on the tenth Business Day following the date of such determination by a majority of the Company's Board of Directors. SECTION 31. Governing Law. This Agreement, each Right and each Rights Certificate issued hereunder shall be governed by, and construed in accordance with, the laws of the State of California; provided, however, that all provisions regarding the rights, duties and obligations of the Rights Agent shall be governed by and construed in accordance with the laws of the State of New York applicable to contracts made and to be performed entirely within such State. SECTION 32. Counterparts. This Agreement may be executed (including by facsimile) in one or more counterparts, and by the different parties hereto in separate counterparts, each of which when executed shall be deemed to be an original, but all of which taken together shall constitute one and the same instrument. SECTION 33. Descriptive Headings. The headings contained in this Agreement are for descriptive purposes only and shall not affect in any way the meaning or interpretation of this Agreement. SECTION 34. Exchange. (a) (i) The Company may, at its option, at any time after any person becomes an Acquiring Person, upon resolution adopted by a majority of the Company's Board of Directors, exchange all or part of the then outstanding and exercisable Rights (which shall not include Rights that have become null and void pursuant Section 7(e)) for Units of Preferred Stock at an exchange ratio of one Unit of Preferred Stock per Right, appropriately adjusted to reflect any stock split, stock dividend or similar transaction occurring after the date hereof (such exchange ratio being hereinafter referred to as the "Section 34(a)(i) Exchange Ratio"). Notwithstanding the foregoing, the Company may not effect such exchange at any time after any Person (other than the Company, any Subsidiary of the Company, any employee benefit plan maintained by the Company or any of its Subsidiaries, or any trustee or fiduciary with respect to such plan acting in such capacity), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner of 50% or more of the shares of Company Common Stock then outstanding. (ii) The Company may, at its option, at any time after any person becomes an Acquiring Person, upon resolution adopted by a majority of the Company's Board of Directors, exchange all or part of the then outstanding and exercisable Rights (which shall not include Rights that have become void pursuant to Section 7(e)) for Units of Preferred Stock at an 35 exchange ratio specified in the following sentence, as appropriately adjusted to reflect any stock split, stock dividend or similar transaction occurring after the date hereof. Subject to such adjustment, each Right may be exchanged for that number of Units of Preferred Stock obtained by dividing the Adjustment Spread (as defined below) by the then-current market price (determined pursuant to Section 11(d)) per Unit of Preferred Stock on the earlier of (i) the date on which any Person becomes an Acquiring Person and (ii) the date on which a tender or exchange offer by any Person (other than the Company, any Subsidiary of the Company, any employee benefit plan maintained by the Company or any of its Subsidiaries or any trustee or fiduciary with respect to such plan acting in such capacity) is first published or sent or given within the meaning of Rule 14d-4(a) of the Exchange Act Regulations or any successor rule, if upon consummation thereof such Person would be the Beneficial Owner of 15% or more of the shares of Company Common Stock then outstanding (such exchange ratio being the "Section 34(a)(ii) Exchange Ratio"). The "Adjustment Spread" shall equal (x) the aggregate market price on the date of such event of the number of Adjustment Shares determined pursuant to Section 11(a)(iii), minus (y) the Purchase Price. Notwithstanding the foregoing, the Company may not effect such exchange at any time after any Person (other than the Company, any Subsidiary of the Company, any employee benefit plan maintained by the Company or any of its Subsidiaries, or any trustee or fiduciary with respect to such plan acting in such capacity), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner of 50% or more of the shares of the Company Common Stock then outstanding. Notwithstanding anything contained in this Section 34(a) to the contrary, the Company may not exchange any Rights pursuant to this Section 34(a) unless at the time of the action of the Board of Directors of the Company approving such exchange. (b) Immediately upon the action of a majority of the Company's Board of Directors ordering the exchange of any Rights pursuant to Section 34(a) and without any further action and without any notice, the right to exercise such Rights shall terminate and the only right thereafter of a holder of such Rights shall be to receive that number of Units of Preferred Stock equal to the number of such Rights held by such holder multiplied by the Section 34(a)(i) Exchange Ratio or Section 34(a)(ii) Exchange Ratio, as the case may be. The Company shall promptly notify the Rights Agent in writing of such exchange and shall promptly give public notice of any such exchange; provided, however, that the failure to give, or any defect in, such notice shall not affect the validity of such exchange. The Company promptly shall mail a notice of any such exchange to all of the holders of such Rights at their last addresses as they appear upon the registry books of the Rights Agent. Any notice that is mailed in the manner herein provided shall be deemed given, whether or not the holder receives the notice. Each such notice of exchange shall state the method by which the exchange of Units of Preferred Stock for Rights will be effected and, in the event of any partial exchange, the number of Rights that will be exchanged. Any partial exchange shall be effected pro rata based on the number of Rights (other than Rights that have become null and void pursuant to Section 7(e)) held by each holder of Rights. (c) In the event that the number of shares of Preferred Stock that are authorized by the Company's Articles of Incorporation but not outstanding or reserved for issuance for purposes other than upon exercise of the Rights are not sufficient to permit any exchange of Rights as contemplated in accordance with this Section 34, the Company shall take 36 all such action as may be necessary to authorize additional shares of Preferred Stock for issuance upon exchange of the Rights or make adequate provision to substitute (1) cash, (2) Company Common Stock or other equity securities of the Company, (3) debt securities of the Company, (4) other assets or (5) any combination of the foregoing, having an aggregate value equal to the Adjustment Spread, where such aggregate value has been determined by a majority of the Company's Board of Directors. (d) The Company shall not be required to issue fractions of Units of Preferred Stock or to distribute certificates that evidence fractional Units. In lieu of fractional Units, the Company may pay to the registered holders of Rights Certificates at the time such Rights are exchanged as herein provided an amount in cash equal to the same fraction of the current market price (determined pursuant to Section 11(d)) of one Unit of Preferred Stock. 37 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed on their behalf as of the date first above written. PG&E CORPORATION By /s/ Robert D. Glynn, Jr. ------------------------------ Name: Robert D. Glynn, Jr. Title: Chairman of the Board Countersigned: MELLON INVESTOR SERVICES LLC By /s/ Joseph Thatcher ------------------------------ Name: Joseph Thatcher Title: Assistant Vice President EXHIBIT A FORM OF RIGHTS CERTIFICATE EXHIBIT A --------- Certificate No. Rights ------ ------ NOT EXERCISABLE AFTER THE EXPIRATION DATE (AS DEFINED IN THE RIGHTS AGREEMENT REFERRED TO BELOW). THE RIGHTS ARE SUBJECT TO REDEMPTION, AT THE OPTION OF THE COMPANY, ON THE TERMS SET FORTH IN THE RIGHTS AGREEMENT. UNDER CERTAIN CIRCUMSTANCES (SPECIFIED IN THE RIGHTS AGREEMENT), RIGHTS BENEFICIALLY OWNED BY ACQUIRING PERSONS (AS DEFINED IN THE RIGHTS AGREEMENT) OR ANY SUBSEQUENT HOLDER OF SUCH RIGHTS MAY BECOME NULL AND VOID. [THE RIGHTS REPRESENTED BY THIS RIGHTS CERTIFICATE ARE OR WERE BENEFICIALLY OWNED BY A PERSON WHO WAS OR BECAME AN ACQUIRING PERSON OR AN AFFILIATE OR ASSOCIATE OF AN ACQUIRING PERSON (AS SUCH TERMS ARE DEFINED IN THE RIGHTS AGREEMENT REFERRED TO BELOW). ACCORDINGLY, THIS RIGHTS CERTIFICATE AND THE RIGHTS REPRESENTED HEREBY MAY BECOME NULL AND VOID IN THE CIRCUMSTANCES SPECIFIED IN SECTION 7(e) OF THE RIGHTS AGREEMENT.]* RIGHTS CERTIFICATE ------------------ PG&E CORPORATION This certifies that, or registered assigns, is the registered holder of the number of Rights set forth above, each of which entitles the registered holder thereof, subject to the terms and conditions of the Rights Agreement dated as of December 22, 2000 (the "Rights Agreement"; terms defined therein are used herein with the same meaning unless otherwise defined herein) between PG&E Corporation, a California corporation (the "Company"), and Mellon Investor Services L.L.C., a New Jersey limited liability company, as Rights Agent (which term shall include any successor Rights Agent under the Rights Agreement), to purchase from the Company at any time after the Distribution Date and prior to the Expiration Date at the office of the Rights Agent, one one-hundredth of a fully paid and non-assessable share of Series A Preferred Stock, par value $100 per share (the "Preferred Stock"), of the Company at the Purchase Price initially of $95 per one one-hundredth share (each such one one-hundredth of a share being a "Unit") of Preferred Stock, upon presentation and surrender of this Rights Certificate with the Election to Purchase and related certificate duly executed. The number of Rights evidenced by this Rights Certificate (and the number of Units which may be purchased upon exercise thereof) set forth above, and the Purchase Price per Unit set forth above shall be subject to adjustment in certain events as provided in the Rights Agreement. Upon the occurrence of a Section 11(a)(iii) Event or Section 13 Event, if the Rights evidenced by this Rights Certificate are beneficially owned by an Acquiring Person or an Affiliate or Associate of any such Acquiring Person or, under certain circumstances described in - -------- * The portion of the legend in brackets shall be inserted only if applicable and shall replace the preceding sentence. 2 the Rights Agreement, a transferee of any such Acquiring Person, Associate or Affiliate, such Rights shall become null and void and no holder hereof shall have any right with respect to such Rights from and after the occurrence of such Section 11(a)(iii) Event or Section 13 Event. In certain circumstances described in the Rights Agreement, the Rights evidenced hereby may entitle the registered holder thereof to purchase capital stock of an entity other than the Company or to receive common stock, cash or other assets, all as provided in the Rights Agreement. This Rights Certificate is subject to all of the terms and conditions of the Rights Agreement, which terms and conditions are hereby incorporated herein by reference and made a part hereof and to which Rights Agreement reference is hereby made for a full description of the rights, limitations of rights, obligations, duties and immunities hereunder of the Rights Agent, the Company and the holders of the Rights Certificates. Copies of the Rights Agreement are on file at the principal office of the Company and are available from the Company upon written request. This Rights Certificate, with or without other Rights Certificates, upon surrender at the office of the Rights Agent designated for such purpose, may be exchanged for another Rights Certificate or Rights Certificates of like tenor and date evidencing an aggregate number of Rights equal to the aggregate number of Rights evidenced by the Rights Certificate or Rights Certificates surrendered. If this Rights Certificate shall be exercised in part, the registered holder shall be entitled to receive, upon surrender hereof, another Rights Certificate or Rights Certificates for the number of whole Rights not exercised. Subject to the provisions of the Rights Agreement, the Rights evidenced by this Certificate may be redeemed by the Company under certain circumstances at its option at a redemption price of $.01 per Right, payable at the Company's option in cash or in common stock of the Company, subject to adjustment in certain events as provided in the Rights Agreement. No fractional shares of Preferred Stock will be issued upon the exercise of any Right or Rights evidenced hereby (other than fractions which are integral multiples of one one-hundredth of a share of Preferred Stock), but in lieu thereof a cash payment will be made, as provided in the Rights Agreement. No holder of this Rights Certificate, as such, shall be entitled to vote or receive dividends or be deemed for any purpose the holder of Preferred Stock or of any other securities which may at any time be issuable upon the exercise hereof, nor shall anything contained in the Rights Agreement or herein be construed to confer upon the holder hereof, as such, any of the rights of a shareholder of the Company or any right to vote for the election of directors or upon any matter submitted to shareholders at any meeting thereof, or to give or withhold consent to any corporate action, or to receive notice of meetings or other actions affecting shareholders (except as provided in the Rights Agreement), or to receive dividends or subscription rights, or otherwise, until the Rights evidenced by this Rights Certificate shall have been exercised as provided in the Rights Agreement. 3 This Rights Certificate shall not be valid or obligatory for any purpose until it shall have been countersigned by the Rights Agent. WITNESS the facsimile signature of the proper officers of the Company and its corporate seal. Dated as of, ----------------- ---- ---------. ATTEST: PG&E CORPORATION By ____________________ By _______________________ Name: Name: Title: Title: Countersigned: MELLON INVESTOR SERVICES L.L.C., as Rights Agent By ____________________ Name: Title: Form of Reverse Side of Rights Certificate FORM OF ASSIGNMENT ------------------ (To be executed by the registered holder if such holder desires to transfer the Rights Certificate) FOR VALUE RECEIVED ____________________________________________________ (Please print name of registered holder) hereby sells, assigns and transfers unto ___________________________________________________________________________ (Please print name and address of transferee) this Rights Certificate, together with all right, title and interest therein, and does hereby irrevocably constitute and appoint __________________, Attorney, to transfer the within Rights Certificate on the books of the within-named Company, with full power of substitution. Dated:______________________ ___, ________ _______________________________ Signature Signature Guaranteed: CERTIFICATE The undersigned hereby certifies by checking the appropriate boxes that: (1) this Rights Certificate [_] is [_] is not being sold, assigned and transferred by or on behalf of a Person who is or was an Acquiring Person or an Affiliate or Associate of any such Acquiring Person (as such terms are defined pursuant to the Rights Agreement); and (2) after due inquiry and to the best knowledge of the undersigned, it [_] did [_] did not acquire the Rights evidenced by this Rights Certificate from any Person who is, was or subsequently became an Acquiring Person or an Affiliate or Associate of an Acquiring Person. Dated:____________________, ____ _______ ________________________________ Signature Signature Guaranteed: ______________________________________________________________ NOTICE ------ The signature to the foregoing Assignment and Certificate must correspond to the name as written upon the face of this Rights Certificate in every particular, without alteration or enlargement or any change whatsoever. In the event the certification set forth above is not completed, the Company will deem the beneficial owner of the Rights evidenced by this Rights Certificate to be an Acquiring Person or an Affiliate or Associate thereof (as defined in the Rights Agreement) and, in the case of an Assignment, will affix a legend to that effect on any Rights Certificates issued in exchange for this Rights Certificate. FORM OF ELECTION TO PURCHASE ---------------------------- (To be executed if the registered holder desires to exercise Rights represented by the Rights Certificate) To: PG&E CORPORATION The undersigned hereby irrevocably elects to exercise Rights represented by this Rights Certificate to purchase the Units of Preferred Stock issuable upon the exercise of the Rights (or such other securities of the Company or of any other person or other property which may be issuable upon the exercise of the Rights) and requests that certificates for such Units be issued in the name of and delivered to: - -------------------------------------------------------------------------- (Please print name and address) - -------------------------------------------------------------------------- Please insert social security or other identifying number: ____________________________ If such number of Rights shall not be all the Rights evidenced by this Rights Certificate, a new Rights Certificate for the balance of such Rights shall be registered in the name of and delivered to: - -------------------------------------------------------------------------- (Please print name and address) - -------------------------------------------------------------------------- Please insert social security or other identifying number: ____________________________ Dated: ____________________ ____, ________ ________________________ Signature Signature Guaranteed: CERTIFICATE ----------- The undersigned hereby certifies by checking the appropriate boxes that: (1) the Rights evidenced by this Rights Certificate [ ] are [ ] are not beneficially owned by an Acquiring Person or an Affiliate or an Associate thereof (as defined in the Rights Agreement); and (2) after due inquiry and to the best knowledge of the undersigned, the undersigned [ ] did [ ] did not acquire the Rights evidenced by this Rights Certificate from any person who is, was or subsequently became an Acquiring Person or an Affiliate or Associate thereof. Dated: ____________________ ____, ________ _________________________________ Signature Signature Guaranteed: ______________________________________________________________ NOTICE ------ The signature in the foregoing Election to Purchase and Certificate must conform to the name as written upon the face of this Rights Certificate in every particular, without alteration or enlargement or any change whatsoever. In the event the certification set forth above is not completed, the Company will deem the beneficial owner of the Rights evidenced by this Rights Certificate to be an Acquiring Person or an Affiliate or Associate thereof (as defined in the Rights Agreement) and, in the case of an Assignment, will affix a legend to that effect on any Rights Certificates issued in exchange for this Rights Certificate. EXHIBIT B --------- SUMMARY OF RIGHTS TO PURCHASE PREFERRED STOCK On December 20, 2000, the Board of Directors of PG&E Corporation (the "Corporation") declared a distribution of one Right for each outstanding share ----------- of Common Stock, no par value, of the Corporation (the "Corporation Common ------------------ Stock"), to shareholders of record at the close of business on January 2, 2001 - ----- (the "Record Date") and for each share of Corporation Common Stock issued by the ----------- Corporation thereafter and prior to the Distribution Date. Each Right entitles the registered holder, subject to the terms of the Rights Agreement (as defined below), to purchase from the Corporation one one-hundredth of a share (a "Unit") ---- of Series A Preferred Stock, par value $100 per share (the "Preferred Stock"), --------------- at a Purchase Price of $95 per Unit, subject to adjustment. The Purchase Price is payable in cash or by certified or bank check payable to the order of the Corporation or by wire transfer to the account of the Corporation (provided a notice of such wire transfer is given by the holder of the related Right to the Rights Agent). The description and terms of the Rights are set forth in a Rights Agreement between the Corporation and Mellon Investor Services LLC, a New Jersey limited liability company, as Rights Agent (the "Rights Agreement"). ---------------- Copies of the Rights Agreement and the form of Certificate of Determination for the Preferred Stock have been filed with the Securities and Exchange Commission as exhibits to a Registration Statement on Form 8-A dated December 22, 2000 (the "Form 8-A"). Copies of the Rights Agreement and the -------- Certificate of Determination are available free of charge from the Corporation. This summary description of the Rights and the Preferred Stock does not purport to be complete and is qualified in its entirety by reference to all the provisions of the Rights Agreement and the Certificate of Determination, including the definitions therein of certain terms, which Rights Agreement and Certificate of Determination are incorporated herein by reference. The Rights Agreement - -------------------- Initially, the Rights will attach to all certificates representing shares of outstanding Corporation Common Stock, and no separate Rights Certificates will be distributed. The Rights will separate from the Corporation Common Stock and the "Distribution Date" will occur upon the earlier of (i) 10 ----------------- days following a public announcement (the date of such announcement being the "Stock Acquisition Date") that a person or group of affiliated or associated ---------------------- persons (other than the Corporation, any subsidiary of the Corporation or any employee benefit plan of the Corporation or such subsidiary) (an "Acquiring --------- Person") has acquired, obtained the right to acquire, or otherwise obtained - ------ beneficial ownership of 15% or more of the then-outstanding shares of Corporation Common Stock, and (ii) 10 business days (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person) following the commencement of a tender offer or exchange offer that would result in a person or group beneficially owning 15% or more of the then-outstanding shares of Corporation Common Stock. Until the Distribution Date, (i) the Rights will be evidenced by Corporation Common Stock certificates and will be transferred with and only with such Corporation Common Stock certificates, (ii) new Corporation Common Stock certificates issued after the Record Date will contain a notation incorporating the Rights Agreement by reference and (iii) the surrender for transfer of any certificates representing outstanding Corporation Common Stock will also constitute the transfer of the Rights associated with the Corporation Common Stock represented by such certificates. The Rights are not exercisable until the Distribution Date and will expire at the close of business on the tenth anniversary of the Rights Agreement, unless earlier redeemed by the Corporation as described below. As soon as practicable after the Distribution Date, Rights Certificates will be mailed to holders of record of Corporation Common Stock as of the close of business on the Distribution Date and, thereafter, the separate Rights Certificates alone will represent the Rights. In the event that (i) the Corporation is the surviving corporation in a merger with an Acquiring Person and shares of Corporation Common Stock shall remain outstanding, (ii) a Person becomes an Acquiring Person, (iii) an Acquiring Person engages in one or more "self-dealing" transactions as set forth in the Rights Agreement, or (iv) during such time as there is an Acquiring Person, an event occurs which results in such Acquiring Person's ownership interest being increased by more than 1% (e.g., by means of a recapitalization) (each such event being a "Section 11(a)(iii) Event"), then, in each such case, ------------------------ each holder of a Right will thereafter have the right to receive, upon exercise, Units of Preferred Stock (or, in certain circumstances, Corporation Common Stock, cash, property or other securities of the Corporation) having a value equal to two times the exercise price of the Right. The exercise price is the Purchase Price multiplied by the number of Units of Preferred Stock issuable upon exercise of a Right prior to the events described in this paragraph. Notwithstanding any of the foregoing, following the occurrence of any of the events set forth in this paragraph, all Rights that are, or (under certain circumstances specified in the Rights Agreement) were, beneficially owned by any Acquiring Person will be null and void. In the event that, at any time following the Stock Acquisition Date, (i) the Corporation is acquired in a merger (other than a merger described in the preceding paragraph) or other business combination and the Corporation is not the surviving corporation, (ii) any Person consolidates or merges with the Corporation and all or part of the Corporation Common Stock is converted or exchanged for securities, cash or property of any other Person or (iii) 50% or more of the Corporation's assets or earning power is sold or transferred, each holder of a Right (except Rights which previously have been voided as described above) shall thereafter have the right to receive, upon exercise, common stock of the ultimate parent of the Acquiring Person having a value equal to two times the exercise price of the Right. The Purchase Price payable, and the number of Units of Preferred Stock issuable, upon exercise of the Rights are subject to adjustment from time to time to prevent dilution (i) in the event of a stock dividend on, or a subdivision, combination or reclassification of, the Preferred Stock, (ii) if holders of the Preferred Stock are granted certain rights or warrants to subscribe for Preferred Stock or convertible securities at less than the current market price of the Preferred Stock, or (iii) upon the distribution to the holders of the Preferred Stock of evidences of indebtedness, cash or assets (excluding regular quarterly cash dividends) or of subscription rights or warrants (other than those referred to above). With certain exceptions, no adjustment in the Purchase Price will be required until cumulative adjustments amount to at least 1% of the Purchase Price. The Corporation is not required to issue fractional Units. In lieu thereof, an adjustment in cash may be made based on the market price of the Preferred Stock prior to the date of exercise. At any time prior to the earlier of (i) ten business days following the Stock Acquisition Date or (ii) the Final Expiration Date, a majority of the Corporation's Board of Directors may redeem the Rights in whole, but not in part, at a price of $.01 per Right (subject to adjustment in certain events) (the "Redemption Price"), payable, at the election of such majority of the ---------------- Corporation's Board of Directors, in cash or shares of Corporation Common Stock. Immediately upon the action of a majority of the Corporation's Board of Directors ordering the redemption of the Rights, the Rights will terminate and the only remaining right of the holders of Rights will be to receive the Redemption Price. The Board of Directors, at its option, may exchange each Right for (i) one Unit of Preferred Stock or (ii) such number of Units of Preferred Stock as will equal (x) the difference between the aggregate market price of the number of Units of Preferred Stock to be received upon a Section 11(a)(iii) Event and the purchase price set forth in the Rights Agreement, divided by (y) the market price per Unit of Preferred Stock upon a Section 11(a)(iii) Event. Until a Right is exercised, the holder thereof, as such, will have no rights as a shareholder of the Corporation, including, without limitation, the right to vote or to receive dividends. While the distribution of the Rights will not be taxable to shareholders or to the Corporation, shareholders may, depending upon the circumstances, recognize taxable income in the event that the Rights become exercisable for Units of Preferred Stock (or other consideration). Any of the provisions of the Rights Agreement may be amended without the approval of the holders of Corporation Common Stock at any time prior to the Distribution Date. After the Distribution Date, the provisions of the Rights Agreement may be amended in order to cure any ambiguity, defect or inconsistency, to make changes which do not adversely affect the interests of the holders of Rights (excluding the interests of any Acquiring Person), or to shorten or lengthen any time period under the Rights Agreement; provided, however, that no amendment to adjust the time period governing redemption shall be made at such time as the Rights are not redeemable. Description of Preferred Stock - ------------------------------ The Units of Preferred Stock that may be acquired upon exercise of the Rights will be nonredeemable and subordinate to any other shares of preferred stock that may be issued by the Corporation. Each Unit of Preferred Stock will have a minimum preferential quarterly dividend of $.01 per Unit or any higher per share dividend declared on the Corporation Common Stock. In the event of liquidation, the holder of a Unit of Preferred Stock will receive a preferred liquidation payment equal to the greater of $1.00 per Unit or the per share amount paid in respect of a share of Corporation Common Stock. Each Unit of Preferred Stock will have one vote, voting together with the Corporation Common Stock. The holders of Units of Preferred Stock, voting as a separate class, shall be entitled to elect two directors if dividends on the Preferred Stock are in arrears for six fiscal quarters. In the event of any merger, consolidation or other transaction in which shares of Corporation Common Stock are exchanged, each Unit of Preferred Stock will be entitled to receive the per share amount paid in respect of each share of Corporation Common Stock. The rights of holders of the Preferred Stock to dividends, liquidation and voting, and in the event of mergers and consolidations, are protected by customary antidilution provisions. Because of the nature of the Preferred Stock's dividend, liquidation and voting rights, the economic value of one Unit of Preferred Stock that may be acquired upon the exercise of each Right is expected to approximate the economic value of one share of Corporation Common Stock. EXHIBIT C --------- CERTIFICATE OF DETERMINATION OF PREFERENCES -------------------------------- Pursuant to Section 401 of the California General Corporation Law -------------------------------- ROBERT D. GLYNN, JR. and LESLIE H. EVERETT certify that: 1. They are the Chairman of the Board, Chief Executive Officer, and President, and the Vice President and Corporate Secretary, respectively, of PG&E Corporation, a California corporation. 2. Pursuant to authority conferred upon the Board of Directors of the Corporation by its Restated Articles of Incorporation (the "Articles"), and, -------- pursuant to the provisions of Section 401 of the California General Corporation Law, said Board of Directors, at a duly called meeting held on December 20, 2000, at which a quorum was present and acted throughout, adopted the following resolutions, which resolutions remain in full force and effect on the date hereof creating a series of 5,000,000 shares of Preferred Stock having a par value of $100 per share, designated as Series A Preferred Stock (the "Series A -------- Preferred Stock") out of the class of 85,000,000 shares of preferred stock (the - --------------- "Preferred Stock"): --------------- RESOLVED, that pursuant to the authority vested in the Board of Directors in accordance with the provisions of the Articles, the Board of Directors does hereby create, authorize and provide for the issuance of the Series A Preferred Stock having the voting powers, designation, relative, participating, optional and other special rights, preferences and qualifications, limitations and restrictions thereof that are set forth as follows: Section 1. Designation and Amount. The shares of such series shall ---------------------- be designated as "Series A Preferred Stock" and the number of shares constituting such series shall be 5,000,000. Section 2. Dividends and Distributions. (A) Subject to the prior --------------------------- and superior rights of the holders of any shares of any other series of Preferred Stock or any other shares of preferred stock of the Corporation ranking prior and superior to the shares of Series A Preferred Stock with respect to dividends, each holder of one one-hundredth (1/100) of a share (a "Unit") of Series A Preferred Stock shall be entitled to receive, when, as and ---- if declared by the Board of Directors out of funds legally available for that purpose, (i) quarterly dividends payable in cash on the last day of March, June, September and December in each year (each such date being a "Quarterly Dividend ------------------ Payment Date"), commencing on the first Quarterly Dividend Payment Date after - ------------ the first issuance of such Unit of Series A Preferred Stock, in an amount per Unit (rounded to the nearest cent) equal to the greater of (a) $.01 or (b) subject to the provision for adjustment hereinafter set forth, the aggregate per share amount of all cash dividends declared on shares of the Common Stock since the immediately preceding Quarterly Dividend Payment Date, or, with respect to the first Quarterly Dividend Payment Date, since the first issuance of a Unit of Series A Preferred Stock, and (ii) subject to the provision for adjustment hereinafter set forth, quarterly distributions (payable in kind) on each Quarterly Dividend Payment Date in an amount per Unit equal to the aggregate per share amount of all non-cash dividends or other distributions (other than a dividend payable in shares of Common Stock or a subdivision of the outstanding shares of Common Stock, by reclassification or otherwise) declared on shares of Common Stock since the immediately preceding Quarterly Dividend Payment Date, or with respect to the first Quarterly Dividend Payment Date, since the first issuance of a Unit of Series A Preferred Stock. In the event that the Corporation shall at any time after December 20, 2000 (the "Rights Declaration ------------------ Date") (i) declare any dividend on outstanding shares of Common Stock payable in - ---- shares of Common Stock, (ii) subdivide outstanding shares of Common Stock or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case the amount to which the holder of a Unit of Series A Preferred Stock was entitled immediately prior to such event pursuant to the preceding sentence shall be adjusted by multiplying such amount by a fraction the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. (B) The Corporation shall declare a dividend or distribution on Units of Series A Preferred Stock as provided in paragraph (A) above immediately after it declares a dividend or distribution on the shares of Common Stock (other than a dividend payable in shares of Common Stock); provided, however, that, in the -------- ------- event no dividend or distribution shall have been declared on the Common Stock during the period between any Quarterly Dividend Payment Date and the next subsequent Quarterly Dividend Payment Date, a dividend of $.01 per Unit on the Series A Preferred Stock shall nevertheless be payable on such subsequent Quarterly Dividend Payment Date. (C) Dividends shall begin to accrue and shall be cumulative on each outstanding Unit of Series A Preferred Stock from the Quarterly Dividend Payment Date next preceding the date of issuance of such Unit of Series A Preferred Stock, unless the date of issuance of such Unit is prior to the record date for the first Quarterly Dividend Payment Date, in which case, dividends on such Unit shall begin to accrue from the date of issuance of such Unit, or unless the date of issuance is a Quarterly Dividend Payment Date or is a date after the record date for the determination of holders of Units of Series A Preferred Stock entitled to receive a quarterly dividend and before such Quarterly Dividend Payment Date, in either of which events such dividends shall begin to accrue and be cumulative from such Quarterly Dividend Payment Date. Accrued but unpaid dividends shall not bear interest. Dividends paid on Units of Series A Preferred Stock in an amount less than the aggregate amount of all such dividends at the time accrued and payable on such Units shall be allocated pro rata on a Unit-by- Unit basis among all Units of Series A Preferred Stock at the time outstanding. The Board of Directors may fix a record date for the determination of holders of Units of Series A Preferred Stock entitled to receive payment of a dividend or distribution declared thereon, which record date shall be no more than 30 days prior to the date fixed for the payment thereof. Section 3. Voting Rights. The holders of Units of Series A Preferred ------------- Stock shall have the following voting rights: (A) Subject to the provision for adjustment hereinafter set forth, each Unit of Series A Preferred Stock shall entitle the holder thereof to one vote on all ma tters submitted for a vote of the shareholders of the Corporation. In the event the Corporation shall at any time after the Rights Declaration Date (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock or (iii) combine the outstanding shares of Common Stock into a smaller number of shares, then in each such case the number of votes per Unit to which holders of Units of Series A Preferred Stock were entitled immediately prior to such event shall be adjusted by multiplying such number by a fraction the numerator of which shall be the number of shares of Common Stock outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. (B) Except as otherwise provided herein or by law, the holders of Units of Series A Preferred Stock and the holders of shares of Common Stock shall vote together as one class on all matters submitted to a vote of shareholders of the Corporation. (C) (i) If, at any time, dividends on any Units of Series A Preferred Stock shall be in arrears in an amount equal to six quarterly dividends thereon, then during the period (a "default period") from the occurrence of such event -------------- until such time as all accrued and unpaid dividends for all previous quarterly dividend periods and for the current quarterly dividend period on all Units of Series A Preferred Stock then outstanding shall have been declared and paid or set apart for payment, all holders of Units of Series A Preferred Stock, voting separately as a class, shall have the right to elect two Directors. (ii) During any default period, such voting rights of the holders of Units of Series A Preferred Stock may be exercised initially at a special meeting called pursuant to subparagraph (iii) of this Section 3(C) or at any annual meeting of shareholders, and thereafter at annual meetings of shareholders, provided that such voting rights may not be exercised at any meeting unless one-third of the outstanding Units of Preferred Stock shall be present at such meeting in person or by proxy. The absence of a quorum of the holders of Common Stock shall not affect the exercise by the holders of Units of Series A Preferred Stock of such rights. At any meeting at which the holders of Units of Series A Preferred Stock shall exercise such voting rights initially during an existing default period, they shall have the right, voting separately as a class, to elect Directors to fill up to two vacancies in the Board of Directors, if any such vacancies may then exist, or, if such right is exercised at an annual meeting, to elect two Directors. After the holders of Units of Series A Preferred Stock shall have exercised their right to elect Directors during any default period, the number of Directors shall not be increased or decreased except as approved by a vote of the holders of Units of Series A Preferred Stock as herein provided or pursuant to the rights of any equity securities ranking senior to the Series A Preferred Stock. (iii) Unless the holders of Series A Preferred Stock shall, during an existing default period, have previously exercised their right to elect Directors, the Board of Directors may order, or any shareholder or shareholders owning in the aggregate not less than 10% of the total number of the Units of Series A Preferred Stock outstanding may request, the calling of a special meeting of the holders of Units of Series A Preferred Stock, which meeting shall thereupon be called by the Secretary of the Corporation. Notice of such meeting and of any annual meeting at which holders of Units of Series A Preferred Stock are entitled to vote pursuant to this paragraph (C)(iii) shall be given to each holder of record of Units of Series A Preferred Stock by mailing a copy of such notice to him at his last address as the same appears on the books of the Corporation. Such meeting shall be called for a time not earlier than 20 days and not later then 60 days after such order or request, or, in default of the calling of such meeting within 60 days after such order or request, such meeting may be called on similar notice by any shareholder or shareholders owning in the aggregate not less than 10% of the total number of outstanding Units of Series A Preferred Stock. Notwithstanding the provisions of this paragraph (C)(iii), no such special meeting shall be called during the 60 days immediately preceding the date fixed for the next annual meeting of the shareholders. (iv) During any default period, the holders of shares of Common Stock and Units of Series A Preferred Stock, and other classes or series of stock of the Corporation, if applicable, shall continue to be entitled to elect all the Directors until holders of the Units of Series A Preferred Stock shall have exercised their right to elect, voting as a separate class, two Directors, after the exercise of which right (x) the Directors so elected by the holders of Units of Series A Preferred Stock shall continue in office until their successors shall have been elected by such holders or until the expiration of the default period, and (y) any vacancy in the Board of Directors may (except as provided in paragraph (C)(ii) of this Section 3) be filled by vote of a majority of the remaining Directors theretofore elected by the holders of the class of capital stock which elected the Director whose office shall have become vacant. References in this paragraph (C) to Directors elected by the holders of a particular class of capital stock shall include Directors elected by such Directors to fill vacancies as provided in clause (y) of the foregoing sentence. (v) Immediately upon the expiration of a default period, (x) the right of the holders of Units of Series A Preferred Stock as a separate class to elect Directors shall cease, (y) the term of any Directors elected by the holders of Units of Series A Preferred Stock as a separate class shall terminate, and (z) the number of Directors shall be such number as may be provided for in the Articles or Bylaws of the Company (the "Bylaws"). Any ------ vacancies in the Board of Directors effected by the provisions of clauses (y) and (z) in the preceding sentence may be filled by a majority of the remaining Directors. (vi) The provisions of this paragraph (C) shall govern the election of Directors by holders of Units of Preferred Stock during any default period notwithstanding any provisions of the Articles or the Bylaws to the contrary. (D) Except as set forth herein, holders of Units of Series A Preferred Stock shall have no special voting rights and their consents shall not be required (except to the extent they are entitled to vote with holders of shares of Common Stock as set forth herein) for taking any corporate action. Section 4. Certain Restrictions. (A) Whenever quarterly dividends -------------------- or other dividends or distributions payable on Units of Series A Preferred Stock as provided in Section 2 are in arrears, thereafter and until all accrued and unpaid dividends and distributions, whether or not declared, on outstanding Units of Series A Preferred Stock shall have been paid in full, the Corporation shall not: (i) declare or pay dividends on, make any other distributions on, or redeem or purchase or otherwise acquire for consideration any shares of junior stock; (ii) declare or pay dividends on or make any other distributions on any shares of parity stock, except dividends paid ratably on Units of Series A Preferred Stock and shares of all such parity stock on which dividends are payable or in arrears in proportion to the total amounts to which the holders of such Units and all such shares are then entitled; (iii) redeem or purchase or otherwise acquire for consideration shares of any parity stock, provided, however, that the Corporation may at -------- ------- any time redeem, purchase or otherwise acquire shares of any such parity stock in exchange for shares of any junior stock; (iv) purchase or otherwise acquire for consideration any Units of Series A Preferred Stock, except in accordance with a purchase offer made in writing or by publication (as determined by the Board of Directors) to all holders of such Units. (B) The Corporation shall not permit any subsidiary of the Corporation to purchase or otherwise acquire for consideration any shares of stock of the Corporation unless the Corporation could, under paragraph (A) of this Section 4, purchase or otherwise acquire such shares at such time and in such manner. Section 5. Reacquired Shares. Any Units of Series A Preferred Stock ----------------- purchased or otherwise acquired by the Corporation in any manner whatsoever shall be retired and cancelled promptly after the acquisition thereof. All such Units shall, upon their cancellation, become authorized but unissued Units of Preferred Stock and may be reissued as part of a new series of Preferred Stock to be created by resolution or resolutions of the Board of Directors, subject to the conditions and restrictions on issuance set forth herein. Section 6. Liquidation, Dissolution or Winding Up. (A) Upon any -------------------------------------- voluntary or involuntary liquidation, dissolution or winding up of the Corporation, no distribution shall be made (i) to the holders of shares of junior stock unless the holders of Units of Series A Preferred Stock shall have received, subject to adjustment as hereinafter provided in paragraph (B), the greater of either (a) $1.00 per Unit plus an amount equal to accrued and unpaid dividends and distributions thereon, whether or not earned or declared, up until the date of such payment, or (b) the amount equal to the aggregate per share amount to be distributed to holders of shares of Common Stock, or (ii) to the holders of shares of parity stock, unless simultaneously therewith distributions are made ratably on Units of Series A Preferred Stock and all other shares of such parity stock in proportion to the total amounts to which the holders of Units of Series A Preferred Stock are entitled under clause (i)(a) of this sentence and to which the holders of shares of such parity stock are entitled, in each case upon such liquidation, dissolution or winding up. (B) In the event the Corporation shall, at any time after the Rights Declaration Date, (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case the aggregate amount to which holders of Units of Series A Preferred Stock were entitled immediately prior to such event pursuant to clause (i)(b) of paragraph (A) of this Section 6 shall be adjusted by multiplying such amount by a fraction the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. Section 7. Consolidation, Merger, etc. In case the Corporation shall -------------------------- enter into any consolidation, merger, combination or other transaction in which the shares of common stock are exchanged for or converted into other stock or securities, cash and/or any other property, then in any such case Units of Series A Preferred Stock shall at the same time be similarly exchanged for or converted into an amount per Unit (subject to the provision for adjustment hereinafter set forth) equal to the aggregate amount of stock, securities, cash and/or any other property (payable in kind), as the case may be, into which or for which each share of Common Stock is converted or exchanged. In the event the Corporation shall at any time after the Rights Declaration Date (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding Common Stock into a smaller number of shares, then in each such case the amount set forth in the immediately preceding sentence with respect to the exchange or conversion of Units of Series A Preferred Stock shall be adjusted by multiplying such amount by a fraction the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event. Section 8. Redemption. The Units of Series A Preferred Stock shall ---------- not be redeemable. Section 9. Ranking. The Units of Series A Preferred Stock shall ------- rank junior to all other series of the Preferred Stock and to any other class of preferred stock that hereafter may be issued by the Corporation as to the payment of dividends and the distribution of assets, unless the terms of any such series or class shall provide otherwise. Section 10. Amendment. The Articles, including, without limitation, --------- this resolution, shall not hereafter be amended, either directly or indirectly, or through merger or consolidation with any other corporation or corporations in any manner that would alter or change the powers, preferences or special rights of the Series A Preferred Stock so as to affect them adversely without the affirmative vote of the holders of a majority or more of the outstanding Units of Series A Preferred Stock, voting separately as a class. Section 11. Fractional Shares. The Series A Preferred Stock may be ----------------- issued in Units or other fractions of a share, which Units or fractions shall entitle the holder, in proportion to such holder's fractional shares, to exercise voting rights, receive dividends, participate in distributions and to have the benefit of all other rights of holders of Series A Preferred Stock. Section 12. Certain Definitions. As used herein with respect to the ------------------- Series A Preferred Stock, the following terms shall have the following meanings: (A) The term "Common Stock" shall mean the class of stock designated ------------ as the common stock, no par value per share, of the Corporation at the date hereof or any other class of stock resulting from successive changes or reclassification of such common stock. (B) The term "junior stock" (i) as used in Section 4 shall mean the ------------ Common Stock and any other class or series of capital stock of the Corporation hereafter authorized or issued over which the Series A Preferred Stock has preference or priority as to the payment of dividends and (ii) as used in Section 6 shall mean the Common Stock and any other class or series of capital stock of the Corporation over which the Series A Preferred Stock has preference or priority in the distribution of assets upon any liquidation, dissolution or winding up of the Corporation. (C) The term "parity stock" (i) as used in Section 4, shall mean any ------------ class or series of stock of the Corporation hereafter authorized or issued ranking pari passu with the Series A Preferred Stock as to the payment of ---- ----- dividends and (ii) as used in Section 6, shall mean any class or series of capital stock ranking pari passu with the Series A Preferred Stock in the ---- ----- distribution of assets upon any liquidation, dissolution or winding up of the Corporation. 3. The number of shares constituting the Series A Preferred Stock is 5,000,000. 4. None of the Series A Preferred Stock has been issued. We further declare under penalty of perjury under the laws of the State of California that the matters set forth in this Certificate are true and correct of our own knowledge. Date: December 22, 2000 _______________________________ Robert D. Glynn, Jr. Chairman of the Board, Chief Executive Officer, and President _______________________________ Leslie H. Everett Vice President and Corporate Secretary EX-10 6 dex10.txt THE GAS ACCORD SETTLEMENT AGREEMENT EXHIBIT 10 CPUC Promising Gas Options OII 99=07=003 Operational Flow Order (OFO) Settlement Agreement October 20, 1999 ======================================================================= 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 ======================================================================= CPUC Promising Gas Options OII 99-07-003 Operational Flow Order (OFO) Settlement Agreement TABLE OF CONTENTS ----------------- A. Introduction.......................................................... 1 B. Forum for Resolving Future Balancing Issues........................... 3 C. Provisions Designed to Reduce the Number and to Increase the Predictability of OFOs................................................ 4 1. Operational Information........................................... 4 2. Pipeline Inventory Limits......................................... 6 3. Customer-Specific OFOs............................................ 7 4. Cashout Prices.................................................... 9 5. Core Procurement Group Imbalances................................. 10 6. Storage Allocation to Balancing................................... 11 D. Provisions Designed to Reduce the Impact of OFOs...................... 12 1. OFO Notification.................................................. 12 2. Noncompliance Charges During an OFO............................... 12 3. OFO Noncompliance Charge Exemption................................ 13
======================================================================= 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 ======================================================================= October 20, 1999 Page i CPUC Promising Gas Options OII 99-07-003 Operational Flow Order (OFO) Settlement Agreement A. Introduction ------------ The purpose of this OFO Settlement Agreement (Agreement, Settlement, or Settlement Agreement) is to revise Pacific Gas and Electric Company's (PG&E's) operating guidelines and gas tariffs to achieve the following goals: . Improve market access to operational information necessary for the management of gas imbalances on PG&E's system. . Significantly reduce the number of system-wide OFOs on the PG&E system. . Reduce the impact of OFOs on the market. . Revise certain procedures implemented under the Gas Accord, in order to improve system operating efficiency, to clarify criteria used by PG&E in making operational decisions, and to enhance customer interfaces with PG&E's gas operations. . Improve the transparency of operations to improve upon operational signals to the market. . Improve the ability of the market to foresee OFO events. . Maintain the OFO process as both a signal and an incentive to the market to balance supply and demand. This Agreement is entered into by the Settlement Parties, as identified by their attached signatures. This Agreement shall become effective on the first day of the month following the thirtieth day after the date of a California Public Utilities Commission ("CPUC" or "Commission") order approving the OFO Settlement Agreement and shall continue in effect through December 31, 2002. On March 1, 1998, the Northern California natural gas market experienced a dramatic change with the restructuring of services on the PG&E system under a broadly-based settlement known as the "Gas Accord". Many previously-bundled PG&E services were unbundled, providing more choice to marketers, shippers, and end-use customers. PG&E and the Gas Accord settling parties worked to develop the rules and guidelines to operate PG&E's system under the Gas Accord provisions, including the unbundling of pipeline transmission and storage services within Northern California. The Gas Accord is effective through December 31, 2002. Experience under the Gas Accord has indicated that certain adjustments are appropriate, particularly with regard to customer balancing requirements and charges; to issuance of ======================================================================= 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 ======================================================================= October 20, 1999 Page 1 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ OFOs; to whether OFOs are issued on a system-wide or customer-specific basis; and to the operational information provided to the market and to individual shippers. This Agreement represents a settlement on these issues set forth herein in the context of the natural gas strategy (D.99-07-015and I.99-07-003) of the CPUC. Not all of the provisions agreed to herein require tariff changes, and some provisions have already been implemented. Nevertheless, it is important and appropriate to document here all issues where parties have agreed to changes in operating guidelines and procedures. This Agreement does not change the basic principles and structure of the Gas Accord as agreed to by the settling parties to the Gas Accord and as approved by the Commission in Decision 97-08-055. The operating guideline and gas tariff changes included within this Agreement, and made a part hereof, are intended to modify certain limited implementation parameters of the Gas Accord, and the Settlement Parties agree that such revisions are within the original bounds of the Gas Accord structure. This Agreement is a negotiated compromise of operational issues and is broadly supported by parties who are marketers, shippers, wholesale and retail end-use customers, and regulatory representatives. Nothing contained herein shall be deemed to constitute an admission or an acceptance by any party of any fact, principle, or position contained herein, except to the extent that Settlement Parties, by signing this Agreement, acknowledge that they pledge support for Commission approval and subsequent implementation of these provisions. This Agreement is to be treated as a complete package and not as a collection of separate agreements on discrete issues or proceedings. To accommodate the interests of different parties on diverse issues, the Settlement Parties acknowledge that changes, concessions, or compromises by a party or parties in one section of this Agreement necessitated changes, concessions, or compromises by other parties in other sections. This Agreement is intended to quickly resolve specific operating issues. Decision 99-07-015 in R.98-01-011 contains additional proposals or issues related to utility balancing services, imbalance trading, real-time customer usage data, electronic bulletin boards, and other areas. PG&E and the parties are pursuing or intend to pursue settlement discussions of these additional issues. New settlement(s) may result in modifications to some of the provisions contained in this Agreement. As this OFO Settlement simply modifies the implementation of existing operating parameters, PG&E will not seek to recover any costs associated with implementing the provisions of this Settlement Agreement, except under the provisions of Section B, below. This agreement on cost recovery is not a precedent with respect to other settlements, litigation or regulatory cases. ======================================================================= 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 ======================================================================= October 20, 1999 Page 2 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ B. Forum for Resolving Future Balancing Issues ------------------------------------------- 1. The Settlement Parties intend that the provisions contained in this settlement will significantly reduce the number of system-wide OFOs on PG&E's system. The Settlement Parties, through the Gas OFO Forum, intend to monitor the effectiveness of the Settlement measures in reducing the number of OFOs and to address on an ongoing basis, improvements and/or modifications to PG&E's balancing and OFO procedures. Any interested shipper or customer on the PG&E transmission system who may be subject to OFOs may choose to participate in this Forum. 2. If, six months after the effective date of this Settlement, there has not been at least a twenty-five (25) percent reduction in the number of system-wide OFOs during this first six-month period compared to the same period in the prior year(s), PG&E in its next quarterly OFO report (see Section C.1.f), will provide an analysis of why the number of OFOs has not been reduced and propose additional measures to reduce the number of system-wide OFOs in addition to those measures outlined in this OFO Settlement Agreement. PG&E and the other members of the Forum will consider in good faith whether, and how, PG&E's proposed additional measures, as well as any other proposals suggested by other Forum members, should be adopted. 3. The Gas OFO Forum will further explore the following issues: a. The effectiveness of customer-specific OFOs and possible improvements to the procedure outlined in this Settlement, including the need and methodology for changes to the Performance Factor set forth in Section C.3.b.(7). b. Whether and how parties who significantly contribute to system-wide OFOs on a repeated basis, e.g. to three (3) or more per month, should be specifically identified. A "significant contributor" is defined as any balancing entity with total imbalances greater than 5,000 Dth and 10 percent of its usage in the three days leading up to each system-wide or customer-specific OFO. For Core Procurement Groups, supply will be compared to their Determined Usage, which is the Cumulative Imbalance (except for OFO days when the 24-hour forecast will be used). c. Whether the exemption for OFO noncompliance charges set forth in Section D.3.b should be increased. d. The need for the allocation of additional storage to balancing (see Section C.6). e. Changing the Cash-out procedures. f. Other issues which relate to PG&E pipeline balancing and OFOs. 4. PG&E may seek recovery of implementation costs to provide additional information or implement additional procedures which are recommended by the Forum. Estimates of these costs will be provided to the Forum for discussion prior to PG&E filing for recovery. PG&E may seek such recovery and/or establishment of a balancing or memorandum account for these projected costs prior to implementing the recommendation. Other parties to this Settlement do not necessarily support PG&E's right to recover these implementation costs. ======================================================================= 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 ======================================================================= October 20, 1999 Page 3 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ C. Provisions Designed to Reduce the Number and to Increase the Predictability --------------------------------------------------------------------------- of OFOs ------- 1. Operational Information a. PG&E will provide the following daily operational information on its Pipe Ranger Web site. (1) Composite system temperature (2) System demand (3) Off-system deliveries by delivery point (4) Fuel and lost and unaccounted for (LUAF) gas (5) Storage injection by storage operator (6) Total system demand (sum of items 2, 3, 4, & 5 above) (7) Interconnect supply by receipt point (8) Storage withdrawal by storage operator (9) Total system supply (sum of items 7 & 8 above) (10) Pipeline inventory change (supply minus demand, item 9 - item 6) (11) Beginning and ending pipeline (12) Pipeline inventory lower and upper operating limits (as established in this agreement) (13) Difference between ending pipeline inventory and operating limits (14) Operational flow order (OFO), emergency flow order (EFO) and involuntary diversion status (15) Storage activity by injection and withdrawal, not just net activity (16) Storage injection and withdrawal used for pipeline balancing (17) On-system supply b. Forecast information specified in C.1.a, above, will be provided for the current day and the next three days. This forecast is updated approximately five times per day. PG&E will establish specific not-later-than times of the day when the updates will occur. If for some reason the data is not available by this time, PG&E will place a notice on its Pipe Ranger Web site indicating when the forecast data will be available. c. Historical data will be provided for the prior two weeks. d. Additionally, PG&E will provide on its Pipe Ranger Web site: (1) Maximum pipeline capacity by path. (2) Maximum daily pipeline capacity at interconnection points for current day and next day. (3) Monthly demand forecast by customer class. (4) Daily storage inventory level for pipeline balancing as part of the three-day historical data (updated monthly to reflect cashouts and other adjustments). ======================================================================= 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 ======================================================================= October 20, 1999 Page 4 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ (5) Current month imbalance gas in storage. (6) Receipt point allocation and end-user curtailment quantities for the system when pipeline operational conditions requires allocations (trimming for balancing purposes) or end-user curtailment. Customer-specific data will only be provided to that customer or their designated agent. (7) Daily demand by customer class using the "24-hour forecast" with a three-day posting lag. (8) Daily demand by customer class using the day-after forecast with a three-day posting lag. (9) Balance of cash-in/out gas in storage and prior month imbalances not cleared on a monthly basis. (10) Cumulative sum of the changes in pipeline inventory (line pack). e. PG&E will maintain records of daily injection and withdrawal and daily storage inventory levels for all storage accounts. f. PG&E will post a quarterly OFO report on its Pipe Ranger Web site pertaining to the number and causes of each customer-specific and system-wide OFO, EFO, and "trimming" occasion ("Event") within the prior three (3) months. PG&E will post this report within 30 days after the close of the calendar quarter. The first OFO report may cover less than three months of operation under this Agreement. These quarterly OFO reports will show the sources of system imbalance for each of the three (3) days prior to an Event, as follows: 1) Imbalance and gas scheduled for each entity responsible for managing imbalances as specified in C.3.b.(3). For Core Procurement Groups, the supply will be compared to their Determined Usage, which is their Cumulative Imbalance (except for OFO days when the 24-hour forecast will be used). Each such entity will be identified by a new and unique numerical identifier, and not by name. 2) Pipeline imbalances. 3) Net market center imbalances for the aggregate of parking, lending and storage services. 4) Pipeline balancing provided by allocated storage. 5) Beginning, ending and change in pipeline inventory. 6) Any proposed changes to any OFO and balancing procedures and/or methodology addressed in this Settlement. g. The Settlement Parties agree that for a period continuing until twelve (12) months after the date this Settlement is filed with the CPUC, the operational information provided herein is the information needed for the market to analyze the status of PG&E's pipeline balancing service and to anticipate OFOs. During this period, PG&E need not provide additional data relevant to OFOs, except as referenced in Section B.3.b or as agreed to by PG&E and the other Settlement Parties. After this 12 month period, the other Settlement Parties reserve their rights to bring to PG&E ======================================================================= 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 ======================================================================= October 20, 1999 Page 5 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ requests for further information, and PG&E agrees to engage in good faith efforts to resolve such requests. The limitation on information contained in this section does not limit, in any manner, information requests pertaining to other matters, e.g. electronic bulletin boards, imbalance trading, curtailments (local or system-wide), secondary markets, capacity rights, and/or any other issue contained in I.99-07-003 or a separate CPUC proceeding. h. No tariff changes are needed to revise the operational information provided. 2. Pipeline Inventory Limits a. PG&E will adjust its current procedures for determining when an OFO is needed and for issuing an OFO. PG&E will issue an OFO for a Gas Day if, on the day prior to this Gas Day, PG&E's forecast of pipeline inventory for the Gas Day is either below the Lower Pipeline Inventory Limit or above the Upper Pipeline Inventory Limit, as provided in Sections C.2.c through f below. PG&E will continue its current practice of determining the need for and issuing of an OFO by 7:30 a.m. on the day before the Gas Day, or as soon as possible thereafter. This practice is intended to allow parties whose imbalances exceed the OFO tolerance band to use all four nomination cycles, as specified in Gas Rule 21, Section B.3.d, to make supply adjustments and avoid or reduce noncompliance charges. Situations may still occur when an OFO needs to be issued later in the day prior to Gas Day as is allowed by Gas Rule 14, Section E. b. The Lower and Upper Pipeline Inventory Limits are the levels below and above which the safety and reliability of pipeline operations are in jeopardy. These Limits replace the desired target inventory levels and the range of 200 MMcf/d above and the 150 MMcf/d below as currently specified in Gas Rule 14. This change allows the pipeline to operate to the operational limits each day, without anticipating trends in what suppliers schedule relative to market demand. c. The Lower and Upper Pipeline Inventory Limits will change, as specified in Section C.2.d, below, depending on whether the forecast of total system demand (the sum of on-system demand and off-system deliveries) is "Low" or "High". The reason for the change in the Pipeline Inventory Lower Limit is that under low system demand, the required minimum pressures on the system can be maintained at a lower pipeline inventory level. Higher demand levels require higher pipeline inventories to maintain system minimum pressures. The Upper Pipeline Inventory Limit is set to allow for variations in supply or usage forecasts. Under low system demand conditions, the potential is greater that forecast variations must be absorbed by the pipeline inventory; therefore, the Upper Pipeline Inventory Limit is set lower to allow for this greater variability without jeopardizing operations. Under higher system demand conditions, forecast variations are often managed by supply or storage withdrawal adjustments, so the Upper Pipeline Inventory Limit can be set higher. ======================================================================= 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 ======================================================================= October 20, 1999 Page 6 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ d. The Pipeline Inventory Limits used to determine OFOs are: Pipeline Inventory Limits, MMcf ------------------------------- Total Demand Forecast, MMcf Lower Upper --------------------------- ----- ----- Low Demand: 1,500 to 2,800 3,900 4,500 High Demand: 2,800 to 3,900 4,000 4,600 e. PG&E may elect not to issue an OFO for a Gas Day if the forecast of pipeline inventory for the day following that Gas Day indicates the pipeline inventory will return to within the Pipeline Inventory Limits without the assistance of an OFO. f. The Lower and Upper Pipeline Inventory Limits in effect each day will be shown in the pipeline inventory report on the Pipe Ranger Web site. g. PG&E may revise these Pipeline Inventory Limits beyond those specified in the table in Section C.2.d above. Any such revisions will be established to ensure pipeline safety and reliability. (1) Changes in the Pipeline Inventory Limits which are needed to reflect operating conditions or limitations, including force majeure events, can be implemented immediately as those conditions warrant. PG&E will post these changes on its Pipe Ranger Web site along with an explanation of the operational limitation. (2) Pipeline Inventory Limits may also change due to more predictable factors. These include changes in end-user demands, compressor operating conditions, pipeline and compressor maintenance activities, and other operational inputs which are used to determine the physical operating limits of the pipeline. PG&E will post these changes on its Pipe Ranger Web site at least two weeks before implementation, along with a supporting explanation. (3) If PG&E proposes to change the methodology used to decide when to issue OFOs, PG&E will seek approval of such modifications from the Gas OFO Forum before making this change. 3. Customer-Specific OFOs a. PG&E's Gas Rule 14, Section E, currently provides for customer-specific OFOs to be issued. Since April 1, 1998, PG&E has issued several customer-specific OFOs when it was clear that a limited number of large customer imbalances were the main contributors to the system imbalance. To be more effective, a better definition of the guidelines for issuing customer-specific, or targeted, OFOs is needed. b. PG&E will use the following process and criteria to determine when to issue customer-specific OFOs, rather than a system-wide OFO, and to determine which balancing entities are subject to the customer-specific OFO. (1) PG&E determines whether an OFO is needed for a Gas Day, as described in Section C.2, Pipeline Inventory Limits. (2) If an OFO needs to be issued, the on-system imbalance is estimated for that OFO Day as the difference between the forecast on-system supply and on-system demand. A portion of this imbalance can be accommodated by (i) the ======================================================================= 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 ======================================================================= October 20, 1999 Page 7 CPUC Promising Gas Options OII 99-07-003 OFO Settlement Agreement - ------------------------ amount of pipeline inventory available within the Pipeline Inventory Limits, plus (ii) the storage injection or withdrawal capacity available for system load balancing. This portion of the imbalance that can be accommodated is divided by the forecast on-system demand to determine the OFO Tolerance Band (set as a percentage of usage). The remaining imbalance is the volume of needed supply and/or demand relief for the pipeline to stay within its Inventory Limits. (3) Next, PG&E prepares an internal imbalance report forecasting the OFO Day imbalance for each entity responsible for managing imbalances. These "balancing entities" are: (a) Noncore Balancing Aggregation Agreement (NBAA) agents; (b) Core Procurement Groups (CPGs); and (c) Individual end-users who do not have an NBAA agent. (4) These balancing entity forecasts are composed of the same individual end-use customer demand forecasts that are used to forecast OFO compliance on INSIDEtracc. No change is proposed in these methods. (5) PG&E then reviews the internal imbalance report and identifies those balancing entities with forecast imbalances exceeding both the calculated OFO Tolerance Band percentage and an imbalance volume of 5,000 Dth. (6) Customer-specific OFOs will be issued, if (i) there are no more than 10 balancing entities, and (ii) the total forecast imbalance relief they would provide in aggregate, multiplied by a Performance Factor, exceeds the volume relief needed for the pipeline, as calculated in Section C.3.b.(2), above. (7) The customer-specific OFO Performance Factor is a measure of the historic effectiveness of these OFOs. Experience shows that balancing entities issued an OFO may trade gas to get within the tolerance band. However, such traded gas is still on the system and does not help offset pipeline inventory levels, since there is usually not an accompanying change in demand under these circumstances. Therefore, the resulting pipeline inventory relief provided may be less than forecast. The Performance Factor is the system relief actually achieved by customer-specific OFOs divided by the forecast relief calculated per Section C.3.b.(6) above. Adjustments may be made to the calculation to reflect experience over several customer-specific OFOs and to normalize for such factors as temperature differences between the forecast and actual data. The Performance Factor may differ depending on whether it is a high or low inventory OFO situation. The Performance Factor is set initially at 100% for both high and low inventory conditions. PG&E may adjust the Performance Factor. The Performance Factor will not be adjusted to a percentage which is less than the average of the actual performance for all customer-specific OFOs since the effective date of this Settlement. However, unless required by operational conditions, PG&E will not reduce the Performance Factor below 50% without the prior consent of the Forum. PG&E will post the changes to the Performance Factor, along with supporting data and explanation within 14 days of each customer-specific OFO. If a customer-specific OFO is issued within this 14-day period, the Performance Factor currently in effect will be ======================================================================= 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 ======================================================================= October 20, 1999 Page 8 CPCU Promising Gas Option OII 99-07-003 OFO Settlement Agreement - ------------------------ used. This information will be evaluated by the Gas OFO Forum on an ongoing basis. (8) In the event the conditions of Section C.3.b.(6) are not met, a system-wide OFO will be issued. (9) On occasion, even if the conditions of Section C.3.b.(6) are met, operating experience or market conditions may indicate to PG&E that customer-specific OFOs will not be effective in achieving needed pipeline inventory relief. In these instances, a system-wide OFO will be issued. If the conditions of Section C.3.b.(6) are met, yet PG&E calls a system-wide OFO, PG&E will post an explanation of the factors causing PG&E to determine not to call a customer-specific OFO on its Pipe Ranger Web site, and will include such information in its quarterly OFO reports. c. PG&E will post a general market notification of customer-specific OFOs on its Pipe Ranger Web site by 7:30 a.m. PT on the day before Gas Day, or as soon as possible thereafter, and will notify the affected balancing entities by 8:00 a.m. PT, or as soon as possible thereafter. d. No tariff revisions are needed to reflect the operating guidelines set forth above for issuing customer-specific OFOs. 4. Cashout Prices a. The Gas Accord Settlement provides that: "The intent of imbalance cashouts is to create an economic disincentive for incurring cashout imbalances. PG&E will file to revise the imbalance charges and cashout options if the Gas Accord provisions do not accomplish this." (D.97-08-055, Appendix 1, E.13.d.vii, page 26) At least three times since the beginning of the Gas Accord, the underdelivery cashout price was lower than the spot price, providing the market with an incentive to cash-out rather than avoiding or trading imbalances. This has occurred only for Tier I commodity cashouts where the cashout price is either 95% or 105% of the weighted market price. In these cases, certain marketers arbitraged this cashout price by buying the gas from PG&E as provided in Schedule G-BAL. b. The commodity cashout price will be changed for Tier I Cashouts in Schedule G-BAL to 75% (from 95%) of the Weighted Overdelivery Index and to 125% (from 105%) of the Weighted Underdelivery Index. c. Commodity cashout transactions will continue to be recorded in the Balancing Charge Account (BCA). ======================================================================== 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 ======================================================================== October 20, 1999 Page 9 CPCU Promising Gas Option OII 99-07-003 OFO Settlement Agreement - ------------------------ 5. Core Procurement Group Imbalances a. Core Procurement Groups (CPGs), which include PG&E's Core Procurement Department, serve residential and small commercial customers whose meters do not generally provide daily usage data. Their cumulative usage over a "cycle" period is read at the meter and recorded in a PG&E data base. They are also billed on this cycle basis, not on a calendar month. Since cycles overlap months, two cycles of meter data are needed to calculate a given calendar month's meter use for these customers. b. Recognizing these data limitations, certain provisions were implemented as part of the Gas Accord so that CPGs could manage their daily and monthly imbalances like the other marketers, shippers and noncore customers. One of these provisions was the Core Load Forecasting and Determination Service, which forecasts the upcoming Gas Day usage for each CPG 24 hours and 48 hours prior to the Gas Day, as well as provides a usage estimate on the morning of the Gas Day. The CPG usage estimate provided on the Gas Day itself is called the Determined Usage. The Determined Usage is used by PG&E to determine two monthly imbalances for each CPG: the Cumulative Imbalance and the Operating Imbalance. (1) Cumulative Imbalances are the monthly accumulation of each day's scheduled supply less Determined Usage. Cumulative Imbalances are calculated at the end of each month and may be traded, cashed-out or carried over to the subsequent month. (2) Operating Imbalances are the difference between calendar month Determined Usage and metered usage. Metered usage for a calendar month is calculated by the appropriate weighting of the measured cycle usage. An Operating Imbalance Statement for a particular month is normally provided to customers two months following the processing of the Cumulative Imbalance Statement for the same month. This added time is necessary to collect and process the billing cycle usage data needed to calculate the indicated calendar month usage. These Operating Imbalances may be traded into or out of storage, traded with other customer Operating Imbalances for the same calendar month, or under current provisions, carried over to the month following the date on which the Operating Imbalance Statement is issued. c. To allow more flexibility in managing their total imbalances, CPGs will now be able to trade Operating Imbalances with any Cumulative Imbalances issued in the same month. The trading between Cumulative and Operating Imbalances is subject to the following rules: (1) Trades must occur in the regular monthly Cumulative Imbalance trading period. (2) Trades must move the total Operating Imbalance towards, but not past, zero. d. Accounting adjustments for CPGs as provided in Schedule G-BAL will be included in their Operating Imbalance Carryover. ======================================================================== 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 ======================================================================== October 20, 1999 Page 10 CPCU Promising Gas Option OII 99-07-003 OFO Settlement Agreement - ------------------------ e. Currently, any Operating Imbalance remaining after the Trading Period normally becomes the first gas through the meter in the month following the trading period. Since an imbalance repayment has no offsetting demand and can be relatively large, it is important to spread these deliveries out over a longer period of time so the impact on pipeline balancing and the possible need to issue OFOs is minimized. This also allows positive and negative Operating Imbalances to offset each other over time. Therefore, the following process is adopted for CPGs to repay untraded Operating Imbalances over approximately a one-year period: (1) An Operating Imbalance Carryover account is established to accumulate (credit) and repay (debit) the untraded monthly Operating Imbalances. (2) Each month, following the trading period, the untraded Operating Imbalance is credited to the Operating Imbalance Carryover. (3) Each month, one-twelfth (1/12) of the Operating Imbalance Carryover at the end of the prior month will be considered the first transaction for that CPG and will be debited to its Operating Imbalance Carryover. (4) A CPG may also make a monthly election to clear its entire Operating Imbalance Carryover if it is less than 5,000 Dth. This will be considered the first transaction during the calendar month following PG&E's receipt of written notification, and will set the Operating Imbalance Carryover to zero. f. PG&E will continue to provide customers with information on the basic assumptions and methods used to develop demand forecasts for Core Procurement Groups. PG&E will also continue to assess and implement appropriate and cost-effective modifications to its forecasting processes, with the objective of reducing Operating Imbalances. 6. Storage Allocation to Balancing a. Settlement Parties agree that no additional storage assets will be allocated to balancing at this time. Parties may agree in a future settlement to either add or reduce the amount of PG&E storage assets allocated to system balancing. b. PG&E will provide the Settlement Parties, no later than the date initial testimony is due in I.99-07-003, with a report which describes the cost of adding and/or allocating additional storage assets to system balancing. This storage report will include the cost of each component (inventory and compressors), the anticipated effect on operations and OFOs, and the effect on rates. ======================================================================== 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 ======================================================================== October 20, 1999 Page 11 CPCU Promising Gas Option OII 99-07-003 OFO Settlement Agreement - ------------------------ D. Provisions Designed to Reduce the Impact of OFOs ------------------------------------------------ 1. OFO Notification a. PG&E will continue to notify the market of system-wide and customer-specific OFOs as soon as practically possible. Primary notice will continue to be posted on INSIDEtracc. Notice will also continue to be provided on PG&E's Pipe Ranger Web site. In addition to electronic mail and/or a FAX for OFO notification, customers may now also sign up to receive an alpha page, which replaces the less effective "blast-paging." b. PG&E currently provides the following information to the market for system-wide OFOs: (1) Date of the OFO. (2) Tolerance Band in percent. (3) Stage (i.e., 1, 2, 3, or 4) as established in this Agreement. (4) Noncompliance Charge in $ per therm. (5) Reason (i.e., High or Low pipeline inventory). c. No tariff changes are needed to reflect these adjustments to PG&E's OFO notification options or procedures. 2. Noncompliance Charges During an OFO a. Experience with OFOs has indicated that some customers tend to over-adjust their supply (and sometimes demand) in order to minimize the risk of being outside the tolerance band and subject to an OFO noncompliance charge. The objective in issuing an OFO is to match the market reaction to the system need for imbalance relief, and thereby permit the system to stay within operating limits. A lower noncompliance charge which is closer to the movement of commodity prices in the market should encourage parties to more accurately adjust their supplies to their expected demand under most OFO conditions. b. PG&E still retains the option under the tariffs of commencing an OFO at a higher stage and noncompliance charge, or even increasing the stage later in the day. c. The noncompliance charge for a Stage 1 OFO will be reduced from $0.10 to $0.025 per therm. Another stage will be added after Stage 1 with a noncompliance charge of $0.10 per therm and a tolerance range up to +/-20%. The table currently included in the Gas Rule 14, Section E, will be revised to the following: Tolerance Band Noncompliance Charge As a % of Usage Dollars Per Therm Stage 1: up to +/-25% $0.025 Stage 2: up to +/-20% $0.10 Stage 3: up to +/-15% $0.50 Stage 4: up to +/-5% $2.50 ======================================================================== 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 ======================================================================== October 20, 1999 Page 12 CPCU Promising Gas Option OII 99-07-003 OFO Settlement Agreement - ------------------------ 3. OFO Noncompliance Charge Exemption a. Currently, some customers have difficulty in complying with OFOs because the gas market generally requires gas commodity purchases in packages of at least 5,000 Dth per transaction, or charges a premium for "small or odd lot" deals. b. All balancing entities will be exempt from OFO noncompliance charges if their total monthly OFO noncompliance charges are equal to or less than $1,000. This noncompliance charge exemption will allow those customers with small imbalances to avoid making supply or demand adjustments during an OFO, even if their imbalance as a percent of their demand is outside the allowable OFO tolerance band. c. PG&E may prospectively withdraw this exemption or reduce the exemption level if in PG&E's sole judgment this provision contributes to an increase in OFOs. PG&E will provide notice to, and will consult with, the Gas OFO Forum prior to making such a change. d. There shall be no exemptions from noncompliance charges during EFOs or Involuntary Diversions. ======================================================================== 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 ======================================================================== October 20, 1999 Page13 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement January 28, 2000 ======================================================================= Subject to Rule 51 of the CPUC Rules or practice and Procedure. Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal -- --- Rule of Evidence and Section 1152 of the California Evidence Code ======================================================================= CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement Table of Contents -----------------
1. INTRODUCTION........................................................................ 1 2. PROMISING OPTIONS WHICH ARE PUT IN PLACE BY THIS SETTLEMENT AGREEMENT............... 4 2.1 Cost and Rate Separation for Balancing Services [Self-Balancing Options].......... 4 2.2 Electronic Trading of Imbalances [Including Rights]............................... 8 2.3 Re-examine Utility Role in Core Procurement Once a Specified Competitor Market Share Has Been Achieved.......................................................... 13 2.4 Eliminate Core Aggregation Transportation Thresholds After Adoption of Consumer Protection Measures.............................................................. 14 2.5 Unbundle Utility Storage Costs for Core Customers [Served by CTAs]................ 14 2.6 Separate Costs and Rates for Core Utility [Procurement] Services. Treat Utility Core Procurement Departments as Any Other Utility Customer....................... 18 2.7 Provide Details of Completed Transactions......................................... 19 2.8 Establish a Secondary Market [Trading System] via a Utility Electronic Bulletin Board............................................................................ 19 2.9 Provide Real-Time, Customer-Specific Usage Data................................... 20 2.10 Provide Competitive Metering Technologies......................................... 22 2.11 Provide Competitive Billing Options to Customers Similar to Those Offered in the Electric Industry................................................................ 25 3. PROMISING OPTIONS ALREADY IN PLACE FOR PG&E......................................... 27 3.1 Create Firm Tradable Intrastate Transmission Rights............................... 27 3.2 Establish a Secondary Market for Intrastate Transmission Capacity................. 27 3.3 Place the Utility At Risk for Unused [Transmission] Resources..................... 27 3.4 Create Firm, Tradable Storage Rights.............................................. 28 3.5 Establish a Secondary Market For Intrastate Storage Capacity...................... 28 3.6 Place the Utility At-Risk for Unused [Storage] Resources.......................... 28 3.7 Separate Utility Hub Services From Procurement Functions.......................... 29 3.8 Unbundle Utility Interstate Capacity Costs for Core Customers..................... 29 3.9 Eliminate Core Subscription Service............................................... 29
i January 28, 200 ======================================================================= Subject to Rule 51 of the CPUC Rules or practice and Procedure. Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal -- --- Rule of Evidence and Section 1152 of the California Evidence Code ======================================================================= CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement Table of Contents (continued) ----------------------------- 4. PROMISING OPTIONS AND OTHER ISSUES WHICH ARE NOT TO BE LITIGATED PENDING FURTHER SETTLEMENT DISCUSSIONS............................................................. 30 4.1 Develop Clear Procedures for Allocating [Firm] Capacity.......................... 30 4.2 Revise PG&E's Transmission Interconnection Policy, Terms and Conditions (Not an Appendix C Item)................................................................ 30 4.3 Revise PG&E's Electric Generation Rate Design (Not an Appendix C Item)................................................................ 30 4.4. Review PG&E's Local Transmission Reliability, Design Standards and Curtailment Provisions (Not an Appendix C Item)............................................. 30 4.5 Investigate Mechanisms to Reduce the Costs of Transmission Service for Noncore Customers Connecting To or Located Close To PG&E's Backbone Transmission Facilities (Not an Appendix C Item)............................................ 31 5. PROMISING OPTIONS WHICH WERE SETTLED IN THE OFO SETTLEMENT AGREEMENT............... 31 5.1 Examine Strategies for Devoting More Assets to PG&E Balancing.................... 31 5.2 Implement Targeted Operational Flow Orders....................................... 31 5.3 Provide Pipeline Operator Demand Forecasts Broken Down by Customer Class.................................................................. 32 6. NO ISSUES REMAIN TO BE LITIGATED IN I.99-07-003.................................... 32
ii January 28, 2000 ======================================================================= Subject to Rule 51 of the CPUC Rules or practice and Procedure. Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal -- --- Rule of Evidence and Section 1152 of the California Evidence Code ======================================================================= CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement ------------------------------------------ 1. INTRODUCTION 1.1 Purpose: The purpose of this Comprehensive Gas OII Settlement Agreement ("Settlement Agreement") is to address the most promising options and other issues presented in Investigation (I.)99-07-003. Specifically, the goal of this Settlement Agreement is to resolve all PG&E issues that would otherwise be litigated in I.99-07-003. 1.2 Parties: This Settlement Agreement is entered into by the Settlement Parties ("Parties"), as identified by their attached signatures. Parties agree to actively support this Settlement Agreement in I.99-07-003 and to not oppose any provision of this Settlement Agreement in any regulatory, legislative or judicial forum. Parties agree that this Settlement Agreement is consistent with the provisions of AB 1421. 1.3 Background: In Decision (D.)99-07-015, the California Public Utilities Commission ("CPUC" or "Commission") identified a number of promising options for continued restructuring of the California natural gas industry. These options were summarized in Appendix C of that decision. This Settlement Agreement uses the Appendix C notation for reference. 1.4 Commission Directive: In her ruling of November 5, 1999, Administrative Law Judge Andrea L. Biren directed parties to file a settlement of all or some of the issues in this docket by January 28, 2000. In the absence of a complete settlement, Parties were directed to file prepared testimony on all non-settled issues by March 7, 2000. 1.5 Summary of Agreement and Conditions: This Settlement Agreement settles all of the issues raised by the most promising options being investigated in I.99-07-003. No issues require further litigation in this proceeding for PG&E. This Settlement Agreement distinguishes between promising options being put in place, those already in place on the PG&E system, those being negotiated elsewhere, and those addressed in the OFO Settlement filed with the Commission on October 22, 1999. The Gas Accord, as approved by the Commission in D.97-08-055, will continue through December 31, 2002, and is only modified as specifically agreed to in this Settlement Agreement, subject to future decisions by the CPUC. PG&E agrees to initiate post-Gas Accord settlement discussions promptly following the Commission's approval of this Settlement Agreement. This Settlement Agreement is a negotiated compromise and is broadly supported by parties who are marketers, gas suppliers, shippers, wholesale and retail end-use customers, storage operators and regulatory representatives, as well as the Coalition of California Utility Employees. Nothing contained herein shall be deemed to constitute an admission or an acceptance by any party of any fact, principle, or position contained herein, except to the extent that Parties, by signing this Settlement Agreement, acknowledge that they pledge support for Commission approval and subsequent implementation of all these provisions. ======================================================================= Subject to Rule 51 of the CPUC Rules or practice and Procedure. Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal -- --- Rule of Evidence and Section 1152 of the California Evidence Code ======================================================================= Page 1 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ This Settlement Agreement is to be treated as a complete package and not as a collection of separate agreements on discrete issues or proceedings. To accommodate the interests of different parties on diverse issues, the Parties acknowledge that changes, concessions, or compromises by a party or parties in one section of this Settlement Agreement necessitated changes, concessions, or compromises by other parties in other sections. All Parties' obligations under this Settlement Agreement are conditioned upon the CPUC issuing a decision approving this Settlement Agreement without modification. If the CPUC modifies the Settlement Agreement, each party reserves the right to withdraw its support for the Settlement Agreement. 1.6 Cost Recovery: PG&E will recover $700,000 in costs from customers/ratepayers to implement and maintain the following provisions of this Settlement Agreement. If costs exceed this amount, they will be borne by PG&E. Section 2.1 Cost and Rate Separation for Balancing Services [Self-Balancing] Section 2.2.2 Anonymous Monthly Imbalance Trading Section 2.2.3 Trading OFO Day Imbalance Rights Section 2.8 Secondary Market Electronic Trading System Upon approval of this Settlement Agreement, PG&E will debit the specified amount of $700,000 to the Balancing Charge Account (BCA). This debited amount will not be subject to a reasonableness review by the Commission. Also as provided in Sections 2.2.2.3.6, 2.2.3.5 and 2.8.4 below, PG&E will credit the BCA with a portion of the transaction fees received from certain trading activities. 1.7 Implementation and Term: Within 60 days of a Commission decision approving this Settlement Agreement without modification, PG&E shall file an advice letter in compliance with that decision. In order to facilitate the implementation of the Settlement Agreement and to enable parties to promptly respond to the compliance advice letter, PG&E agrees to serve the parties in I.99-07-003 with pro forma tariff sheets reflecting the provisions of the Settlement Agreement within 60 days of the filing of this Settlement Agreement. Unless stated otherwise, those provisions of this Settlement Agreement which do not require tariff changes shall become effective upon approval by the Commission. Those provisions requiring tariff changes shall become effective at such time as indicated in a Commission decision, resolution, or letter of approval. This Settlement Agreement shall continue in effect through December 31, 2002, or until such other dates as specified in this Settlement Agreement. 1.8 Implementation Date For Changes Put In Place By This Settlement Agreement Which Affect Core Transportation Agents (CTAs): 1.8.1 PG&E is not be able to provide PG&E-consolidated gas billing for gas-only customers until its billing system replacement project is completed ("Billing Availability Date"). PG&E commits to providing PG&E-consolidated billing for such customers upon completion of its billing system replacement project. Absent unforeseen circumstances, PG&E intends to provide this functionality by no later than the end of 2002 based on PG&E's current project plan. In the event of any unexpected delays, PG&E will notify the Parties of the possible delays as soon as ======================================================================= Subject to Rule 51 of the CPUC Rules or practice and Procedure. Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal -- --- Rule of Evidence and Section 1152 of the California Evidence Code ======================================================================= Page 2 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ is reasonably practical. Parties agree that under AB 1421 and other relevant law, nothing in this Settlement Agreement will require PG&E to offer PG&E-consolidated gas billing for gas-only customers prior to the Billing Availability Date. 1.8.2 The following sections of this Settlement Agreement will be implemented independent of the Billing Availability Date: 2.1 Cost and Rate Separation for Balancing Services [Self-Balancing Option] 2.2.2 Anonymous Monthly Imbalance Trading 2.2.3 Trading OFO Day Imbalance Rights 2.5 Unbundle Utility Storage Costs for Core Customers [Served by CTAs] 2.7 Provide Details of Completed Transactions 2.8 Establish a Secondary Market Electronic Trading System 2.9 Provide Real-Time Customer-Specific Usage Data 2.10 Provide Competitive Metering Technologies 2.11.4 Terminate Information Bill Requirement 2.11.5 Provide Billing Credits For CTA Consolidated Billing 1.8.4 This Settlement Agreement is contingent on a final decision by the CPUC that contains an express finding that under AB 1421 and any other relevant law, nothing in this Settlement Agreement requires PG&E to offer consolidated gas billing for gas-only customers prior to the Billing Availability Date. 1.8.5 If, after approval of this Settlement Agreement, the CPUC or a court issues a decision finding that certain changes resulting from this Settlement Agreement require PG&E to offer consolidated gas billing for gas-only customers prior to the Billing Availability Date, then such changes shall not be made available until the Billing Availability Date, notwithstanding Section 1.8.2 of this Settlement Agreement. ======================================================================= Subject to Rule 51 of the CPUC Rules or practice and Procedure. Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal -- --- Rule of Evidence and Section 1152 of the California Evidence Code ======================================================================= Page 3 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2. PROMISING OPTIONS WHICH ARE PUT IN PLACE BY THIS SETTLEMENT AGREEMENT 2.1 Cost and Rate Separation for Balancing Services [Self-Balancing Options] 2.1.1 Summary of D.99-07-015: The creation of separate, avoidable rates for balancing services might facilitate the entry of competitors who would provide balancing services along with procurement, storage, as well as intrastate and interstate transmission. Cost and rate separation for balancing services might also facilitate the provision of a variety of balancing services on the part of the utility as well as competitors. Examples of such services would include daily balancing with varying tolerance bands and penalties as well as more generous monthly balancing tariffs, with costlier charges. The provision of a daily balancing option may be necessary in order to implement other reforms such as electronic trading of imbalances as well as cost and rate separation for balancing services. The costs and benefits of the daily balancing option should be considered in the next phase of this inquiry. (pp. 38-40, Findings of Fact (FoF) 22, Conclusions of Law (CoL) 8, Appendix C) 2.1.2 Gas Accord Balancing Provisions: 2.1.2.1 Currently, PG&E's pipeline (California Gas Transmission or CGT) provides a limited amount of balancing for customers to manage their differences between supplies and usage caused by a variety of factors, including end-user demand uncertainty, unplanned equipment outages, and price arbitrage. PG&E's pipeline must also manage other imbalances including shrinkage, pipeline- to-pipeline imbalances, California gas production imbalances and imbalances due to forecast error for core loads on the day of gas flow. 2.1.2.2 The resources used by the pipeline for balancing include the gas in the pipelines (called pipeline inventory or linepack) and the firm storage assets assigned to balancing under the Gas Accord. If the pipeline inventory is forecast to exceed operating limits, Operational Flow Orders (OFOs) are issued, which impose daily balancing limits and penalties for that day. If conditions warrant, Emergency Flow Orders (EFOs), involuntary diversions or trimming receipt point deliveries can also be implemented to protect the integrity of the pipeline. 2.1.2.3 Balancing entities are limited to a monthly imbalance of +/-5 percent. After the end of the month, they can trade imbalances outside this range. Following trading, amounts outside +/-5 percent are cashed-out. There are no specific daily balancing limits, except on OFO or EFO days, although customers have daily nomination limits. ======================================================================== 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 ======================================================================== Page 4 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.1.3 Self-Balancing Option Provisions: As part of this Settlement Agreement, PG&E will develop and implement an unbundled daily balancing option, which is called the Self-Balancing option. This option allows customers to receive a credit for a portion of the balancing costs currently bundled in the backbone rate, and is designed to reduce the need for PG&E to make systems changes for accounting, operations and tracking of daily imbalances for a significant number of customers. The following provisions will apply to Self-Balancing. 2.1.3.1 Bundled Balancing: Bundled monthly balancing provided by ----------------- PG&E remains the default balancing service for any customer who does not elect the Self-Balancing option. The intent of the Parties is that the offering by PG&E and the election by customers of the Self-Balancing option will not adversely affect the availability, reliability or cost of bundled balancing, nor will it cause an increase in the frequency of OFOs or EFOs. As provided in Section 2.1.3.8 below, the OFO Forum will monitor these effects, and meet to discuss and resolve concerns if such adverse effects occur. 2.1.3.2 Availability and Election of Self-Balancing Option: The -------------------------------------------------- Self-Balancing option is available to noncore customers, wholesale customers, and core procurement groups (CPGs). For CPGs, a daily forecast of demand will continue to be used to measure daily imbalances, similar to how OFOs are done. PG&E's Core Procurement Department agrees that for the term of this Settlement Agreement it will not elect the Self-Balancing option. Noncore Balancing Aggregation Agreements (NBAAs) may contain either Self-Balancing customers or monthly balancing customers, but not combine Self-Balancing and monthly balancing customers (since the balancing rules which apply to each are quite different). 2.1.3.3 Transmission Rates: All of the costs agreed to be included ------------------ in rates for system balancing in the Gas Accord will continue to be included in backbone transmission rates. 2.1.3.4 Allocation of Balancing Storage Assets: For purposes of -------------------------------------- this Settlement Agreement, through March 31, 2003, eighty percent (80%) of the balancing storage assets are unbundled and made available to the self-balancing option. However, all these storage assets remain with the pipeline unless a customer elects the Self-Balancing option. For these customers, their share of the balancing storage assets will be assigned to and remarketed through PG&E's at-risk unbundled storage program. If a customer elects to return to monthly balancing from Self-Balancing during the annual election period, then the same amount of storage is reassigned back to pipeline balancing. The amount is calculated as a pro rata share of the unbundled balancing storage assets based on the customer's annual average usage as a percentage of PG&E's average annual system usage. 2.1.3.5 Limitations on Self-Balancing Option: The elections for ------------------------------------ Self-Balancing are limited to 50 percent of the total storage balancing assets of 2.2 Bcf of inventory, 50 MMcf per day of injection and 70 MMcf per day of ======================================================================== 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 ======================================================================== Page 5 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ withdrawal. Once this limit is neared or reached, the OFO Forum will meet to consider lifting this cap and whether other adjustments are needed to PG&E's operating parameters to ensure both the integrity of pipeline operations and the benefits to the market of the Self-Balancing option. 2.1.3.6 Credit for Self-Balancing: Those customers and CPGs ------------------------- electing Self-Balancing will receive a credit equal to $0.0050 per decatherm times their actual monthly metered usage. 2.1.3.7 Analysis of Storage Balancing Assets: The Parties agree ------------------------------------ that a first priority for the OFO Forum is to evaluate the level of storage assets made available for pipeline balancing. By February 1, 2001, the OFO Forum will recommend to the Commission whether the amount of storage capacity allocated to balancing service should be revised. If the recommendation is for an increase, the OFO Forum will also recommend the source of this additional firm storage capacity. Possible sources include PG&E's at-risk unbundled storage program, capacity rejected by CTAs pursuant to the provisions of Section 2.5, non-PG&E on- system storage, or some combination thereof. Additionally, the OFO Forum will recommend rate treatment for the costs associated with a recommended change in allocated balancing storage capacity. Parties agree that there will be no decrease in assets dedicated to system balancing (except as provided herein for self-balancing elections), nor rate decreases, during the term of this Settlement Agreement Provision. 2.1.3.8 Monitoring the Effect of Self-Balancing on OFOs: The ----------------------------------------------- Parties, through the OFO Forum, will monitor the response to the Self-Balancing option and the impact on OFOs. After reviewing the data, the OFO Forum may recommend revising the Self-Balancing option and/or pipeline operating parameters. 2.1.4 Self-Balancing Option Terms and Conditions: Customers electing the Self-Balancing option will be subject to the following terms and conditions. 2.1.4.1 Election of the Self-Balancing option is made annually in February and is effective for a minimum term of one year from April 1 through March 31. After the initial year, a customer who previously elected to Self-Balance, may elect back to monthly balancing during the election period. A multi-year election to Self-Balance may also be made, but not extending beyond March 31, 2003. Circumstances may also arise which would require a customer to change its self- balancing election during the year. 2.1.4.2 Customers will be responsible for tracking their own daily imbalance position. PG&E will not be required to provide warnings or other notice, even if a customer is falling outside the prescribed Self-Balancing requirements. 2.1.4.3 Noncore customers must have meters which record daily usage, even if these meters are only read once per month. The cost of adding daily usage recording devices and/or data access is the responsibility of the customer. ======================================================================== 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 ======================================================================== Page 6 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ Small meters (meter capacity less than 100 dth per day) at a customer facility with large hourly recording meters are exempted from the hourly recording requirement and will be included in daily calculations using a forecast of daily usage based on averages derived from monthly data. 2.1.4.4 Daily usage for CPGs electing the Self-Balancing option will be based on a forecast of their customers' gas usage. For CPGs whose demand is smaller than three percent (3%) of the core market (based on annual demand), daily usage will be determined using the first 24-hour forecast available each day. For CPGs whose demand is greater than or equal to three percent (3%) of the core market, daily usage will be determined using an end of the gas day forecast. For any CPG electing Self-Balancing, the applicable daily usage forecast will also be used to calculate its monthly cumulative imbalance available for trading or carry forward as described below in Section 2.1.4.9. If the annual demand of CPGs electing Self-Balancing exceeds ten percent (10%) of the total core market annual demand, then the largest CPG(s) electing to self-balance will have their daily usage determined based on the end of the gas day forecast, such that the sum of the demands for the remaining self- balancing CPGs continuing to use the 24-hour forecast does not exceed the ten percent (10%) limit. The OFO Forum may review and make recommendations to address impacts on OFOs and/or EFOs that may arise due to CPGs electing Self- Balancing. 2.1.4.5 Customers electing the Self-Balancing option will be subject to two imbalance limits each day. 2.1.4.5.1 The daily imbalance cannot exceed plus or minus ten percent (+/-10%) of that day's metered or forecast usage, except on OFO or EFO days; and 2.1.4.5.2 The accumulated daily imbalance cannot exceed plus or minus one percent (+/-1%) of that month's usage. Each month's usage for this purpose will be set prior to the month based on historical usage and forecast patterns. 2.1.4.6 Each balancing entity subject to the Self-Balancing limits specified above is still subject to system-wide and customer-specific OFOs. On those days, the OFO or EFO tolerance band requirements and associated noncompliance charges will be imposed, and the +/-10 percent Self-Balancing requirement will not apply for that OFO or EFO day. However, the accumulated daily imbalance requirement will still apply. 2.1.4.7 PG&E will calculate the daily imbalances after the calendar month for each noncore customer or balancing entity electing this option after processing the applicable meter data. Daily imbalances for CPGs will be based on their daily usage as described in Section 2.1.4.4 above. 2.1.4.8 Noncompliance charges will be calculated for customers electing the Self-Balancing option as the sum of the following, except as provided in Section 2.1.4.8.4, and will be recorded in the Balancing Charge Account (BCA). ======================================================================== 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 ======================================================================== Page 7 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.1.4.8.1 For each non-OFO or non-EFO day, a noncompliance charge equal to $1.00 per decatherm per day for each day when the daily imbalance exceeds +/-10 percent of the daily metered or determined usage. 2.1.4.8.2 For each OFO or EFO day, a noncompliance charge is calculated using the applicable OFO or EFO tolerance level and noncompliance charge. 2.1.4.8.3 For each day including OFO and EFO days, a noncompliance charge equal to $1.00 per decatherm per day for each day when the accumulated daily imbalance exceeds +/-1 percent of the preset monthly usage. 2.1.4.8.4 For each OFO day or EFO day on which a noncore customer or balancing entity electing the Self-Balancing option is exceeding its accumulated imbalance limit in a direction opposite to that of the OFO or EFO situation, there will be no noncompliance charge under Section 2.1.4.8.3 above. For example, under a high inventory OFO, a balancing entity with a negative accumulated imbalance exceeding -1% of its preset monthly usage would not receive a noncompliance charge for this situation. However, if the accumulated imbalance is not corrected to within the +/-1 percent limit on the next non-OFO or non-EFO day, noncompliance charges will apply. 2.1.4.9 Monthly cumulative imbalance trading is allowed. Any gas imbalances remaining after the trading period that are in excess of plus or minus one percent (+/-1%) of the monthly usage will be cashed out at the highest cash-out price indicated in Schedule G-BAL for imbalances in excess of 10%. Any carry forward amount will set the beginning accumulation level for the next month. No daily trading during the month of imbalance position or rights is allowed. However, trading of OFO day imbalance rights (chips) will be allowed as provided in Section 2.2.3 below. 2.1.4.10 Following each annual election period, PG&E will report within 30 days on its Pipe Ranger Web site the percentage (based on annual demands) of the core and noncore markets electing to Self-Balance. Specific customers or entities electing the Self-Balancing option will not be identified. 2.2 Electronic Trading of Imbalances [Including Rights] 2.2.1 Summary of D.99-07-015: The Commission provisionally finds that shippers should be allowed to trade or sell imbalance rights since they pay for a balancing tolerance as a component of their intrastate transmission rates and are entitled to have the plus or minus tolerance on a daily or monthly basis. The trading of imbalance rights would give shippers the ability to adapt to daily balancing rules, where they apply, during a given day's nomination cycles. The Commission finds the concept of imbalance trading to hold sufficient promise to merit further inquiry. The Commission also encourages parties to consider whether a mechanism could be developed to produce the hoped-for benefits versus its costs. (pp. 41-44, FoF 24-26, Appendix C) ======================================================================== 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 ======================================================================== Page 28 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.2.2 Anonymous Monthly Imbalance Trading 2.2.2.1 Current PG&E Platform for Monthly Imbalance Trading: PG&E currently provides a platform on its Pipe Ranger Web site for entities to confirm trades of same month cumulative and operating imbalances. This Internet-based platform allows balancing entities who have negotiated imbalance trades with another balancing entity to inform PG&E of the imbalance trade using the Internet. Basically, one balancing entity electronically enters the results of the negotiated trade, and the other balancing entity confirms the trade. This platform validates whether the confirmed trade is in compliance with the current imbalance trading rules set forth in PG&E's tariff Schedule G-BAL. If not, the trade is rejected. this platform currently does not provide for posting offers to buy or sell monthly imbalances, or for facilitating trading such imbalances. Entities contact each other directly to work out the trade details, including price. 2.2.2.2 Provider of Electronic Imbalance Trading System: PG&E will contract with a Third Party Service Provider (TPSP) to provide anonymous electronic trading of cumulative and operating imbalances, i.e., the trading of actual imbalance gas, not rights. PG&E intends to enter into a sole-source contract with an affiliate of Altra Energy Technologies, Inc. (ALTRA(R)) to provide the monthly imbalance trading platform using their Altrade(R)product. The sole source provision of this contract will be in effect through December 31, 2002. Once PG&E finalizes its contract with ALTRA, a copy of the contract will be provided to the Parties, subject to a confidentiality agreement. At the end of this sole-source period, any other TPSP may provide service in competition with ALTRA. At that time, PG&E will provide a customer service and data interface with all interested TPSPs offering electronic imbalance trading. 2.2.2.3 Principles for Imbalance Trading System: The following principles are agreed to in order to mitigate concerns about the market relying on a sole-source provider during this market development period. 2.2.2.3.1 PG&E will continue to provide its platform for entities to post and confirm monthly imbalance trades without charging transaction fees. 2.2.2.3.2 Use of the anonymous trading platform is voluntary. 2.2.2.3.3 ALTRA is a logical sole-source provider. ALTRA has contracts with about 80% of the entities for gas commodity trading, and is well recognized as an industry leader in building and servicing electronic trading platforms. 2.2.2.3.4 Entities with currently-effective ALTRA contracts will not have to pay added monthly subscription fees. A smaller fixed subscription fee will be made available for those entities who only want to use ALTRA for imbalance trading, and not commodity trading. The monthly subscription fee will be credited against transaction fees up to that amount. Subscription fees are needed in addition to transaction fees because experience is that entities will use the price discovery ======================================================================== 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 ======================================================================== Page 9 January 28, 2000 CPUC Promising Gas Options 1.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ information available on the trading screens to do their own deals outside the trading platform. These deals can then be reported through PG&E's existing platform, thus avoiding transaction fees. 2.2.2.3.5 Each trade will be subject to buyer and to seller transaction fees for each decatherm traded. The transaction fee provides an incentive for ALTRA to encourage trading volume which in turn improves liquidity and price discovery. These fees will be charged in a non- discriminatory manner, but could include tiered pricing. The transaction fees will be capped during the sole-source period. 2.2.2.3.6 PG&E will retain a share of ALTRA's transaction fee which offsets PG&E's transaction and credit costs, as well as reflects the value PG&E brings to this service. The fee sharing will also provide an incentive to PG&E to encourage use of this trading service. The fee shall be established by ALTRA with any revenues shared between ALTRA and PG&E equally. One-half of the PG&E portion of these transaction fees will be recorded as a credit to the BCA to help offset the costs incurred to implement this trading system. PG&E will include the specific fee provisions in its tariffs pursuant to Section 1.7 above. 2.2.2.3.7 ALTRA will operate the trading system and retain ownership of all software. ALTRA will be responsible for all maintenance and operation costs associated with operating the Altrade trading platform. 2.2.2.3.8 PG&E shall not influence, in any way, ALTRA's selection of trading partners, business associations or contracts with any third party operating on the PG&E system, other than in matters of routine credit and nomination capacities envisioned by this Settlement Agreement. 2.2.2.4 System Features for Electronic Imbalance Trading System: The following provisions will be part of the monthly imbalance trading system limitations and features. 2.2.2.4.1 The electronic trading platform will allow a balancing agent to post either a bid to purchase imbalance gas or to post an asking price to sell imbalance gas. Other parties will be able to monitor these postings and accept the posted offer or make a counter-offer. When two parties agree on price, ALTRA will manage the transaction by adding imbalance gas to the Purchaser's account and subtracting imbalance gas from the Seller's account. The Purchaser is then billed for the agreed upon price, and payment is made to the Seller for the same amount. 2.2.2.4.2 Anonymous trading on ALTRA platform will not be required to abide by all the imbalance trading limitations in Schedule G-BAL during the trading period. However, the final summation of the imbalance trades completed on ALTRA's trading platform and those posted on PG&E's platform will be subject to the Schedule G-BAL limitations and cash-out provisions. The limitations include: no trading across months; ========================================================================== 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 ========================================================================== Page 10 January 28, 2000 CPUC Promising Gas Options 1.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ trading cumulative imbalances towards zero; trading results in a cumulative imbalance that is within the range of plus or minus three percent of usage past zero; and trading into or out of on-system storage accounts which have documented inventory gas or space available. 2.2.2.4.3 PG&E and ALTRA will establish an electronic link to transfer data on current account balances and to update these accounts once the imbalance trading period ends. ALTRA will send its trading results to PG&E. PG&E will add additional trades that are confirmed through PG&E's current platform and add trades between storage accounts. The final ending imbalance position for each balancing entity will be used to determine any cashout or carry forward amounts based on the rules in Schedule G-BAL. 2.2.2.4.4 Entities will be subject to trading limitations based on individual credit limits and system operating limitations. PG&E will revise its credit-worthiness requirements in its tariffs to reflect these transactions. PG&E will be responsible for providing ALTRA with these trading limits. ALTRA will not allow an entity to complete a trade if their limit would be exceeded by completing the trade. 2.2.2.4.5 PG&E will accept the credit risk for entities which are PG&E customers approved for this program, including designated marketers, NBaas, and CTas. If a Purchaser accepts a trade and fails to pay its trading position (either buying or selling imbalance gas) when billed by ALTRA, PG&E will guarantee payment to the Seller in the transaction. PG&E will then take collection action against the Purchaser, including late fees and, if appropriate, cashouts in accordance with the G-BAL requirements. 2.2.2.4.6 To encourage additional liquidity, ALTRA may allow market makers that have no imbalances on the PG&E system to participate in imbalance trading. ALTRA will be responsible for credit approval and collection for these market makers, pursuant to its agreement with PG&E. Market makers will be required to have zero imbalances at the end of the trading period. ALTRA may institute additional rules to enforce this requirement and other conditions needed to conduct business. 2.2.2.4.7 On-system, non-PG&E storage facilities may participate under the same terms and conditions applicable to imbalance trading with PG&E's storage and/or market center. ========================================================================== 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 ========================================================================== Page 11 January 28, 2000 CPUC Promising Gas Options 1.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.2.3 Trading OFO Day Imbalance Rights 2.2.3.1 Objectives: PG&E and ALTRA will implement a mechanism to allow trading of imbalance rights for each OFO day using the same electronic platform as for monthly imbalance trading. The objective is to provide balancing entities the opportunity after the fact to reduce or eliminate OFO noncompliance charges, and to create value for those entities who are within the specified OFO day tolerance band. Trading these rights does not change the physical imbalance position of the entity or the pipeline. Trading these OFO day rights also avoids the problem of significant retroactive accounting adjustments which would be needed if physical imbalances for the OFO day were traded. 2.2.3.2 Market Benefits: A daily balancing tolerance level is specified for each day an OFO is called. This tolerance level generally ranges from +/-2% to +/-16%. If a balancing entity has an imbalance outside this tolerance level for that OFO day, it is subject to noncompliance charges. If a balancing entity has an imbalance that is within this tolerance level for that OFO day, that entity receives no benefit for helping the situation. With imbalance rights trading, there is an opportunity for the balancing entity that is below the tolerance level to gain value from this position, while helping the balancing entity outside the tolerance band to reduce their noncompliance charges. 2.2.3.3 Establishing and Trading Imbalance Rights: The approach is to establish imbalance rights, or chips, for each balancing entity for each OFO day, and then to allow the trading of these rights. The following describes this mechanism. 2.2.3.3.1 The imbalance rights or chips are calculated as the difference between the entities' imbalance and the tolerance level on that OFO day. Chips are positive (black) for those entities whose imbalances are within the tolerance level, and negative (red) for those entities that are outside the tolerance level and subject to noncompliance charges. One chip is given for each decatherm of difference. 2.2.3.3.2 Each chip is dated corresponding to a specific OFO day. Chips can only be traded with those of the same date. In other words, imbalances and noncompliance charges cannot be traded between OFO days. Unlike cumulative imbalance trading, gas in storage accounts will not be eligible to create positive chips or to offset a negative chip position during the imbalance rights trading period. Trading between different OFO days and using storage after the gas day occurs would change the incentive of balancing agents to comply with the OFO on that particular day. Trading of chips does not change these incentives to comply with the OFO order. 2.2.3.3.3 Chips are cleared after the month is over. For example, if there were five different OFO days during the previous month, each balancing entity would have five separate trading accounts and associated chips. ========================================================================== 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 ========================================================================== Page 12 January 28, 2000 CPUC Promising Gas Options 1.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.2.3.3.4 For each individual OFO day, entities with positive (black) chips will be able to sell them at a mutually agreed upon price to those entities needing to offset their negative (red) chips. The market would establish the price for positive chips. It is likely that the price to buy positive chips would be much lower than the noncompliance charge if a large number of entities are below the tolerance band and are competing to sell their positive chips. When only a few entities have positive chips for sale, the price would likely be close to the noncompliance charge, but should never exceed the noncompliance charge. 2.2.3.3.5 Those entities with net negative (red) chips remaining after the trading period would be billed for the commensurate noncompliance charges for the related OFO. It is possible, although not likely, that an entity who was physically in balance during the OFO could end up in a negative chip position and pay noncompliance charges. 2.2.3.4 Electronic Trading and Confirmation System: Electronic trading and electronic confirmation of offline trades of OFO day imbalance rights (chip) will be included as part of the sole- source contract with ALTRA, and subject to the terms of that contract. Under this contract, ALTRA and PG&E will establish the necessary interfaces, and ALTRA will provide the necessary screens and trading platform. PG&E will modify its GTS and accounting systems to verify compliance with the trading rules, to record the trades, and to adjust the payments of noncompliance charges accordingly. 2.2.3.5 Electronic Trading Fees: A monthly subscription fee will be required if the customer does not already subscribe to ALTRA. A smaller fixed subscription fee will be made available for those entities who only want to use ALTRA for imbalance rights trading, and not commodity trading. ALTRA will charge a transaction fee to both the buyer and seller performing electronic trading or electronic confirmation of offline trades. This fee will be capped, and any discounts made available on a nondiscriminatory basis. PG&E will receive fifty percent (50%) of these fees, which will be recorded as a credit to the BCA to help offset the costs for implementing this trading system. PG&E will include the specific fee provisions in its tariffs pursuant to Section 1.7 above. 2.3 Re-examine Utility Role in Core Procurement Once a Specified Competitor Market Share Has Been Achieved 2.3.1 Summary of D.99-07-015: The Commission recommends the re-examination of local distribution company core procurement and the default provider function if the market share exceeds 30% of the number of customers, but even at that point the Commission has seen no compelling reason to eliminate local distribution company procurement as an option for customers. (pp. 50-59, Appendix C) 2.3.2 Resolution: Parties agree that there is no need to litigate nor for the Commission to further examine the utility role in core procurement in this proceeding. ====================================================================== Subject to Rule 51 of the CPUC Rules of Practice and Procedure. Rule et seq of the FERC Rules of Practice, Rule 408 of the Federal -- --- Rules of Evidence and Section 1152 of the California Evidence Code ====================================================================== Page 13 January 28, 2000 CPUC Promising Gas Options 1.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.4 Eliminate Core Aggregation Transportation Thresholds After Adoption of Consumer Protection Measures 2.4.1 Summary of D.99-07-015: The Commission believes the lifting of the core aggregation threshold and core participation cap will expand the competitive options available to residential and small commercial customers. In Ordering Paragraph 11, the Commission recommends to the California Legislature that the consumer protection measures proposed by the Commission's Energy Division be immediately adopted by statute. The Commission also recommends that the Legislature provide an exception to Senate Bill 1602 to allow the Commission to remove the current restrictions that limit participation in the utilities' Core Aggregation Transportation programs. The exception would allow the limits to be removed before January 1, 2000, but after the Commission has implemented the appropriate consumer protection measures. (pp. 59-61, FoF 30, Ordering Paragraph (OP) #11, Appendix C) 2.4.2 Market Threshold: Under the Gas Accord, PG&E eliminated the market limit threshold of 10 percent, and no further action is needed. 2.4.3 CTA Participation Threshold: Under the Gas Accord, PG&E reduced the minimum size for core aggregation (CTA) participation from 250,000 to 120,000 therms per year. Parties agree that no change to this threshold is necessary in this proceeding or during the term of this Settlement Agreement. 2.5 Unbundle Utility Storage Costs for Core Customers [Served by CTAs] 2.5.1 Summary of D.99-07-015: The Commission recommends exploration of the unbundling of storage costs for core customers. (p.49) 2.5.2 Current CTA Storage Requirements: Under the Gas Accord, each Core Transportation Agent (CTA) is assigned a pro rata share of the total core allocated storage. This assignment is based on the total historical winter usage of their customers. PG&E's tariff Schedule G-CT requires that CTAs must fill and maintain their allocated storage inventory within specified limits to aid in customer cold weather system reliability. 2.5.3 Unbundling Storage Costs for CTAs: Parties agree to unbundle core storage costs for CTAs during the remainder of the Gas Accord period pursuant to the provisions below. Any further unbundling of storage costs for all core customers will be considered only in the context of the post-Gas Accord structure. 2.5.4 Basic Provisions: The following describes the structure and timing of the CTA storage choice. Final details will be included in the tariff changes needed to implement this program. 2.5.4.1 Core Storage Rate Treatment: As of the effective date of the --------------------------- tariffs implementing this provision of the Settlement Agreement, core storage costs will be recovered from PG&E's Core Procurement Department customers through monthly core procurement rates and from CTAs through monthly fees to the extent they accept an allocation of core storage on ========================================================================== 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 ========================================================================== Page 14 January 28, 2000 CPUC Promising Gas Options 1.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ behalf of their core transport customers, subject to balancing account treatment up to the limits described below. Cost shifts among core customers are to be minimized and no costs are shifted to noncore customers. 2.5.4.2 CTA Storage Allocations: An allocation of storage inventory, ----------------------- injection and withdrawal capacity to CTAs will continue to be calculated in the same manner as is currently provided for in Schedule G-CT. This allocation is based upon the historical total winter throughput of CTA customers and the BCAP-adopted winter throughput of all core customers. A core storage allocation will continue to be calculated each February, based upon the CTA group contracted volumes for the subsequent winter season using the Direct Access Service Requests (DaSRs) that have been processed to date. 2.5.4.3 CTA Option to Accept or Reject Storage Allocations: Each year -------------------------------------------------- between about February 15 and March 1, CTAs will be given the option to accept or reject their Annual Allocation of core storage, for the storage year of April 1 through March 31, in ten percent (10%) increments. CTAs will be able to make adjustments to their annual election for increases or decreases in loads during the Intra-Year Adjustment period described below. 2.5.4.4 Initial Partial Year Option: If tariffs to implement this --------------------------- provision are approved such that implementation can begin on or before December 1, 2000, any CTA may reject all or a portion of its current core storage allocation in ten percent (10%) increments for the April 1, 2000 through March 31, 2001 storage season, subject to the Cap specified in Section 2.5.4.5 below. A CTA rejecting storage must sell the gas from the portion of its storage account that it rejects to PG&E's Core Procurement Department at a weighted average Core Procurement price (Schedule G-CP) for the months that the Core Procurement Department has injected gas during its current or most recent injection season. A CTA must also certify Alternate Resources pursuant to Section 2.5.4.11 below. The PG&E Core Procurement Department's Benchmark under its Core Procurement Incentive Mechanism (CPIM) will be adjusted by adding the costs associated with the purchase of this CTA storage gas. 2.5.4.5 Cap on Rejected Storage Allocations: During the term of this ----------------------------------- Settlement Agreement, the total amount of core storage allocations that can be rejected by all of the CTAs is capped each storage season as follows for inventory, with proportionate injection and withdrawal rights. Storage Season Cap On Rejected Share of Total April 1 - March 31) CTa Storage Core Storage ------------------- ----------- ------------ 2000-2001 1.64 Bcf 5% 2001-2002 3.28 Bcf 10% 2002-2003 4.92 Bcf 15% =========================================================================== 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 =========================================================================== Page 15 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ To the extent that rejected Annual CTA Allocations amount to more than this Cap, the amounts that exceed the Cap will be reassigned to CTAs in proportion to the amounts they have rejected. 2.5.4.6 Accepted and Assigned CTA Storage Allocations: For amounts --------------------------------------------- of capacity that a CTA may accept or have assigned, the CTA will pay PG&E monthly, over the storage year, the revenue requirement associated with accepted and assigned amounts as a proportion of total core storage. CTAs must fill and maintain accepted and assigned storage inventories on an annual cycle as specified in the current tariff under Schedule G-CT. 2.5.4.7 Core Procurement Core Storage Assignment: Amounts of core ---------------------------------------- storage not allocated to CTAs in accordance with Section 2.5.4.2 above, plus rejected CTA Core Storage Allocations up to 1.64 Bcf, will be assigned to PG&E's Core Procurement Department. 2.5.4.7.1 The cost of storage assigned to the Core Procurement Department will be recovered through the procurement portion of core customer bundled rates, subject to balancing account treatment. All storage allocations to the Core Procurement Department are to be treated in the same manner as current Core Procurement Department storage allocations in the CPIM. 2.5.4.7.2 The Core Procurement Department will fill and maintain inventory for this assignment according to the terms currently specified by the CPIM for amounts now allocated to the Core Procurement Department. 2.5.4.8 Disposition of Rejected Core Storage Allocations Above 1.64 ----------------------------------------------------------- Bcf: Core storage inventory allocations rejected by CTAs --- above 1.64 Bcf will be allocated to PG&E's at-risk unbundled storage program. 2.5.4.9 Intra-Year Rules - Increase In Load: In August of each ----------------------------------- year, based upon the CTA group contracted volumes for the upcoming winter season using the Direct Access Service Requests (DASRs) that have been processed to date, PG&E will recalculate the pro rata CTA storage allocations and compare this new calculation with the Annual Storage Allocation calculated at the beginning of the current storage season. If a CTA's allocated share of storage inventory has increased by more than 100,000 therms, the CTA must choose whether to accept an increased allocation for any portion of the incremental change, in ten percent (10%) increments. This election must be made between August 15 and September 1. 2.5.4.9.1 For amounts that the CTA accepts of these incremental storage rights, gas in the Core Procurement Department's storage account will be transferred to the CTA storage account at a price that reflects a weighted average Core Procurement (Schedule G-CP) price for the months of April through October times an injection schedule for the Core Procurement Department (Schedule G-CT will be modified in this way for all gas-in-storage transactions). The CTA will also pay ======================================================================== 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 ======================================================================== Page 16 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ the total cost of this storage capacity for that year in payments over the remainder of the storage year. 2.5.4.9.2 For amounts that the CTA rejects of this offered storage, Alternate Resources, in like amount, will be required as described in Section 2.5.4.11 below. Rejection of offered storage is subject to the Cap for the current storage season. To the extent rejected capacity exceeds the Cap during the intra-season election, the right to reject storage will be pro rated among those rejecting storage capacity at this time. 2.5.4.10 Intra-Year Rules - Decrease In Load: If the mid-year ----------------------------------- evaluation, described in Section 2.5.4.9 above, results in a decrease of more than 100,000 therms in the amount of storage inventory that would be allocated to a CTA, and the CTA has accepted a storage allocation, the CTA must transfer to the Core Procurement Department a share of its reduced allocation in a proportion equal to the percentage of its Annual Allocation that it accepted for the year. For instance, consider a CTA whose Annual Allocation was 400,000 therms, and it accepted 300,000 therms, or three-quarters of its allocation. If this CTA's mid-year Allocation was 250,000 therms, three-quarters, or 112,500 therms of the 150,000 therm reduced allocation would be transferred to the Core Procurement Department. The gas in storage will also be transferred to Core Procurement Department, which will pay the CTA for the storage and gas on the same terms described in Section 2.5.4.9 above, to the extent that the total rejected capacity has been reduced. 2.5.4.11 CTA Certification of Alternate Resources: A CTA rejecting ---------------------------------------- all or part of a PG&E core storage allocation, must certify to PG&E no less than ten business days before each winter month that it has sufficient Alternate Resources in amounts equal to the amounts of withdrawal capacity associated with rejected storage. The certification is that the CTA has contracts for the following resources or combination of these resources which provide peak-day gas supplies equivalent to that which would have been available from the PG&E-allocated storage that the CTA has rejected. The resources used as alternates in this certification cannot duplicate any resources offered as replacements for winter intrastate transmission capacity that the CTA may be required to hold. 2.5.4.11.1 Contracted firm storage services from PG&E or from an on-system CPUC-certificated independent storage provider; 2.5.4.11.2 Contracted firm PG&E backbone capacity matched with an equivalent quantity of contracted upstream gas supply, and any necessary firm upstream pipeline capacity (upstream gas supply can include a gas producer contract, or a contract with an off-system CPUC-certificated gas utility or independent storage provider); and/or 2.5.4.11.3 Third-party peaking supply arrangements, where that supply is backed up by contracts under Section 2.5.4.11.1 or 2.5.4.11.2 above. 2.5.4.12 Release and Indemnification of PG&E: Any CTA that elects to ----------------------------------- reject all or a portion of its core storage allocation shall enter into an agreement with ======================================================================== 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 ======================================================================== Page 17 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ PG&E releasing PG&E from any and all liability associated with that CTA's rejection of its core storage allocation. In this agreement, the CTA shall be required to indemnify PG&E for any and all losses, including direct and consequential damages, that arise (i) from any representation in that CTA's certification which turns out to be inaccurate or (ii) from any failure of its Alternate Resources to perform as compared to the resources which would have been available from the PG&E-allocated core storage had this storage not been rejected by the CTA. 2.5.5 Term: This unbundling of core storage for CTAs will be effective upon the effective date of the tariffs implementing this Settlement Agreement provision. If this date is after December 1, 2000, then no intra-year elections may be made for the April 2000-March 2001 storage season as provided in Section 2.5.4.4. This program will continue for the April 2001-March 2002 and for the April 2002-March 2003 storage seasons. The provisions of this program will be reconsidered as part of the post-Gas Accord negotiations. 2.6 Separate Costs and Rates for Core Utility [Procurement] Services. Treat Utility Core Procurement Departments as Any Other Utility Customer 2.6.1 Summary of D.99-07-015: The Commission recommends, to the extent reasonable as determined in the cost-benefit phase, separating the costs and rates for core utility services including core procurement, transmission, storage, distribution, and balancing, and treating the local distribution company core procurement departments as a single customer for operational purposes, which is subject to the same terms and conditions of service as other customers. On PG&E's system, core customers are being treated like any other customer, are clearly liable for OFO penalties, and hub service revenues are not included in the CPIM. The Commission recognizes that it is important to ensure that all costs are assigned to the appropriate function. Additionally the Commission states that when they have determined whether and the extent to which various service components will be competitively provided, the utilities will be able to implement separate rates for those services, and to assure that no charges have been left in any functional category by default. (p. 49 [#8], p. 62, p. 86, Appendix C) 2.6.2 Current Brokerage Fee: A core brokerage fee of 2.4 cents per decatherm was negotiated in the Gas Accord as a proxy for certain costs directly related to PG&E's Core Procurement Department functions and overheads. Under the Gas Accord, the brokerage fee is subject to balancing account recovery and can be re-examined if PG&E's market share drops to 80% (Gas Accord, ss.IV.H.1). The parties reserved the right to propose other cost-based core cost allocation and rate design changes in future BCAPs for distribution rates and rate design (Gas Accord, ss.III.C.6.d.). 2.6.3 Resolution: The Parties agree the brokerage fee, and the method of separating PG&E's Core Procurement Department costs this fee addresses, will remain unchanged for the duration of this Settlement Agreement. PG&E agrees to ======================================================================== 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 ======================================================================== Page 18 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ discuss this issue and to consider reevaluating the method of allocating all procurement-related costs as part of PG&E's post- Gas Accord negotiations. ======================================================================== 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 ======================================================================== Page 19 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.7 Provide Details of Completed Transactions 2.7.1 Summary of D.99-07-015: The Commission believes that disclosure of the transaction-specific details requested by parties is basic and fundamental to an efficient market. In Conclusion of Law 17, the Commission directs the utilities either to provide timely information along the lines of the specific requests outlined in this decision, or to find different ways to convey to shippers information that they need to function effectively in the marketplace without compromising confidentiality concerns. (pp. 73- 78, FoF 17, CoL 17, Appendix C) 2.7.2 Monthly Negotiated Contract Report: PG&E will continue to file a monthly negotiated contract capacity report with the CPUC. This reports lists the details, but not customer names, of all negotiated capacity transactions for firm transportation, as-available transportation, and storage. Negotiated arrangements with affiliates or other Company departments are identified. 2.7.3 Resolution: Parties agree that the other provisions of this Settlement Agreement, including Sections 2.2.3, 2.2.4, 2.7 and 2.8 of this Settlement Agreement, as well as the OFO Settlement Agreement (filed October 22, 1999), should provide sufficient information on transactions to the market and shippers to enhance market liquidity and efficiency. Parties also agree that no further litigation of this issue is needed in I.99-07-003. 2.8 Establish a Secondary Market [Trading System] via a Utility Electronic Bulletin Board 2.8.1 Summary of D.99-07-015: Participation in the secondary market transactions through a mandatory Electronic Bulletin Board is consistent with the Commission's goals of enhancing market efficiency, preventing anti-competitive behavior, and providing additional competitive tools to the marketplace. Considering that all secondary market transactions will need to be confirmed through the utility, the Commission believes the utility should be required to provide the electronic bulletin board. However, the Commission wants to understand the costs of providing such a service before determining whether to require its provision. (p. 79, FoF 38, Appendix C) 2.8.2 Current Secondary Market Trading: Secondary market capacity trading is currently done on a voluntary basis through private transactions. There is no facilitating electronic platform currently available to the northern California market, other than a posting section on PG&E's INSIDEtracc. If parties to a capacity transaction want to change billing and nomination responsibility, the assignment is reported to PG&E so the change can be made and a new authorized nomination number can be provided. 2.8.3 Electronic Trading System Provisions: PG&E will facilitate a voluntary and anonymous secondary market trading system for firm backbone transmission ======================================================================== 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 ======================================================================== Page 20 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ capacity as part of its sole-source contract with ALTRA, and subject to the terms of that contract. The following provisions will apply: 2.8.3.1 Firm transmission capacity by path will be included on the electronic trading platform. 2.8.3.2 ALTRA and PG&E will establish the process for reporting assignments, and ALTRA will provide the screens and trading platform. 2.8.3.3 ALTRA will notify PG&E of the capacity assignment upon completion of a trade and PG&E will adjust its records accordingly and issue a new authorized nomination number to the assignee. 2.8.3.4 ALTRA will post on its electronic trading platform a summary of the completed transactions, listing the amount of capacity, the path (for transmission), transaction price and the term of the assignment. Customer names will not be provided. 2.8.4 Trading Fees: A monthly subscription fee is required if the customer does not already subscribe to ALTRA. A smaller fixed subscription fee will be made available for those entities who only want to use ALTRA for capacity trading, and not commodity trading. ALTRA will charge a transaction fee to both the buyer and seller. This fee will be capped, and any discounts made available on a nondiscriminatory basis. PG&E will receive fifty percent (50%) of the transaction fees to cover its ongoing costs and services, and will record one-half of these monies as a credit to the BCA to help offset the costs for implementing this trading system. PG&E will include the specific fee provisions in its tariffs pursuant to Section 1.7 above. 2.9 Provide Real-Time, Customer-Specific Usage Data 2.9.1 Summary of D.99-07-015: The Commission believes that customer access to real-time consumption data is consistent with its goals of increased market efficiency and providing competitive tools. Access to real-time data may help customers to better manage their pipeline flows. The Commission considers the most promising option going forward appears to be for the utilities to make available to any customer, at the customer's expense, the equipment, technology and training necessary for expanded customer access to timely consumption information. The Commission is interested in hearing from parties in the cost/benefit phase of this proceeding what it would cost on a per-customer basis to make such access generally available, as well as the specific impediments to providing real-time available capacity updates. (pp. 72-73, FoF 33 & 36, CoL 15-16, Appendix C) 2.9.2 Customer Options to Access Meter Data: Currently, about 900 of the 1200 noncore customers have Automatic Meter Reading (AMR) equipment, which PG&E "polls" via conventional phone lines once per day in order to retrieve the customer's hourly usage for each of the prior 24 hours. Since it takes about four to five hours to gather this data from all the AMR-equipped meters, the cumulative 24 hour data is not available to these customers until around 7:00 a.m. ======================================================================== 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 ======================================================================== Page 21 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ the following morning through PG&E's INSIDEtracc and Pipe Ranger. In addition, PG&E currently offers all customers options to access their gas usage data through pulses (which can be converted to usage), with the cost billed to the specific customer per the provisions contained in Gas Rule 2.C, Special Facilities. 2.9.3 Dial-In Access to AMR Data: PG&E may, depending on interest from market participants, offer customers, or their agents, dial-in access to PG&E's AMR meters. PG&E will survey market representatives to determine this level of interest. Any such dial-in access program would be subject to the following provisions. This option would only be available for meters equipped with both Mercury ECAT and AMR equipment. Equipment upgrades would be provided at customer expense to allow this data access option. The number of customer calls per meter would be limited to two per day so that battery life is not severely reduced. Also, no customer calls would be allowed between the hours of midnight and 5:00 a.m., during which time PG&E is calling the meter and downloading data for its use. PG&E would establish a start-up fee and a monthly service fee, as well as fees for other requests, such as changing an access password. These fees will be estimated based on recovering the costs to implement and maintain this program. 2.9.4 Internet Information on Meter Access Options: PG&E may, depending on interest from market participants, create an Internet accessible web page specifying customer options for accessing their own meter data or pulses. Each option would generally describe the types of meters involved, the type of data provided, the frequency of the data, an estimated cost range for typical installations, any related service fees, and other information which could help customers perform a rough evaluation of these options. PG&E contact phone numbers would be provided for responding to questions and to specific requests. These options should include: . AMR access for noncore customers, . Meter pulse data for all customers, . Dial-in access to the meter, . Pilot for noncore meter ownership for new facilities (per Section 2.10.4 below), and . Pilot for meter add-on devices (per Section 2.10.5 below). 2.9.5 Internet Access to Full AMR Data: PG&E may, depending on interest from market participants, make available on its Pipe Ranger Web site the AMR usage data for each hour of the prior day's usage in addition to the 24-hour total now provided. Data would be available about 7:00 a.m. in the morning for the prior midnight to midnight period. PG&E does not consider this billing quality data since missing data is filled in using estimation processes. This option would only be available to those customers with AMR equipment. Fees may be charged for this service based on recovering the costs to implement and maintain this program. ======================================================================== 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 ======================================================================== Page 22 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.9.6 Resolution: Parties agree that all issues in this proceeding with respect to the provision of real-time consumption data are resolved for the term of this Settlement Agreement and need not be litigated. ======================================================================== 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 ======================================================================== Page 23 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.10 Provide Competitive Metering Technologies 2.10.1 Summary of D.99-07-015: For safety implications, the Commission does not currently believe that it is an option to encourage the cost or rate separation of meter reading or servicing, or of what have been referred to as after-meter services. Distribution utilities should continue to provide these services as part of a bundled distribution service. The Commission views the competitive provision of meters to be a promising option, consistent with their goals of ensuring safe and reliable service, as well as their objective of removing unnecessary barriers to entry into various components of the natural gas service market. This inquiry can include consideration of whether or not the local distribution company should become the owner of any meter that it installs. Any meter would have to meet appropriate safety standards and utilize standardized information protocols. (pp. 84-85, Appendix C) 2.10.2 Resolution: Consistent with obligations under existing law, PG&E will install, read, remove, service, and maintain all gas meters during the term of this agreement. As part of the pilot program described below, a limited number of noncore customers may own their own PG&E-approved meters, or may choose meters to be owned by PG&E, for new meter installations. Further, also as a pilot program, a limited number of customers may own an "add-on device" to the PG&E-owned meter that allows the customer to access (and thus read remotely) meter data at time intervals needed for the customer's own purposes, or allows the customer to provide this meter data to another party. The selection and installation of this add-on device must also comply with established standards and procedures. 2.10.3 Principles for Ownership of Meters and Add-On Devices: The following principles provide the basis for the pilot ownership programs and to help guide implementation. 2.10.3.1 All customer-owned meters and add-on devices will have to meet appropriate standards of safety, accuracy and reliability, as determined by PG&E. 2.10.3.2 Customer ownership of any meter or add-on device will not interfere with PG&E's right to obtain current or additional data from the meter. PG&E also reserves the right to reconfigure the meter to improve PG&E's ability to obtain current or additional data. For example, if PG&E chooses to install automated meter reading (AMR) technology for a new class of customers or a given portion of its service area, PG&E shall be free to install that capability for all customers of that category, whether or not such customers had previously installed a customer-owned meter or meter add-on device incompatible with the AMR technology to be employed by PG&E. 2.10.3.3 Those customers that choose to own their own meters or add-ons are responsible for the additional incremental costs associated with such equipment. ======================================================================== 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 ======================================================================== Page 24 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.10.3.4 Nothing in this Settlement Agreement prevents PG&E from continuing to offer its currently available meter and meter-related products and services, or to propose new meter-related products and services. Furthermore, nothing in this Settlement Agreement requires Parties to support any PG&E proposals to offer any such new meter or meter-related products and services during the term of this Settlement Agreement. 2.10.4 Pilot Program for Customer Meter Ownership and Meter Choice: The following provisions apply to this pilot program for limited meter ownership and choice of PG&E-owned meters. 2.10.4.1 Participation Limit: The pilot program is limited to the ------------------- installation of 500 customer-owned meters per year. The pilot program applies only to new meter installations at noncore customer facilities, and does not apply to the replacement of an existing PG&E-owned meter. PG&E at its sole discretion may increase the cap on the number of meters which can be owned by customers. 2.10.4.2 Limit on Meter Choice: The meter ownership pilot program is --------------------- limited to customer ownership of meters approved by PG&E. Nothing in this program requires PG&E to evaluate and/or approve additional meters that are not already approved as of the date of a Commission order approving this Settlement Agreement, nor does anything in this program prevent PG&E from removing currently-approved meters from the approved list. 2.10.4.3 Cost Responsibility: Customers choosing to own their meter ------------------- are responsible for incremental costs associated with their meter that are incurred by PG&E. Incremental costs are those costs beyond the costs that would have been incurred by PG&E having installed and owned the most cost-effective meter for that site. Costs for which customers may be responsible could include, but are not limited to, installation of the meter or additional equipment, maintenance, call-out servicing, and any other incremental transaction-based costs associated with their owning the meter. 2.10.4.4 PG&E Access to Meter Data: PG&E has the right to obtain or ------------------------- directly access any data available from the customer-owned meter. PG&E may also add-on devices to a customer-owned meter which do not interfere with the customer's use of that meter. PG&E would pay the cost of such add-ons. 2.10.4.5 Advice Filing for Pilot: PG&E will prepare and submit an ----------------------- advice filing to implement this pilot meter ownership program, including tariff and fee provisions, consistent with the terms of this Settlement Agreement. This filing will be made as part of the submission discussed in Section 1.7 of this Settlement Agreement. 2.10.4.6 Term of Pilot: This pilot program is effective when the ------------- CPUC-approved tariffs implementing this program are effective, and will continue for the term of this Settlement Agreement. ======================================================================== 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 ======================================================================== Page 25 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.10.4.7 Assessment of Pilot: One year prior to the completion of ------------------- the program, PG&E will begin working with interested parties to prepare a report assessing the pilot meter ownership program. This assessment report, which will include recommendations concerning the future of the program, will be submitted to the CPUC six months prior to the end of the pilot. The report will address, among other things, whether the pilot program should be expanded, and the disposition of all existing customer-owned meters if the meter ownership pilot program is terminated. 2.10.5 Pilot Program for Customer Ownership of Meter Add-Ons: Subject to the following terms and conditions, PG&E will allow a limited customer ownership of add-on devices to PG&E-owned meters for the purpose of accessing meter data at time intervals needed for the customer's internal purposes, or for providing such data to another party. 2.10.5.1 Participation Limit: This pilot program is limited to the ------------------- installation of 1000 customer-owned meter add-on devices per year. PG&E at its sole discretion may increase the cap on the number of customer-owned meter add-on devices. 2.10.5.2 Meter Responsibility: Add-on devices will not adversely -------------------- affect the safety, reliability and accuracy of PG&E's gas meters, nor PG&E's ability to obtain any meter data. PG&E remains responsible for installation, removal, service and maintenance of the meters and the add-on devices. Customer ownership of an add-on device will not prevent or interfere with PG&E's ability to replace or reconfigure the meter. 2.10.5.3 Cost Responsibility: Customers will be responsible for the ------------------- costs associated with add-on devices, including, but not limited to, installation, maintenance, removal, and any other transaction-based costs associated with that add-on device. 2.10.5.4 Advice Filing for Pilot: PG&E will prepare and submit an ----------------------- advice filing to implement this pilot meter add-on program, including tariff and fee provisions, consistent with the terms of this Settlement Agreement. This filing will be made as part of the submission discussed in Section 1.7 of this Settlement Agreement. 2.10.5.5 Term of Pilot: This pilot program is effective when the ------------- CPUC-approved tariffs implementing this Settlement Agreement are effective, and will continue for the term of this Settlement Agreement. 2.10.5.6 Assessment of Pilot Program: One year prior to the --------------------------- completion of the program, PG&E will begin working with interested parties to prepare a report assessing the pilot meter add-on program. This assessment report, which will include recommendations for the future of the program, will be submitted to the CPUC six months prior to the end of this program. The report will address, among other things, whether the pilot program should be expanded, and the disposition of all existing customer-owned add-on devices if the meter add-on pilot program is terminated. ======================================================================== 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 ======================================================================== Page 26 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 2.11 Provide Competitive Billing Options to Customers Similar to Those Offered in the Electric Industry 2.11.1 Summary of D.99-07-015: The Commission states that competing gas and electric providers should be able to choose to provide a consolidated bill for gas and electricity so that the customers of such providers will not face duplicative charges for the billing function. The Commission feels that it may be appropriate for the natural gas utilities to provide billing options similar to those currently offered on the electric side. The Commission states that it should be just as possible for an electricity provider to bill its customers for gas service as it would be for a gas provider to bill for electric service. The Commission includes this as a promising option for further study and wants to examine cost system conversion and potential labor impacts associated with providing competitive billing and other services in the cost/benefit phase. (pp. 85-86, FoF 43, CoL 19, Appendix C) 2.11.2 Current Billing Options: Currently, CTAs who sell gas to residential and small commercial customers have three options open to them. The first option is for the CTA to bill for the gas commodity and have PG&E bill for gas transportation. This is called separate billing. The second option is for the CTA to bill for both their gas service and PG&E's transportation service. This option is called CTA consolidated billing. A third billing option, PG&E consolidated billing, where PG&E bills for both its transportation service and the CTA's commodity gas cost, is currently available only for dual-commodity customers who also participate in electric direct access. PG&E consolidated billing for gas-only customers (including those customers that receive separate gas and electric bills) will not be available until the Billing Availability Date as defined in Section 1.8 above. 2.11.3 PG&E Consolidated Gas Billing: PG&E will provide a PG&E gas consolidated billing option for gas-only customers by the Billing Availability Date. This approach avoids unnecessary costs for programming and manual processes which would still take one to one-and-a-half years to complete, and then be disposed of once the new billing system is operational. Once implemented, PG&E reserves the right to charge CTAs for PG&E consolidated gas billing services based on a methodology consistent with the methodology then in effect for PG&E consolidated electric billing. 2.11.4 Termination of Informational Bill Requirement: If a CTA performs CTA consolidated billing, PG&E is currently required to send the customer an informational bill. The Parties agree that the requirement for an informational bill should be removed upon implementation of this Settlement Agreement for those CTAs receiving PG&E billing information via Electronic Data Interchange (EDI) that agree in writing to present the requisite PG&E-provided charges, bill inserts and customer protection information in each end-user bill. CTAs also agree to provide a market-index commodity price (i.e., the Natural Gas Intelligence Weekly Gas Price Index, first of the month publication, PG&E Citygate, Bidweek) or the currently-required PG&E core procurement price in each end-user bill. The CTA shall annually elect which commodity price to provide. The requisite information to be presented in each end-user's bill will be addressed as ======================================================================== 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 ======================================================================== Page 27 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ part of the tariff process described in Section 1.7 above. In the agreement between PG&E and the CTA, the CTA shall indemnify PG&E for all direct and consequential damages, and the CTA shall expressly agree to assume all liability associated with the CTA's modification of, or failure to provide a customer with, any PG&E- provided bill insert. Any disputes concerning the content of PG&E provided bill inserts will be resolved by the Energy Division of the CPUC. As part of its compliance filing set forth in Section 1.7, PG&E will include provisions specifying compliance monitoring, cost responsibility, and enforcement measures. Any such CTA agreements will be in effect for the term of this Settlement Agreement, except that they will expire after (i) gas consumer protection legislation becomes effective which includes a provision authorizing the CPUC to enforce consumer protection rules, and (ii) the CPUC adopts such rules, including a CTA certification program. 2.11.5 Billing Credits for CTA-Consolidated Billing: The customer of a CTA, which performs consolidated CTA billing, will get the following avoided cost credit off their transportation rate as long as PG&E no longer has to send them an informational bill per Section 2.11.4 above. These credits will apply for both gas-only customers and dual-commodity customers for the term of this Settlement Agreement. If an Energy Service Provider (ESP) is also a CTA and performs both gas and electric consolidated billing for a dual-commodity customer, then that customer will receive the CTA consolidated gas billing credit in addition to the applicable electric credit for a dual-commodity customer. ($ per account per month) Residential G-NR1 G-NR2 ----------- ----- ----- Gas Billing Credit $0.71 $1.00 $1.00 2.11.6 Delivery of CTA Consolidated Gas Billing Credits: PG&E will deliver credits to those customers receiving consolidated billing services from their respective CTAs via checks sent to the respective CTAs in whatever manner PG&E deems most cost-effective, except that PG&E will deliver such checks on at least a semi-annual basis. This process will continue for the term of this Settlement Agreement, or until automation of the gas credit process in the new billing system. Upon automation of the gas credit process, credits will be included as a line item on PG&E's customer-specific billing data provided to CTAs and shown on their consolidated bill to these customers. ================================================================================ 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 ================================================================================ Page 28 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 3. PROMISING OPTIONS ALREADY IN PLACE FOR PG&E Parties agree that the following promising options identified in D.99-07-015 do not need to be litigated for the PG&E system in I.99-07-003, although they may be otherwise negotiated or litigated for the post-Gas Accord period. Through the Gas Accord, PG&E has already implemented these options for the Gas Accord period. 3.1 Create Firm Tradable Intrastate Transmission Rights 3.1.1 Summary of D.99-07-015: The Commission agrees that the creation of firm, tradable intrastate transmission rights offers the hope of improving efficiency through value-based pricing, as well as providing individual shippers with greater certainty as to their ability to move certain quantities of gas through the pipeline system. (pp. 12-14, FoF 1 & 2, CoL 1, 2, 5, Appendix C) 3.1.2 Resolution: The path-based firm backbone transmission capacity rights established by the Gas Accord continue to apply for Northern California. These rights are fully tradable and assignable, subject to the creditworthiness of the assignee. 3.2 Establish a Secondary Market for Intrastate Transmission Capacity 3.2.1 Summary of D.99-07-015: Participation in the secondary market transactions through a mandatory Electronic Bulletin Board is consistent with the Commission's goals of enhancing market efficiency, preventing anti-competitive behavior, and providing additional competitive tools to the marketplace. The Commission wants to understand the costs of providing such a service before determining whether to require its provision. (p. 79, FoF 38, Appendix C) 3.2.2 Resolution: A secondary market exists for PG&E's firm intrastate transmission capacity rights. This Settlement Agreement establishes an electronic trading platform for secondary market transmission transactions pursuant to Section 2.8 above. 3.3 Place the Utility At Risk for Unused [Transmission] Resources 3.3.1 Summary of D.99-07-015: The Commission refers to the fact that PG&E's shareholders are at risk for "stranded" costs associated with intrastate transmission in a table. (p. 12) 3.3.2 Resolution: The Gas Accord places PG&E at risk for recovery of transmission facility costs, and the rates associated with these costs are fixed for the Gas Accord period. These at-risk provisions continue to apply. However, this Settlement Agreement does not predetermine how risk will be allocated following the Gas Accord. ================================================================================ 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 ================================================================================ Page 29 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 3.4 Create Firm, Tradable Storage Rights 3.4.1 Summary of D.99-07-015: The Commission believes there would be more efficient use of the hard-to-find gas storage resources if individual shippers and customers could bid for firm storage access rights. In addition, the local distribution company will be motivated to pursue more complete utilization of its storage assets if its shareholders bear the risk for cost recovery. If accompanied by an active secondary market, the bidding and trading of storage rights should lead to pricing that reflects demand. (pp. 23-24, FoF 9, CoL 4, Appendix C) 3.4.2 Resolution: The Gas Accord assigned PG&E's existing firm gas storage capacity rights to core procurement, pipeline balancing and an unbundled storage program. Annual open seasons are held under the unbundled storage program, with negotiated deals at other times. The acquirers of firm storage capacity can sell that capacity on the secondary market, as can core procurement entities holding firm storage capacity, subject to the creditworthiness of the assignee. 3.5 Establish a Secondary Market For Intrastate Storage Capacity 3.5.1 Summary of D.99-07-015: The Commission anticipates that the existence of an active secondary market for storage would reduce a utility's ability to increase its storage revenues in an unfair manner. Shippers should be more willing to acquire storage rights when they know they are able to sell unused capacity on the secondary market. Participation in the secondary market transactions through a mandatory Electronic Bulletin Board is consistent with the Commission's goals of enhancing market efficiency, preventing anti-competitive behavior, and providing additional competitive tools to the marketplace. The Commission wants to understand the costs of providing such a service before determining whether to require its provision. (p. 24, FoF 38, Appendix C) 3.5.2 Resolution: As with firm transmission capacity, firm storage rights are already tradable and assignable under the provisions of the Gas Accord, subject to the creditworthiness requirements. Parties agree that no further action is needed on the PG&E system for trading storage rights. 3.6 Place the Utility At-Risk for Unused [Storage] Resources 3.6.1 Summary of D.99-07-015: The Commission requests the parties to consider the costs and benefits related to creating a system of tradable storage rights in Southern California that places the utility at risk for unused resources and preserving such a market in Northern California beyond the period of the Gas Accord. (pp. 20-24, Appendix C) 3.6.2 Gas Accord At-Risk Requirements: The Gas Accord places PG&E at risk for recovery of its storage facility costs. The major portion of the storage (32.8 Bcf) is assigned to core customers to ensure reliability of service. The core is obligated to pay these costs. However, this Settlement Agreement allows Core Transport ================================================================================ 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 ================================================================================ Page 30 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ Agents (CTAs) to provide reliability through other means and avoid payment of their share of these costs. Another portion of storage (2.2 Bcf) is assigned to pipeline balancing. These costs are included in the backbone transmission rates, which are at- risk for cost recovery. The feasibility of adding more storage assets to this service is one of the issues for the OFO Forum, as provided in the Gas OFO Settlement, filed October 22, 1999 in I.99-07-003. The remaining portion of storage (4.7 Bcf) is assigned to a fully at-risk unbundled storage program, where firm and negotiated storage services are offered by PG&E's Golden Gate Market Center. 3.6.3 Resolution: These at-risk provisions for storage continue to apply, as modified by this Settlement Agreement. However, this Settlement Agreement does not predetermine how risk will be allocated following the Gas Accord period. 3.7 Separate Utility Hub Services From Procurement Functions 3.7.1 Summary of D.99-07-015: The Commission would like to separate hub services, where possible, from the procurement function to eliminate the possibility of a conflict of interest affecting the two functions. (pp. 48-49, CoL 10, Appendix C) 3.7.2 Resolution: The current rules and protocols provide separation of PG&E's Core Procurement Department from PG&E's utility hub services for the term of the Gas Accord. This issue may be revisited during the post-Gas Accord negotiations. 3.8 Unbundle Utility Interstate Capacity Costs for Core Customers 3.8.1 Summary of D.99-07-015: The Commission recommends the unbundling of interstate capacity costs for SoCalGas, which may enhance the opportunities for competition for core customers, as marketers search for ways to beat SoCalGas' costs for inter-state transportation. PG&E and SDG&E have already unbundled such costs. (p. 49 [#4], pp. 60-61, FoF 31, Appendix C) 3.8.2 Resolution: PG&E unbundled these costs as part of the Gas Accord. This unbundling was approved in D.97-12-032, dated December 4, 1997. 3.9 Eliminate Core Subscription Service 3.9.1 Summary of D.99-07-015: The Commission recommends to eliminate the core subscription by April 1, 2001, and require that any noncore customer who prefers to continue procurement from local distribution companies after that date to take and pay for core service. (p. 49 [#7], pp. 63-64, Appendix C) 3.9.2 Resolution: The Gas Accord, as approved in D.97-08-055, phases out core subscription by March 1, 2001. Parties agree that no further action is needed on the PG&E system. ================================================================================ 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 ================================================================================ Page 31 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 4. PROMISING OPTIONS AND OTHER ISSUES WHICH ARE NOT TO BE LITIGATED PENDING FURTHER SETTLEMENT DISCUSSIONS 4.1 Develop Clear Procedures for Allocating [Firm] Capacity 4.1.1 Summary of D.99-11-053 issued November 18, 1999: This decision resolved the investigation into PG&E's bidding behavior in the Gas Accord open season auction. The Commission finds that PG&E abided by all the rules in place at that time and "that the UEG did not behave in an anti-competitive manner warranting penalty. The auction procedures should be reformed to further limit the ability of any single entity to unduly influence the market." (Mimeo, p. 22) The Commission also notes that "[F]urther discussion of potential reforms to auction rules for intrastate transmission capacity and for sales in the secondary market may take place within Investigation 99-07-003." (Mimeo, p. 25, Ordering Paragraph 2) 4.1.2 Resolution: PG&E does not plan on conducting any firm capacity open seasons before the end of the Gas Accord period. PG&E and the Parties will re-examine the issue of open season rules in the process of negotiating a post-Gas Accord settlement. Parties agree that this issue does not need to be litigated or resolved as part of I.99-07-003 or the current Settlement Agreement. 4.2 Revise PG&E's Transmission Interconnection Policy, Terms and Conditions (Not an Appendix C Item) 4.2.1 Gas Rule 27 Committee: This issue, which includes PG&E's proposed Gas Rule 27, is under consideration by a committee of the Parties. The objective is to resolve this issue through settlement, and perhaps a separate application. 4.2.2 Resolution: Parties agree that these issues do not need to be litigated or resolved as part of I.99-07-003 or the current Settlement Agreement. 4.3 Revise PG&E's Electric Generation Rate Design (Not an Appendix C Item) 4.3.1 Resolution: The Parties agree not to litigate issues related to Public Utilities Code Section 454.4 in I.99-07-003. The Parties also agree that PG&E's Biennial Cost Allocation Proceeding (BCAP), and not I.99-07-003, is an appropriate proceeding in which to address PG&E's electric generation cost allocation and rate design issues in I.99-07-003. PG&E commits to work with the BCAP parties to attempt to settle these issues. 4.4. Review PG&E's Local Transmission Reliability, Design Standards and Curtailment Provisions (Not an Appendix C Item) 4.4.1 Resolution: Parties agree that issues related to PG&E's local transmission reliability, design standards and local curtailment provisions will be negotiated ================================================================================ 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 ================================================================================ Page 32 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ separately, and will not be litigated with respect to PG&E as part of I.99-07-003 or resolved in this Settlement Agreement. 4.5 Investigate Mechanisms to Reduce the Costs of Transmission Service for Noncore Customers Connecting To or Located Close To PG&E's Backbone Transmission Facilities (Not an Appendix C Item) 4.5.1 Resolution: Parties agree that issues related to "direct connects," and/or limited use of PG&E's local transmission system, between a customer's facility and PG&E's backbone facilities will be negotiated separately, and will not be litigated with respect to PG&E as part of I.99-07-003 or resolved in this Settlement Agreement. 5. PROMISING OPTIONS WHICH WERE SETTLED IN THE OFO SETTLEMENT AGREEMENT 5.1 Examine Strategies for Devoting More Assets to PG&E Balancing 5.1.1 Summary of D.99-07-015: The Commission states that it is clear that shippers need to be better-equipped to anticipate and respond to OFOs. It's logical to assume that if PG&E had more storage capacity set aside to support its balancing efforts, it would have greater ability to smooth out fluctuations in system balancing without calling OFOs or undertaking curtailments. The Commission considers asking PG&E to identify the incremental cost of expanding balancing services in the next phase and suggests all interested parties to address the economics of this step. (pp. 32-33, FoF 15, CoL 6, Appendix C 5.1.2 OFO Forum: This issue will be considered by the OFO Forum in accordance with Section 2.1.3.7 above. 5.1.3 Balancing Study: PG&E agrees to provide the balancing study to all parties participating in the OFO Forum no later than March 7, 2000, even if the date for filing testimony is extended. 5.1.4 Resolution: Parties agree that this issue does not need to be litigated in I.99-07-003 and that the Forum is open to all storage operators on the PG&E system, as well as customers, shippers and consumer representatives. 5.2 Implement Targeted Operational Flow Orders 5.2.1 Summary of D.99-07-015: The Commission wants to explore targeted OFOs along with other similar reforms in the cost/benefit phase. They believe even though it's possible that some customers might respond to a targeted request by shifting excess gas to other customers, it may also improve the system balance. (p. 41, p. 50 [#10], FoF 23, CoL 9, Appendix C) ================================================================================ 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 ================================================================================ Page 33 January 28, 2000 CPUC Promising Gas Options I.99-07-003 Comprehensive Gas OII Settlement Agreement - ------------------------------------------ 5.2.2 Resolution: The OFO Settlement provides specific procedures for implementing customer-specific or targeted OFOs. No further litigation is needed. 5.3 Provide Pipeline Operator Demand Forecasts Broken Down by Customer Class 5.3.1 Summary of D.99-07-015: The Commission is not persuaded that disaggregating demand forecast information will create a disadvantage for any customer, including the core. Furthermore, the Commission does not believe that any particular customer would have an incentive to lessen the reliability or precision of its communications with the pipeline operator if they were provided the demand forecasts. (pp. 79-84, FoF 41, Appendix C) 5.3.2 Resolution: The OFO Settlement Agreement specifies that PG&E will provide customer class demand data with a three-day lag, as agreed to by those Parties. No further litigation is needed. 6. NO ISSUES REMAIN TO BE LITIGATED IN I.99-07-003 Parties agree that there are no issues of material fact or promising options which need litigating in I.99-07-003, provided the Commission approves this Settlement Agreement pursuant to its conditions. If Commission approval is conditional or modifies the Settlement Agreement, Parties reserve the right to seek hearings on any or all issues otherwise covered by this Settlement Agreement. ================================================================================ 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 ================================================================================ Page 34 January 28, 2000 EX-10.2 7 dex102.txt CREDIT AGREEMENT EXHIBIT 10.2 ================================================================== CREDIT AGREEMENT among PG&E CORPORATION as Borrower, the LENDERS party hereto, GENERAL ELECTRIC CAPITAL CORPORATION as Co-Arranger, LEHMAN COMMERCIAL PAPER INC. as Administrative Agent and LEHMAN BROTHERS INC. as Lead Arranger and Book Manager _______________________________________ Dated as of March 1, 2001 _______________________________________ ================================================================== TABLE OF CONTENTS -----------------
Page ---- SECTION 1. DEFINITIONS AND RULES OF INTERPRETATION................... 1 1.1 Defined Terms............................................ 1 1.2 Rules of Interpretation.................................. 1 1.3 Accounting Principles.................................... 1 SECTION 2. AMOUNTS AND TERMS OF CREDIT FACILITY...................... 1 2.1 The Commitment........................................... 1 2.2 Notice of Borrowing...................................... 2 2.3 Disbursement of Funds.................................... 2 2.4 Notes.................................................... 2 2.5 Interest................................................. 2 2.6 Interest Periods......................................... 3 2.7 Increased Costs, Illegality, etc......................... 5 2.8 Compensation............................................. 6 2.9 Extension of Maturity Date .............................. 7 SECTION 3. PREPAYMENTS; PAYMENTS; TAXES.............................. 7 3.1 Voluntary Prepayments.................................... 7 3.2 Mandatory Repayments..................................... 7 3.3 Method and Place of Payment.............................. 9 3.4 Net Payments............................................. 10 3.5 Allocation............................................... 12 3.6 Fee...................................................... 12 3.7 Application of Payments; Sharing......................... 12 SECTION 4. CONDITIONS PRECEDENT...................................... 13 4.1 Conditions to Closing.................................... 13 SECTION 5. REPRESENTATIONS, WARRANTIES AND AGREEMENTS................ 18 5.1 Standing................................................. 19 5.2 Requisite Authority; Etc................................. 19 5.3 No Conflict.............................................. 19 5.4 Consents................................................. 19 5.5 Compliance with Law...................................... 20 5.6 Litigation Claims........................................ 20 5.7 Contracts and Commitments................................ 20 5.8 Liens.................................................... 21 5.9 Insurance................................................ 21
5.10 Capitalization and Ownership................................................ 21 5.11 Financial Statements; Absence of Certain Changes............................ 22 5.12 Taxes....................................................................... 23 5.13 Disclosure.................................................................. 24 5.14 Environmental Matters....................................................... 24 5.15 Brokers' or Finders' Fees................................................... 24 5.16 Certain Regulatory Matters.................................................. 24 5.17 Transactions With Affiliates................................................ 26 5.18 Use of Proceeds............................................................. 26 5.19 Compliance with ERISA....................................................... 26 5.20 Investment Company Act...................................................... 27 5.21 Regulation.................................................................. 27 5.22 Security Documents.......................................................... 27 5.23 Certain Scheduled Projects.................................................. 27 5.24 Environmental Matters....................................................... 28 5.25 Intellectual Property....................................................... 28 5.26 No Default.................................................................. 29 5.27 Single-Purpose Entity....................................................... 29 5.28 Trust Indenture Act......................................................... 29 5.29 [OMITTED]................................................................... 29 5.30 Ratings Letter.............................................................. 29 5.31 Certain Indebtedness........................................................ 29 SECTION 6. AFFIRMATIVE COVENANTS......................................................... 30 6.1 Information Covenants....................................................... 30 6.2 Books, Records and Inspections.............................................. 33 6.3 Maintenance of Property; Insurance.......................................... 33 6.4 Corporate Franchises........................................................ 34 6.5 Compliance with Statutes, etc............................................... 34 6.6 Compliance with Environmental Laws.......................................... 34 6.7 ERISA....................................................................... 35 6.8 End of Fiscal Years; Fiscal Quarters........................................ 36 6.9 Payment of Taxes............................................................ 36 6.10 [OMITTED.................................................................... 36 6.11 Performance of Obligations.................................................. 37 6.12 Use of Proceeds............................................................. 37 6.13 Regulatory Compliance....................................................... 37 6.14 Financial Covenants......................................................... 37 6.15 Charter Documents........................................................... 37 6.16 Further Assurances; etc..................................................... 37 6.17 Tax Refund.................................................................. 38 SECTION 7. NEGATIVE COVENANTS............................................................ 38 7.1 Liens........................................................................ 38 7.2 Consolidation, Merger, Purchase or Sale of Assets, etc....................... 40
ii 7.3 Dividends.................................................................... 41 7.4 Indebtedness................................................................. 41 7.5 Advances, Investments and Loans.............................................. 42 7.6 Transactions with Affiliates................................................. 43 7.7 Capital Expenditures......................................................... 43 7.8 Limitations on Liens on Collateral; Modifications of Certain Indebtedness; Modifications of Certificate of Incorporation, By-Laws and Certain Other Agreements, etc............................................................ 43 7.9 Limitation on Issuance of Capital Stock...................................... 44 7.10 Business..................................................................... 45 7.11 Regulatory Compliance........................................................ 45 SECTION 8. EVENTS OF DEFAULT AND REMEDIES.............................................. 45 8.1 Events of Default............................................................ 45 8.2 Acceleration................................................................. 48 8.3 Other Remedies............................................................... 48 SECTION 9. MISCELLANEOUS............................................................... 48 9.1 Costs and Expenses........................................................... 48 9.2 Indemnity.................................................................... 49 9.3 Notices...................................................................... 51 9.4 Benefit of Agreement......................................................... 51 9.5 No Waiver; Remedies Cumulative............................................... 51 9.6 No Third Party Beneficiaries................................................. 52 9.7 Reinstatement................................................................ 52 9.8 No Immunity.................................................................. 52 9.9 Counterparts................................................................. 52 9.10 Amendment or Waiver.......................................................... 52 9.11 Assignments, Participations, etc............................................. 53 9.12 Survival..................................................................... 55 9.13 WAIVER OF JURY TRIAL......................................................... 55 9.14 Right of Set-off............................................................. 55 9.15 Severability................................................................. 55 9.16 Governing Law; Submission to Jurisdiction.................................... 56 9.17 Waiver by Borrower........................................................... 57 9.18 Recourse..................................................................... 57 9.19 Complete Agreement........................................................... 57 9.20 Publicity.................................................................... 57 9.21 Effectiveness................................................................ 57 9.22 Certain Representations and Warranties....................................... 57 9.23 Confidentiality.............................................................. 57
iii SECTION 10. THE ADMINISTRATIVE AGENT; THE LEAD ARRANGER, THE CO- ARRANGER AND THE BOOK MANAGER.................................................58 10.1 Appointment..................................................................58 10.2 Nature of Duties.............................................................58 10.3 Lack of Reliance on the Agent................................................58 10.4 Certain Rights of the Administrative Agent...................................59 10.5 Reliance.....................................................................59 10.6 Indemnification..............................................................59 10.7 The Administrative Agent in its Individual Capacity..........................60 10.8 Holders......................................................................60 10.9 Resignation by the Administrative Agent......................................60 10.10 The Lead Arranger, Co-Arranger and Book Manager..............................61
iv APPENDICES: - ---------- Appendix A Defined Terms and Rules of Interpretation EXHIBITS: - -------- Exhibit A Form of Notice of Borrowing Exhibit B Form of Note Exhibit C Form of Section 3.4(b)(ii) Certificate Exhibit D Form of Process Agent Letter SCHEDULES: - --------- Schedule 3.5 Allocation - Investment Unit Schedule 4.1(k) SEC Filings Schedule 5.6 Litigation Schedule 5.7 Covered Contracts Schedule 5.8 Liens Schedule 5.9 Insurance Schedule 5.10(e) Warrants, etc. Schedule 5.10(f) Ownership Schedule 5.14 Environmental Matters Schedule 5.15 Brokers Schedule 5.16(e) Regulated Entities Schedule 5.17 Transactions with Affiliates Schedule 5.19 ERISA Schedule 5.23 Scheduled Projects Schedule 7.1 Certain Liens Schedule 9.3 Notices ANNEXES - ------- Annex A Section 13 of the LLC Agreement v CREDIT AGREEMENT (this "Agreement"), dated as of March 1, 2001, among --------- PG&E Corporation, a California corporation, as the Borrower, the Lenders party hereto, General Electric Capital Corporation, a New York corporation, as Co- Arranger, Lehman Commercial Paper Inc., a New York corporation, as Administrative Agent, and Lehman Brothers Inc., a Delaware corporation, as Lead Arranger and Book Manager. W I T N E S S E T H: ------------------- WHEREAS, the Lenders party hereto are willing to provide the credit facility described herein upon the terms and conditions herein set forth; NOW, THEREFORE, in consideration of the premises and mutual agreements hereinafter contained, the parties hereto agree as follows: SECTION 1. DEFINITIONS AND RULES OF INTERPRETATION. --------------------------------------- 1.1 Defined Terms. Except as otherwise expressly provided herein, ------------- capitalized terms used in this Agreement and its Schedules and Exhibits shall have the respective meanings assigned to such terms in Appendix A hereto. 1.2 Rules of Interpretation. Except as otherwise expressly provided ----------------------- herein, the rules of interpretation set forth in Appendix A hereto shall apply to this Agreement. 1.3 Accounting Principles. Except as otherwise provided in this --------------------- Agreement, all computations and determinations as to financial matters, and all financial statements to be delivered under this Agreement shall be made or prepared in accordance with U.S. GAAP (including principles of consolidation where appropriate) applied on a consistent basis (except to the extent approved or required by the independent public accountants certifying such statements and disclosed therein). SECTION 2. AMOUNTS AND TERMS OF CREDIT FACILITY. ------------------------------------ 2.1 The Commitment. (a) Subject to and upon the terms and -------------- conditions set forth herein, each Lender agrees to make a term loan to the Borrower, which term loans (i) shall be incurred pursuant to a single drawing on the Closing Date, (ii) shall be denominated in Dollars, (iii) shall be incurred and maintained as Eurodollar Loans, except as otherwise specifically provided in Section 2.7(b), (iv) shall be made on the Closing Date in an aggregate principal amount which (x) in the case of the Tranche A Loan, equals the Tranche A Commitment and (y) in the case of the Tranche B Loan, equals the Tranche B Commitment, and (v) shall mature on the earlier of (A) the date of a Spin-Off of NEG, Inc. and (B) the Date Certain. (b) If the Closing Date has not occurred on or prior to March 30, 2001, then, in such event, the Lenders shall have no further obligations or liabilities under any of the Financing Documents and the Financing Documents shall have no further force or effect with respect to the Lenders, but the Borrower's obligation to pay the Commitment Fees and other costs, fees and expenses as provided herein and to indemnify the other parties to the Financing Documents shall not be terminated, modified or diminished in any respect. (c) The Loans are available only on the terms and conditions specified hereunder, and once repaid, in whole or in part, at maturity or by prepayment, may not be reborrowed in whole or in part. 2.2 Notice of Borrowing. The Borrower shall give the Lenders prior ------------------- notice of the Eurodollar Loan to be incurred hereunder, provided that any such -------- notice shall be deemed to have been given on a certain day only if given before 1:00 P.M. (New York time) on such day. Such notice (the "Notice of Borrowing") ------------------- shall be irrevocable and shall be in writing, or by telephone promptly confirmed in writing, in the form of Exhibit A, appropriately completed to specify: (i) the aggregate principal amount of the Loans to be incurred on the Closing Date (which shall be a Business Day), (ii) the Selected Interest Period for the period beginning on the Closing Date pursuant to Section 2.6(b), and (iii) the account information for disbursement of the Loans. 2.3 Disbursement of Funds. No later than 1:00 P.M. (New York time) --------------------- on the Closing Date, each Lender will make available such Lender's pro rata --- ---- share of the amount of Borrowing requested to be made on such date. All such amounts will be made available in Dollars and in immediately available funds and disbursed in accordance with the provisions of the Escrow Agreement. 2.4 Notes. (a) The Borrower's obligation to pay the principal of, ----- and interest on, any Loan made by a Lender shall be evidenced by a promissory note duly executed and delivered by the Borrower substantially in the form of Exhibit B, with blanks appropriately completed in conformity herewith (each, a "Note"). ---- (b) The Note issued to a Lender shall (i) be executed by the Borrower, (ii) be payable to such Lender or its Assignee and be dated the Closing Date (or, if issued after the Closing Date, be dated the date of issuance thereof), (iii) be in a stated principal amount equal to the Loan made by, or assigned to, such Lender, as the case may be, and be payable in the outstanding principal amount of the Loan evidenced thereby, (iv) mature on the earlier of (A) the date of a Spin-Off of NEG, Inc. and (B) the Date Certain, (v) bear interest as provided in the appropriate clause of Section 2.5 in respect of a Base Rate Loan (if converted pursuant to Section 2.7(b)) or a Eurodollar Loan, as the case may be, evidenced thereby, (vi) be subject to voluntary prepayment as provided in Section 3.1, and mandatory repayment as provided in Section 3.2, and (vii) be entitled to the benefits of this Agreement and the other Financing Documents. (c) Each Lender will note on its internal records the amount of the Loan made by it and each payment in respect thereof and will prior to any transfer of its Note endorse on the reverse side thereof the outstanding principal amount of the Loan evidenced thereby. Failure to make any such notation or any error in such notation shall not affect the Borrower's obligations in respect of such Loan. 2.5 Interest. (a) The Borrower agrees to pay interest in respect of -------- the unpaid principal amount of any Base Rate Loan from the date of conversion thereof pursuant to Section -2- 2.7(b) until the maturity thereof (whether by acceleration or otherwise) at a rate per annum which shall be equal to the sum of the Applicable Margin plus the Base Rate each as in effect from time to time. (b) The Borrower agrees to pay interest in respect of the unpaid principal amount of each Eurodollar Loan from the date of Borrowing thereof until the earlier of (i) the maturity thereof (whether by acceleration or otherwise) and (ii) the conversion of such Eurodollar Loan to a Base Rate Loan pursuant to Section 2.7(b) at a rate per annum which shall, during each Interest Period applicable thereto, be equal to the sum of the Applicable Margin as in effect from time to time during such Interest Period plus the Eurodollar Rate for such Interest Period. (c) Overdue principal and, to the extent permitted by law, overdue interest in respect of each Loan and any other overdue amount payable by the Borrower shall, in each case, bear interest at a rate per annum equal to the rate which is 2% in excess of the rate then borne by such Loan. Interest which accrues under this Section 2.5(c) shall be payable on demand. (d) Accrued (and theretofore unpaid) interest shall be payable (i) in respect of each Base Rate Loan, (x) quarterly in arrears on each Quarterly Date, (y) on the date of any repayment or prepayment in full of the outstanding principal amount of such Base Rate Loan, and (z) at maturity (whether by acceleration or otherwise) and, after such maturity, on demand, and (ii) in respect of each Eurodollar Loan, (x) on the last day of each Interest Period applicable thereto and, in the case of an Interest Period in excess of three months, on each date occurring at three month intervals after the first day of such Interest Period, and (y) on the date of any repayment or prepayment (on the amount repaid or prepaid), at maturity (whether by acceleration or otherwise) and, after such maturity, on demand; provided that the first interest payment -------- shall be due and payable in advance on the Closing Date in an amount equal to the Interest Prepaid Amount and the first Interest Period shall be a one year period (the "First Interest Period"). (e) Upon each Interest Determination Date with respect to any Eurodollar Loan, the Administrative Agent shall determine the Eurodollar Rate for the relevant Interest Period applicable to such Eurodollar Loan and shall promptly notify the Borrower thereof. Each such determination shall, absent manifest error, be final and conclusive and binding on all parties hereto. 2.6 Interest Periods. (a) At the time the Borrower gives the Notice ---------------- of Borrowing or prior to 1:00 P.M. (New York time) on the third Business Day prior to the expiration of an Interest Period applicable to a Eurodollar Loan (in the case of any subsequent Interest Period), the Borrower shall have the right to elect the interest period (each an "Interest Period") applicable to --------------- such Eurodollar Loan, which Interest Period shall, at the option of the Borrower, be a one, two, three or six-month period; provided that (in each -------- case): (i) the initial Interest Period for any Eurodollar Loan shall commence on the date of Borrowing of such Eurodollar Loan and each Interest Period occurring thereafter in respect of such Eurodollar Loan shall commence on the day on which the next preceding Interest Period applicable thereto expires; -3- (ii) if any Interest Period for a Eurodollar Loan begins on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period, such Interest Period shall end on the last Business Day of such calendar month; (iii) if any Interest Period for a Eurodollar Loan would otherwise expire on a day which is not a Business Day, such Interest Period shall expire on the next succeeding Business Day; provided, however, that if any -------- ------- Interest Period for such Eurodollar Loan would otherwise expire on a day which is not a Business Day but is a day of the month after which no further Business Day occurs in such month, such Interest Period shall expire on the next preceding Business Day; (iv) no Interest Period may be selected at any time when a Default or an Event of Default is then in existence; and (v) no Interest Period in respect of any Borrowing of any Eurodollar Loan shall be selected which extends beyond the Date Certain. If upon the expiration of any Interest Period applicable to any Eurodollar Loan, the Borrower has failed to elect, or is not permitted to elect, a new Interest Period to be applicable to such Eurodollar Loan as provided above, the Borrower shall be deemed to have elected a one-month Interest Period effective as of the expiration date of such current Interest Period. (b) During the First Interest Period, the Borrower shall have the right, at the times indicated and following the procedure set forth in Section 2.6(a), to deliver notice to the Administrative Agent to indicate Interest Periods of one, two, three or six months (each such Interest Period, with respect to any Eurodollar Loan, a "Selected Interest Period") for purposes of ------------------------ comparing the interest rates. The Administrative Agent shall determine the Eurodollar Rate for each such Selected Interest Period applicable to a Eurodollar Loan and the amount of accrued interest (such amount, the "Selected -------- Interest Amount") which would be payable in respect of such Eurodollar Loan for - --------------- each such Selected Interest Period, which determination shall, absent manifest error, be final, conclusive and binding on all parties hereto. On the date which is the earlier of the date of prepayment of all the Loans by the Borrower pursuant to the terms hereof and the first anniversary of the Closing Date (x) the Borrower shall pay to the Administrative Agent the amount by which the sum of the aggregate Selected Interest Amounts (discounted to present value as of the Closing Date using a discount factor of 4.25%) plus any amounts due and payable under Section 2.8 with respect to a Selected Interest Period exceeds the Interest Prepaid Amount or (y) each Lender shall credit to the Borrower the amount by which the Interest Prepaid Amount with respect to the Loan of such Lender exceeds the sum of the aggregate Selected Interest Amounts (discounted to present value as of the Closing Date using a discount factor of 4.25%) with respect to the Loan of such Lender plus any amounts due and payable to such Lender under Section 2.8 or otherwise under this Agreement. In no event shall a Selected Interest Period extend beyond the last day of the First Interest Period. 2.7 Increased Costs, Illegality, etc. (a) In the event that a --------------------------------- Lender shall have determined (which determination shall, absent manifest error, be final and conclusive and binding upon all parties hereto): -4- (i) on any Interest Determination Date that, by reason of any changes arising after the date of this Agreement affecting the interbank Eurodollar market, adequate and fair means do not exist for ascertaining the applicable interest rate on the basis provided for in the definition of Eurodollar Rate; or (ii) at any time, that such Lender shall incur increased costs or reductions in the amounts received or receivable hereunder with respect to any Eurodollar Loan of such Lender because of (x) any change since the Closing Date in any applicable law or governmental rule, regulation, order, guideline or request (whether or not having the force of law) or in the interpretation or administration thereof and including the introduction of any new law or governmental rule, regulation, order, guideline or request, such as, for example, but not limited to: (A) a change in the basis of taxation of payment to such Lender of the principal of or interest on such Lender's Loan or Note or any other amounts payable to such Lender hereunder (except for changes in the rate of tax on, or determined by reference to, the net income or net profits of such Lender pursuant to the laws of the jurisdiction in which it is doing business, organized or in which its principal office or applicable lending office is located or any subdivision thereof or therein) or (B) a change in official reserve requirements, but, in all events, excluding reserves required under Regulation D to the extent included in the computation of the Eurodollar Rate and/or (y) other circumstances (other than with respect to taxes) arising since the Closing Date affecting such Lender (or its Source), the interbank Eurodollar market or the position of such Lender in such market; or (iii) at any time, that the making or continuance of any Eurodollar Loan has been made (x) unlawful by any law or governmental rule, regulation or order, (y) impossible by compliance by such Lender in good faith with any governmental request (whether or not having force of law) or (z) impracticable as a result of a contingency occurring after the Closing Date which materially and adversely affects the interbank Eurodollar market; then, and in any such event, such Lender shall promptly give notice (by telephone promptly confirmed in writing) to the Borrower of such determination. Thereafter (x) in the case of clause (i) above, Eurodollar Loans shall no longer be available until such time as such Lender notifies the Borrower that the circumstances giving rise to such notice by the Lender no longer exist, (y) in the case of clause (ii) above, the Borrower agrees to pay to such Lender, upon such Lender's written request therefor, such additional amounts (in the form of an increased rate of, or a different method of calculating, interest or otherwise as such Lender in its sole discretion shall determine) as shall be required to compensate such Lender for such increased costs or reductions in amounts received or receivable hereunder (a written notice as to the additional amounts owed to such Lender, showing in reasonable detail the basis for the calculation thereof, submitted to the Borrower by such Lender shall, absent manifest error, be final and conclusive and binding on all the parties hereto) and (z) in the case of clause (iii) above, the Borrower shall take one of the actions specified in Section 2.7(b) as promptly as possible and, in any event, within the time period required by Law. Each Lender, at the sole cost and expense of the Borrower (including, but not limited to, such Lender's internal costs for use of its personnel and resources), will use its reason- -5- able efforts to minimize taxes indemnifiable by the Borrower under this Section 2.7(a), including by complying with reasonable requests by the Borrower to do or to refrain from doing any act (including the execution of any certificates or similar documents required to establish an exemption or relief from any tax), if such efforts or any such compliance is, in the good faith discretion of such Lender, of a purely ministerial nature and has no adverse impact on such Lender or any Affiliate or on the business or operations of the foregoing (unless such adverse impact is one of a nature and quality such that it is subject to indemnification and the Borrower has indemnified such Lender against such adverse impact in a manner satisfactory to such Lender determined in its sole discretion). The Borrower shall indemnify such Lender for any taxes that may be imposed on it as a consequence of such compliance. (b) At any time that any Eurodollar Loan is affected by the circumstances described in Section 2.7(a)(i) or (ii), the Borrower may, and in the case of a Eurodollar Loan affected by the circumstances described in Section 2.7(a)(iii), the Borrower shall, upon at least three Business Days' written notice to such Lender, require the affected Lender to convert such Eurodollar Loan into a Base Rate Loan. (c) If a Lender determines that after the Closing Date the introduction of or any change in any applicable law or governmental rule, regulation, order, guideline, directive or request (whether or not having the force of law) concerning capital adequacy, or any change in interpretation or administration thereof by the NAIC or any governmental authority, central bank or comparable agency, will have the effect of increasing the amount of capital required or expected to be maintained by such Lender (or its Source) or any corporation controlling such Lender based on the existence of such Lender's Commitment hereunder or its obligations hereunder, then the Borrower agrees to pay to such Lender, upon its written demand therefor, such additional amounts as shall be required to compensate such Lender or such other corporation for the increased cost to such Lender or such other corporation or the reduction in the rate of return to such Lender or such other corporation as a result of such increase of capital. In determining such additional amounts, each Lender will act reasonably and in good faith and will use averaging and attribution methods which are reasonable, provided that such Lender's determination of compensation -------- owing under this Section 2.7(c) shall, absent manifest error, be final and conclusive and binding on all the parties hereto. Such Lender, upon determining that any additional amounts will be payable pursuant to this Section 2.7(c), will give prompt written notice thereof to the Borrower, which notice shall show in reasonable detail the basis for calculation of such additional amounts. 2.8 Compensation. The Borrower agrees to compensate each Lender, ------------ upon its written request (which request shall set forth in reasonable detail the basis for requesting such compensation), for all losses, expenses and liabilities (including, without limitation, any loss, expense or liability incurred by reason of the liquidation or reemployment of deposits or other funds required by such Lender to fund its Eurodollar Loan but excluding loss of anticipated profits) which such Lender may sustain: (i) if any prepayment or repayment (including any prepayment or repayment made pursuant to Section 3.1, Section 3.2 or as a result of an acceleration of the Loans pursuant to Section 8.2) or conversion of any Eurodollar Loan is made on a date other than the last day of the Interest Period (or during the First Interest Period, any Selected Interest Period) applicable thereto; or (ii) as a consequence of (x) any other default by the -6- Borrower to repay such Eurodollar Loan when required by the terms of this Agreement or any Note held by such Lender or (y) any election made pursuant to Section 2.7(b). 2.9 Extension of Maturity Date The Borrower may by notice to the -------------------------- Administrative Agent and the holders of the Loans not later than thirty (30) days prior to the Initial Date Certain or the Extended Date Certain occurring six months after the Initial Date Certain (if the maturity date of the Loans was extended on the Initial Date Certain to such Extended Date Certain), and upon payment of the Extension Fees relating to such extension pursuant to the Fee Letter and the Lehman Fee Letter, extend the maturity date of the Loans to the earlier of (i) the date of a Spin-Off of NEG, Inc. and (ii) the Extended Date Certain, but in no event shall the Date Certain be beyond the third anniversary of the Closing Date; provided, that there shall be no extension of the maturity -------- date of the Loans if on the date of such extension, (a) a Default or an Event of Default shall be continuing or (b) the aggregate outstanding principal amount of the Loans at such time shall be more than $692,000,000. SECTION 3. Prepayments; Payments; Taxes. ---------------------------- 3.1 Voluntary Prepayments. The Borrower shall have the right to --------------------- prepay the Tranche A Loan and the Tranche B Loan, on a pro rata basis, without --- ---- premium or penalty, in whole or in part at any time and from time to time on the following terms and conditions: the Borrower shall give each Lender prior to 12:00 Noon (New York time) (x) at least one Business Day's prior written notice (or telephonic notice promptly confirmed in writing) of its intent to prepay a Base Rate Loan and (y) at least three Business Days' prior written notice (or telephonic notice promptly confirmed in writing) of its intent to prepay a Eurodollar Loan, which notice (in each case) shall specify the amount of such prepayment which shall be in an aggregate principal amount of at least $10,000,000, and minimum increments of $1,000,000 in excess thereof. 3.2 Mandatory Repayments. (a) The principal amount of each Loan, to -------------------- the extent then outstanding, shall be repaid at its maturity (whether by acceleration or otherwise). (b) In addition to any other mandatory repayments pursuant to this Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc. or any NEG Subsidiary receives any cash proceeds from any incurrence by LLC, NEG, Inc. or any NEG Subsidiary of Indebtedness for borrowed money, an amount equal to 100% of the Net Debt Proceeds of the respective incurrence of Indebtedness shall be applied on such date in accordance with the requirements of Section 3.2(h); provided that such Net Debt Proceeds shall not be required to -------- be so applied to the extent such Net Debt Proceeds are (i) retained as cash or Cash Equivalents by LLC, NEG, Inc. or any NEG Subsidiary or (ii) applied to repay Indebtedness for borrowed money of NEG, Inc. or any NEG Subsidiary or (iii) reinvested in the business of NEG, Inc. or any NEG Subsidiary within the scope of business as described by the Business Plan; provided, further, that if -------- ------- a Default or Event of Default shall have occurred and be continuing, such reinvestment may only be made to the extent specified in Part II of the Business Plan. (c) In addition to any other mandatory repayments pursuant to this Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc. or any NEG Subsidiary receives any cash proceeds from any sale or issuance of its equity (other than cash -7- proceeds received as part of an IPO which shall be applied pursuant to clause (d) below) an amount equal to 100% of the Net Equity Proceeds of such sale or issuance of equity, whether common or preferred, shall be applied on such date in accordance with the requirements of Section 3.2(h); provided that such Net -------- Equity Proceeds shall not be required to be so applied to the extent such Net Equity Proceeds are (i) retained as cash or Cash Equivalents by LLC, NEG, Inc. or the NEG Subsidiaries or (ii) applied to repay Indebtedness for borrowed money of NEG, Inc. or any NEG Subsidiary or (iii) reinvested in the business of NEG, Inc. or any NEG Subsidiary within the scope of business as described by the Business Plan; provided, further, that if a Default or Event of Default shall -------- ------- have occurred and be continuing, such reinvestment may only be made to the extent specified in Part II of the Business Plan. (d) In addition to any other mandatory repayments required pursuant to this Section 3.2, on the date of an IPO upon which the Borrower, LLC or NEG, Inc. receives any proceeds from such IPO, (i) so long as no Default or Event of Default shall have occurred and be continuing (both before and after giving effect to such IPO), an amount sufficient to reduce the outstanding principal amount of the Loans to no more than $500,000,000, or (ii) if a Default or an Event of Default shall have occurred and be continuing (either before or after giving effect to such IPO), then (A) in the event such Default or Event of Default may be cured by the payment of money, an aggregate amount sufficient to cure such Default or Event of Default and to reduce the aggregate outstanding principal amount of the Loans to no more than $500,000,000, or (B) in the event such Default or Event of Default is not subject to cure by the payment of money, an amount equal to the greater of (x) the amount specified in clause (i) above or (y) 100% of such proceeds, in each case shall be applied on such date in accordance with the requirements of Section 3.2(h). (e) In addition to any other mandatory repayments pursuant to this Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc. or any NEG Subsidiary receives any cash proceeds from any Asset Sale by LLC, NEG, Inc. or any NEG Subsidiary, an amount equal to 100% of the Net Sale Proceeds therefrom shall be applied in accordance with the requirements of Section 3.2(h); provided that such Net Sale Proceeds shall not be required to be -------- so applied to the extent such Net Sale Proceeds are (i) retained as cash or Cash Equivalents by LLC, NEG, Inc. or the NEG Subsidiaries or (ii) applied to repay Indebtedness for borrowed money of NEG, Inc. or any NEG Subsidiary or (iii) reinvested in the business of NEG, Inc. or any NEG Subsidiary within the scope of business as described by the Business Plan; provided, further, that if a -------- ------- Default or Event of Default shall have occurred and be continuing, such reinvestment may only be made to the extent specified in Part II of the Business Plan. (f) In addition to any other mandatory repayments pursuant to this Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc. or any NEG Subsidiary receives any cash proceeds from any Recovery Event, an amount equal to 100% of the Net Insurance Proceeds from such Recovery Event shall be applied in accordance with the requirements of Section 3.2(h); provided -------- that such Net Insurance Proceeds shall not be required to be so applied to the extent such Net Insurance Proceeds are (i) applied to repay Indebtedness for borrowed money of NEG, Inc. or any NEG Subsidiary or (ii) reinvested in the business of NEG, Inc. or any NEG Subsidiary within the scope of business as described by the Business Plan within eighteen (18) months of the Recovery Event; provided, further, that if a Default or Event -------- ------- -8- of Default shall have occurred and be continuing, such reinvestment may only be made to the extent specified in Part II of the Business Plan. (g) In addition to any other mandatory repayments pursuant to this Section 3.2, on each date on or after the Closing Date upon which the Borrower receives a distribution, Dividend or payment of any sort from LLC (other than the proceeds of an IPO which shall be applied pursuant to clause (d) above and issuance of the note from NEG, Inc. to LLC or the Borrower or from LLC to the Borrower, solely in connection with the IPO (but not payments thereunder)), an amount equal to 100% of such proceeds (net of any amount thereof used to reimburse the Borrower for (i) any expense related to any income or franchise Taxes of NEG, Inc. or any NEG Subsidiary (computed as if NEG, Inc. and each of its Subsidiaries filed a consolidated federal income Tax return and state consolidated or combined income or franchise Tax returns, where applicable, separate from the Borrower, PG&E Utility and Subsidiaries of PG&E Utility, for all taxable periods), (ii) any expenses then due and payable under the Expense Sharing Agreement or (iii) any amount then due and payable under the note from NEG, Inc. and payable to LLC or the Borrower solely in connection with the IPO) shall be applied in accordance with the requirements of Section 3.2(h). (h) Each amount required to be applied pursuant to this Section 3.2(h) shall be first paid to the Lenders ratably according to the respective outstanding principal amounts of Loans held by the Lenders and shall be applied by each Lender to payment of any amount owing to such Lender under Section 2.8, then to payment of any interest then due and payable to such Lender, and then to reduce ratably the remaining principal balance of the Loans of such Lender. (i) In addition to any other mandatory repayments pursuant to this Section 3.2, all the then outstanding Loans shall be repaid in full on the earlier of (x) the date of a Spin-Off of NEG, Inc. and (y) the Date Certain. (j) The application of any proceeds received by LLC to be applied for mandatory repayment under Sections 3.2(b), (c), (e) and (f) shall be subject to Compliance by LLC with the requirements for Distribution under Section 13 of the LLC Agreement. (k) Nothing in this Section 3.2 shall limit any other rights or remedies a Lender may have under Article 8 of this Agreement or under applicable law in connection with any Event of Default. 3.3 Method and Place of Payment. Except as otherwise specifically --------------------------- provided herein, all payments under this Agreement and under any Note shall be made to the Administrative Agent for the account of the Lenders entitled thereto not later than 12:00 Noon (New York time) on the date when due and shall be made in Dollars in immediately available funds at the Payment Office or pursuant to such other instruction as the Administrative Agent shall designate to the Borrower in writing. Except as otherwise provided herein, whenever any payment to be made hereunder or under any Note shall be stated to be due on a day which is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day and, with respect to payments of principal, interest shall be payable at the applicable rate during such extension. -9- 3.4 Net Payments. (a) All payments made by the Borrower to the ------------ Administrative Agent or any Lender hereunder and under any Note will be made without setoff, counterclaim or other defense. Except as provided in Section 3.4(b), all such payments will be made free and clear of, and without deduction or withholding for, any present or future taxes, levies, imposts, duties, fees, assessments or other charges of whatever nature now or hereafter imposed by any jurisdiction or by any political subdivision or taxing authority thereof or therein with respect to such payments (but excluding, except as provided in the second succeeding sentence, any tax imposed on or measured by the net income or net profits of a Lender pursuant to the laws of the jurisdiction in which it is doing business, organized or the jurisdiction in which the principal office or applicable lending office of such Lender is located or any subdivision thereof or therein) and all interest, penalties or similar liabilities with respect to such non-excluded taxes, levies, imposts, duties, fees, assessments or other charges (all such non-excluded taxes, levies, imposts, duties, fees, assessments or other charges being referred to collectively as "Taxes"). If any Taxes are ----- so levied or imposed, the Borrower agrees to pay the full amount of such Taxes, and such additional amounts as may be necessary so that every payment of all amounts due under this Agreement or under any Note, after withholding or deduction for or on account of any Taxes, will not be less than the amount provided for herein or in such Note. If any amounts are payable in respect of Taxes pursuant to the preceding sentence, the Borrower agrees to reimburse each Lender, upon the written request of such Lender, for taxes imposed on or measured by the net income or net profits of such Lender pursuant to the laws of the jurisdiction in which such Lender is doing business, organized or in which the principal office or applicable lending office of such Lender is located or under the laws of any political subdivision or taxing authority of any such jurisdiction in which such Lender is doing business, organized or in which the principal office or applicable lending office of such Lender is located and for any withholding of taxes as such Lender shall reasonably determine are payable by, or withheld from, such Lender, in respect of such amounts so paid to or on behalf of such Lender pursuant to the preceding sentence and in respect of any amounts paid to or on behalf of such Lender pursuant to this sentence. The Borrower will furnish to such Lender within 45 days after the date the payment of any Taxes is due pursuant to applicable law certified copies of tax receipts evidencing such payment by such Borrower. The Borrower agrees to indemnify and hold harmless each Lender, and reimburse such Lender upon its written request, for the amount of any Taxes so levied or imposed and paid by such Lender. (b) Any Lender that is not a United States person (as such term is defined in Section 7701(a)(30) of the Code) for U.S. Federal income tax purposes agrees to deliver to the Administrative Agent and the Borrower on or prior to the Closing Date or, in the case of a Lender that is an assignee or transferee of an interest under this Agreement pursuant to Section 9.11(a) (unless such Assignee was already a Lender hereunder immediately prior to such assignment in which case such assignee shall reaffirm its ability to deliver the forms set forth below in clause (i) or (ii), as applicable), on the date of the assignment to such Assignee, (i) two accurate and complete original signed copies of Internal Revenue Service Form W-8ECI or Form W-8BEN (with respect to a complete exemption under an income tax treaty) (or successor forms) certifying to such Lender's entitlement as of such date to a complete exemption from United States withholding tax with respect to payments to be made under this Agreement and under any Note, or (ii) if any such Lender is not a "bank" within the meaning of Section 881(c)(3)(A) of the Code and cannot deliver either Internal Revenue Service Form W-8ECI or -10- Form W-8BEN (with respect to a complete exemption under an income tax treaty) (or any successor forms) pursuant to clause (i) above, (x) a certificate substantially in the form of Exhibit C (any such certificate, a "Section 3.4(b)(ii) Certificate") and (y) two accurate and complete original signed copies of Internal Revenue Service Form W-8BEN (with respect to the portfolio interest exemption) (or successor form) certifying to such Lender's entitlement as of such date to a complete exemption from United States withholding tax with respect to payments of interest to be made under this Agreement and under any Note. In addition, each such Lender agrees that from time to time after the Closing Date, when a lapse in time or change in circumstances renders the previous certification obsolete or inaccurate in any material respect, such Lender will deliver to the Administrative Agent and the Borrower two new accurate and complete original signed copies of Internal Revenue Service Form W- 8ECI, Form W-8BEN (with respect to the benefits of any income tax treaty), or Form W-8BEN (with respect to the portfolio interest exemption) and a Section 3.4(b)(ii) Certificate, as the case may be, and such other forms as may be required in order to confirm or establish the entitlement of such Lender to a continued exemption from or reduction in United States withholding tax with respect to payments under this Agreement and any Note, or such Lender shall immediately notify the Administrative Agent and the Borrower of its inability to deliver any such Form or Certificate, in which case such Lender shall not be required to deliver any such Form or Certificate pursuant to this Section 3.4(b). Notwithstanding anything to the contrary contained in Section 3.4(a) and the immediately succeeding sentence, (x) the Borrower shall be entitled, to the extent it is required to do so by law, to deduct or withhold income or similar taxes imposed by the United States (or any political subdivision or taxing authority thereof or therein) from interest, fees or other amounts payable hereunder for the account of any Lender which is not a United States person (as such term is defined in Section 7701(a)(30) of the Code) for U.S. Federal income tax purposes to the extent that such Lender has not provided to the Administrative Agent and the Borrower U.S. Internal Revenue Service Forms that establish a complete exemption from such deduction or withholding and (y) the Borrower shall not be obligated pursuant to Section 3.4(a) to gross-up payments to be made to a Lender in respect of income or similar taxes imposed by the United States if (I) such Lender has not provided to the Administrative Agent and the Borrower the Internal Revenue Service Forms required to be provided to the Administrative Agent and the Borrower pursuant to this Section 3.4(b) or (II) in the case of a payment, other than interest, to a Lender described in clause (ii) above, to the extent that such Forms do not establish a complete exemption from withholding of such taxes. Notwithstanding anything to the contrary contained in the preceding sentence or elsewhere in this Section 3.4, the Borrower agrees to pay any additional amounts and to indemnify each Lender in the manner set forth in Section 3.4(a) (without regard to the identity of the jurisdiction requiring the deduction or withholding) in respect of any amounts deducted or withheld by it as described in the immediately preceding sentence as a result of any changes that are effective after the Closing Date in any applicable law, treaty, governmental rule, regulation, guideline or order, or in the interpretation thereof, relating to the deducting or withholding of such Taxes. The sole consequence of any Lender failing to comply with the requirement to deliver the Internal Revenue Service Forms or the Section 3.4(b)(ii) Certificate shall be that the Borrower shall not be obligated pursuant to Section 3.4(a) to gross-up payments to be made to such Lender in respect of any resulting U.S. income or similar taxes. -11- (c) Any Lender that is (i) an Assignee pursuant to Section 9.11(a) and (ii) not a United States person (as such term is defined in Section 7701(a)(30) of the Code) for U.S. Federal income tax purposes will certify to the Borrower on or prior to the date of the assignment to such Lender that payments to such Lender hereunder and under any Note are, as of the date of such assignment, not subject to any withholding tax imposed by any taxing jurisdiction located outside of the United States. (d) Each Lender, at the sole cost and expense of the Borrower (including, but not limited to, the Lender's internal costs for use of its personnel and resources), will use its reasonable efforts to minimize taxes indemnifiable by the Borrower under this Section 3.4, including by complying with reasonable requests by the Borrower to do or to refrain from doing any act (including the execution of any certificates or similar documents required to establish an exemption or relief from any tax), if such efforts or any such compliance is, in the good faith discretion of such Lender, of a purely ministerial nature and has no adverse impact on such Lender or any Affiliate or on the business or operations of the foregoing (unless such adverse impact is one of a nature and quality such that it is subject to indemnification and the Borrower has indemnified such Lender against such adverse impact in a manner satisfactory to such Lender determined in its sole discretion). The Borrower shall indemnify such Lender for any taxes that may be imposed on it as a consequence of such compliance. No Lender shall be required to disclose any tax return or filing or any related information it deems confidential and all positions taken by each Lender in any tax return, filing or proceeding shall be within the sole control of such Lender. 3.5 Allocation. The parties agree that the Notes issued by the ---------- Borrower under this Agreement and the Options issued by LLC under the Option Agreement, will for federal tax purposes, be treated as an "investment unit" as such term is defined under Section 1273(c)(2) of the Code and the parties agree that the consideration paid by each Lender for its Note and Option shall be allocated as set forth on Schedule 3.5. 3.6 Fee. The Borrower shall pay to (a) the Tranche A Lender the --- Commitment Fee payable to it pursuant to the terms of the Fee Letter and (b) the Tranche B Lender the Commitment Fee payable to it pursuant to the Lehman Fee Letter. 3.7 Application of Payments; Sharing. -------------------------------- (a) Subject to the provisions of this Section 3.7, the Administrative Agent agrees that promptly after its receipt of each payment from or on behalf of the Borrower in respect of any Obligations of the Borrower hereunder, it shall promptly distribute such payment to the Lenders pro rata based upon their --- ---- respective shares, if any, of the Obligations with respect to which such payment was received. (b) Each of the Lenders agrees that, if it should receive any amount hereunder (whether by voluntary payment, by realization upon security, by the exercise of the right of setoff or banker's lien, by counterclaim or cross action, by the enforcement of any right under the Financing Documents, or otherwise), which, in any such case, is in excess of its ratable share of payments on account of the Obligations obtained by all Lenders, then such Lender receiving such excess payment shall purchase for cash without recourse or warranty from the other Lenders an -12- interest in the Obligations of the Borrower to such Lenders in such amount as shall result in a proportional participation by all the Lenders in such amount; provided, however, that if all or any portion of such excess amount is - -------- ------- thereafter recovered from such Lender, such purchase shall be rescinded and the purchase price restored to the extent of such recovery, but without interest. SECTION 4. CONDITIONS PRECEDENT. -------------------- 4.1 Conditions to Closing. The obligation of any Lender to make its --------------------- Loan shall be subject to the conditions precedent that such Lender shall have received, or shall have waived receipt of, the following, each of which shall be in form and substance satisfactory to such Lender, and that the other conditions set forth below shall have been satisfied or waived by such Lender: (a) Financing Documents. Each of the Financing Documents (including ------------------- the LLC Pledge Agreement, the Stock Pledge Agreement and the Option Agreement) shall have been duly authorized, executed and delivered by each party thereto. Such Lender shall have received an original of each Financing Document executed by all parties thereto. (b) Notes. The Borrower shall have duly authorized, executed and ----- delivered a Note for the account of such Lender. Each Note shall be appropriately completed with the name of the payee, the maximum principal amount thereof and the date of issuance (which shall be the Closing Date) inserted therein. (c) Charter Documents. Such Lender shall have received the following ----------------- documents, each certified as indicated below: (i) a copy of the Charter Documents of the Borrower, LLC, NEG, Inc., the Significant Subsidiaries and the Specified Subsidiaries, as in effect on the Closing Date, certified by the Secretary of State of the State of such Person's organization, as applicable, and a certificate, where available, as to the good standing of and payment of franchise taxes by the Borrower, LLC, NEG, Inc., the Significant Subsidiaries and the Specified Subsidiaries from the Secretary of State of the State of such Person's organization, dated as of a date no earlier than 5 days prior to the Closing Date; (ii) a certificate of an Authorized Officer of each of the Borrower, LLC and NEG, Inc., dated the Closing Date, certifying (A) that attached thereto is a true and complete copy of the Charter Documents of such Person, as in effect at all times from the date on which the resolutions referred to in clause (B) below were adopted to and including the date of such certificate, (B) that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors (or other equivalent body) or evidence of all corporate, partnership or limited liability company action, as the case may be, of such Person, authorizing the execution, delivery and performance of the Financing Documents to which such Person is or is intended to be a party, and that such resolutions have not been modified, rescinded or amended and are in full force and effect, and (C) as to the name, incumbency and specimen signature of each officer of such Person executing the Financing Documents to which such Person is intended to be a party and each other document to be delivered by such Person from time to time in connection therewith; and -13- (iii) a certificate of another Authorized Officer of each of the Borrower, LLC and NEG, Inc., as to the name, incumbency and specimen signature of the Authorized Officer of such Person that signed the certificate referred to in clause (ii) above. (d) Filings, Registrations, Recordings; Other Perfection Actions. (i) ------------------------------------------------------------ On or prior to the Closing Date, such Lender shall have received certified copies of Requests for Information or Copies (Form UCC-11), or equivalent reports, each of a recent date listing all effective financing statements that name the Borrower, LLC or NEG, Inc., as debtor, together with copies of such financing statements. (ii) Any document required to be filed, registered, notarized or recorded in order to create and perfect the security interest of the Collateral Agent under the Security Documents as a first priority Lien shall have been properly filed, registered, notarized or recorded in each office in each jurisdiction in which such filings, registrations, notarizations and recordations are required, and any other action required in the judgment of any Lender to perfect such security interest as such first priority Lien shall have been effected, and such Lender shall have received acknowledgment copies or other evidence satisfactory to it that all necessary filing, notarization, recording and other fees and all taxes and expenses related to such filings, notarizations, registrations and recordings have been paid in full. (iii) The Collateral Agent shall have received the stock certificates representing 100% of the capital stock of NEG, Inc., together with related appropriate stock powers, duly executed in blank. (iv) The Collateral Agent shall have received the certificates representing 100% of the Pledged Interest of the Borrower being pledged pursuant to the LLC Pledge Agreement, together with related powers, duly executed in blank. (e) Borrower's Certificate. Such Lender shall have received an ---------------------- original counterpart of a certificate of an Authorized Officer of the Borrower, dated the Closing Date, to the effect that: (i) the representations and warranties of the Borrower contained in Section 5 hereof and the representations and warranties of the Borrower contained in each of the other Financing Documents to which the Borrower is a party are true and correct in all material respects (or in the event any such representation or warranty shall be qualified by a "Material Adverse Effect" or a materiality threshold, in all respects) on and as of the Closing Date (or, if stated to have been made solely as of an earlier date, were true and correct as of such earlier date), (ii) all covenants required to be performed by the Borrower contained in any Financing Document to which it is a party prior to the Closing Date have been performed in all material respects, (iii) all Financing Documents are in full force and effect under the terms and conditions set forth in such Financing Documents, and (iv) no Default or Event of Default has occurred and is continuing. (f) Other Officer Certificates. (i) Such Lender shall have received -------------------------- a certificate signed by an Authorized Officer of LLC, dated the Closing Date, to the effect that (i) the representations and warranties of LLC set forth in each of the Financing Documents to which it is a party are true and correct in all material respects (or in the event any such representation or warranty shall be qualified by a "Material Adverse Effect" or a materiality threshold, in all respects) -14- on and as of such date as if made on and as of the Closing Date (or, if stated to have been made solely as of an earlier date, were true and correct as of such earlier date) and (ii) all covenants required to be performed by LLC contained in any Financing Document to which it is a party prior to the Closing Date have been performed in all material respects. (ii) Such Lender shall have received a certificate signed by an Authorized Officer of NEG, Inc., dated the Closing Date, to the effect that (i) the representations and warranties of NEG, Inc. set forth in each of the Financing Documents to which it is a party are true and correct in all material respects (or in the event any such representation or warranty shall be qualified by a "Material Adverse Effect" or a materiality threshold, in all respects) on and as of such date as if made on and as of such date (or, if stated to have been made solely as of an earlier date, were true and correct as of such earlier date) and on and as of the Closing Date, and (ii) all covenants required to be performed by NEG, Inc. contained in any Financing Document to which it is a party prior to the Closing Date have been performed in all material respects. (g) Financial Information, etc. (i) Such Lender shall have received -------------------------- copies of the most recent audited and unaudited (x) consolidated financial statements from each of the Borrower and NEG, Inc. and (y) financial statements or information from each of the FI Subsidiaries, in each case, in form and substance satisfactory to such Lender together with a certificate from the Chief Financial Officer or other Authorized Officer of such Person, dated the Closing Date, to the effect that, to the best of such officer's knowledge, (A) such financial statements or information are true, complete and correct in all material respects and (B) there has been no material adverse change in the condition (financial or otherwise), results of operations, business, Properties, liabilities, management or prospects of such Person since the date of the most recent financial statements or information of such Person; provided that for -------- purposes of this clause (g), defaults or events of default in respect of the Indebtedness of the Borrower which is to be Refinanced by the proceeds of the Loan or other defaults or events of default with respect to the Borrower which are described in the SEC Filings by the Borrower since December 31, 2000 but prior to the Closing Date, and any Utility Event shall not be deemed a Material Adverse Change to such Person. (ii) Such Lender shall have received such other financial, business and other information regarding any other Subsidiary of the Borrower as such Lender shall have reasonably requested. (h) Process Agent. Such Lender shall have received a copy of a letter ------------- from CT Corporation System accepting its appointment as process agent in New York for the Borrower, LLC and NEG, Inc., in substantially the form of Exhibit D hereto. (i) Legal Opinions. Such Lender shall have received original -------------- counterparts of the legal opinions of counsel to the Borrower, LLC and NEG, Inc., which legal opinions shall be dated the Closing Date, addressed to such Lender, and in form, scope and substance satisfactory to such Lender. (j) Due Diligence. Such Lender shall have (i) completed its due ------------- diligence investigation of the organization and capital structure of the Borrower and its Subsidiaries and all -15- documents and instruments relating thereto, and other matters related to or in connection with the transactions contemplated hereby, in scope, and with results, satisfactory to such Lender in all respects, and (ii) been given such access to the management, records, books of account, contracts, concessions, and other documents relating to the business, regulatory framework and Property of the Borrower and its Subsidiaries as such Lender shall have reasonably requested. (k) Material Adverse Change. Since December 31, 2000, and except as ----------------------- disclosed in the SEC Filings by the Borrower since December 31, 2000 but prior to the Closing Date, there shall not have occurred and be continuing any Material Adverse Change of the Borrower or of LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole; provided that for purposes of this clause (k), -------- defaults or events of default in respect of the Indebtedness of the Borrower which is to be Refinanced by the proceeds of the Loan and a Utility Event shall not be deemed a Material Adverse Change to the Borrower. (l) Fees; Interest; Expenses. Such Lender shall have received the ------------------------ Commitment Fee pursuant to the Fee Letter or the Lehman Fee Letter, as the case may be, and all other fees, costs and charges due and owing under the Financing Documents on or prior to the Closing Date and shall have received its pro rata --- ---- share of the Interest Prepaid Amount required to be paid pursuant to Section 2.5. The Collateral Agent shall have received the CA Fee for payment of its services as Collateral Agent under the Financing Documents. Such Lender shall have received payment of all out-of-pocket expenses payable by the Borrower to such Lender pursuant to Section 9.1 (including reasonable fees and expenses and disbursements of legal counsel). (m) Notice of Borrowing. Such Lender shall have received a Notice of ------------------- Borrowing pursuant to and in compliance with Section 2. (n) Governmental Approvals, etc. (i) All Governmental Approvals and ---------------------------- consents or approvals from any third party which under applicable Law or any agreement, contract or document are required to be obtained by the Borrower or its Subsidiaries with respect to the transactions contemplated by the Financing Documents prior to the Closing Date shall have been duly obtained and shall be final, non-appealable and in full force and effect; (ii) there shall have been no change in any applicable Law, and no issuance of any order, writ, injunction or decree of any Governmental Authority or arbitral tribunal, which, in either such case, could reasonably be expected to have a Material Adverse Effect; and (iii) there shall have been no proposed change in or modification of any applicable Law which could reasonably be expected to be enacted and which if enacted could reasonably be expected to have a Material Adverse Effect. (o) Material Adverse Effect. There shall exist no circumstance, event ----------------------- or condition which has had or could reasonably be expected to have a Material Adverse Effect. (p) Litigation. No legal or arbitral proceedings or investigations, ---------- or any proceedings by or before any Governmental Authority or any Person, shall be pending or threatened against the transactions contemplated by the Financing Documents or any document executed in connection therewith which, if adversely determined, could reasonably be expected to have a Material Adverse Effect, and no other legal or arbitral proceedings or investigations, or any pro -16- ceedings by or before any Governmental Authority or any Person, shall be pending in respect of the Borrower, LLC, NEG, Inc. or the Significant Subsidiaries which, if adversely determined, could reasonably be expected to result in a Material Adverse Change to the Borrower, or a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole. (q) Solvency Certificate. On or before the Closing Date, the Borrower -------------------- shall cause to be delivered to such Lender a solvency certificate from the Chief Financial Officer of the Borrower in form, scope and substance satisfactory to such Lender, dated the Closing Date, setting forth the conclusion that, after giving effect to the transaction contemplated by the Financing Documents and the incurrence of all the financings contemplated herein, the Borrower (on a stand- alone basis), the Borrower and its Subsidiaries (on a consolidated basis) and LLC (on a stand-alone basis), in each case, are not insolvent and will not be rendered insolvent by the indebtedness incurred in connection therewith, and will not be left with unreasonably small capital with which to engage in its or their businesses and will not have incurred debts beyond its or their ability to pay debts as they mature and become due. (r) No Breach. Immediately prior to and after giving effect to the --------- transactions contemplated by the Financing Documents, except as disclosed in Part E of the Disclosure Letter, there shall exist no default or event of default under any material agreement or contract to which the Borrower, LLC, NEG, Inc. or any Significant Subsidiary is a party which would result in a Material Adverse Change to the Borrower, or a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole. (s) Refinancing; Existing Indebtedness. (i) On the Closing Date (but ---------------------------------- concurrently with the consummation of the transactions contemplated by the Financing Documents), all Indebtedness to be Refinanced shall have been repaid in full in the manner set forth in Part C of the Disclosure Letter by the Borrower by applying thereto the proceeds of the Loans, and all commitments in respect thereof shall have been terminated and all Liens and guaranties in connection therewith shall have been terminated (and all appropriate releases, termination statements or other instruments of assignment with respect thereto shall have been obtained) to the reasonable satisfaction of such Lender. Without limiting the foregoing, there shall have been delivered to such Lender (x) proper termination statements (Form UCC-3 or the appropriate equivalent) for filing under the UCC of each jurisdiction where a financing statement (Form UCC- 1 or the appropriate equivalent) was filed with respect to the Borrower or any of its Subsidiaries in connection with the security interest created with respect to the Indebtedness to be Refinanced and the documentation related thereto and (y) terminations of all mortgages, leasehold mortgages and deeds of trust created with respect to property of the Borrower or any of its Subsidiaries, in each case, to secure the obligations under the Indebtedness to be Refinanced, all of which shall be in form and substance satisfactory to such Lender. (ii) On the Closing Date and after giving effect to the transactions contemplated by the Financing Documents, the Borrower and LLC shall have no Indebtedness or preferred stock outstanding other than the Loan and certain other indebtedness existing on the Closing Date acceptable to such Lender as listed on Part B of the Disclosure Letter. On and as of the Closing Date, all of the existing Indebtedness under the Existing Indebtedness Agreements shall remain outstanding after giving effect to the transactions contemplated hereby without any -17- default or event of default existing thereunder or arising as a result of the transaction contemplated hereby (except to the extent amended or waived by the parties thereto on terms and conditions reasonably satisfactory to such Lender). (iii) On the Closing Date, such Lender shall have received evidence in form and substance reasonably satisfactory to such Lender that the matters set forth in this Section 4.1(s) have been satisfied. (t) [OMITTED]. ------- (u) Finality of FERC Orders. FERC shall have (i) issued final binding ----------------------- orders not subject to rehearing in Docket Nos. EC01-49-000 and EC01-41-000, and (ii) denied all motions to intervene, requests for rehearing, requests to vacate or any other relief requested in pleadings other than those by LLC or any member of NEG Group which were filed subsequent to the FERC orders in Docket Nos. EC01- 49-000 and EC01-41-000. (v) Letter. Such Lender shall have received a copy of letters ------ addressed to the Borrower from third parties, confirming the amount and type of Indebtedness of the Borrower with respect to items B and C of Part A(IV) of the Disclosure Letter to be Refinanced hereunder. (w) Business Plan. Such Lender shall have received a true and ------------- complete copy of the Business Plan, certified by an Authorized Officer of each of the Borrower, LLC and NEG, Inc. (x) Disclosure Letter. Such Lender shall have received the Disclosure ----------------- Letter. (y) Proceedings. All corporate and other proceedings, and all Charter ----------- Documents, other documents, instruments and other legal matters in connection with the transactions contemplated hereby and the other Financing Documents shall be satisfactory in form and substance to such Lender and such Lender shall have received such other documents, certificates and instruments relating to the Financing Documents or the transactions contemplated thereby as it shall have reasonably requested, in each case, in form and substance satisfactory to it. SECTION 5. REPRESENTATIONS, WARRANTIES AND AGREEMENTS. ------------------------------------------ In order to induce the Administrative Agent and each Lender to enter into this Agreement, and to induce each Lender to make its Loan, the Borrower makes the following representations, warranties and agreements as of the date hereof, all of which shall survive the execution and delivery of this Agreement and the Notes and the making and continuance of the Loans: 5.1 Standing. (a) Each of the Borrower, LLC, NEG, Inc. and each -------- Significant Subsidiary (collectively, the "Covered Parties") is a corporation, limited partnership or limited liability company duly formed, validly existing and in good standing under the laws of its jurisdiction of organization and has the requisite power and authority to own, lease and operate its Properties and to carry on its business as now being conducted. -18- (b) Each Covered Party is duly qualified or licensed to do business as a foreign entity and is in good standing in each jurisdiction in which the use and ownership of its Property or the conduct of its business requires such license or qualification, except where the failure to be so qualified or licensed would not have a Material Adverse Effect. 5.2 Requisite Authority; Etc. Each Covered Party has all requisite ------------------------- power and authority to enter into the Financing Documents to which it is a party. All necessary action on the part of each Covered Party has been taken to authorize the execution and delivery of the Financing Documents to which it is a party, the performance of its obligations under such Financing Documents and the consummation of the transactions contemplated hereby and thereby. Each of the Financing Documents has been duly and validly executed and delivered by each Covered Party that is a party thereto, and constitutes valid and binding agreements of each such Covered Party, enforceable in accordance with their respective terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general application relating to or affecting creditors' rights generally and to general principles of equity (regardless of whether such enforceability is considered in an proceeding in equity or at law). 5.3 No Conflict. Neither the execution and delivery of the Financing ----------- Documents nor the consummation of the transactions contemplated by such Financing Documents nor compliance by any Covered Party with any of the provisions of such Financing Documents to which it is a party will (i) violate or conflict with any provision of the charter, certificate of formation, by-laws or limited liability company agreement or other governing documents of such Covered Party, or any Law, judgment, order, writ, decree or injunction applicable to such Covered Party, or (ii) except as set forth in Part F of the Disclosure Letter, violate, or conflict with, or result in a breach of any provision of, or constitute a default (or any event which, with or without due notice or lapse of time, or both, would constitute a default) under, or result in the termination of, accelerate the performance required by, or, except for the Liens created by the Financing Documents, result in the creation of any Lien upon any of the Properties or assets of such Covered Party, under any contract, note, bond, mortgage, indenture, deed of trust, license, lease, agreement, permit or other instrument or obligation of which such Covered Party is a party or by which it or any of its assets are bound. 5.4 Consents. (a) No permit, application, notice, transfer, -------- consent, approval, order, qualification, waiver from or authorization of, or declaration, filing or registration with, any Governmental Authority or any third party is currently required to be made or obtained by any Covered Party or any of its Subsidiaries in connection with (i) the execution, delivery and performance of the Financing Documents or the consummation of the transactions contemplated by such Financing Documents, (ii) the grant by the Borrower or LLC, or the perfection and maintenance, of the Liens contemplated by the Financing Documents (including the first priority nature thereof) or (iii) the exercise by any party to the Financing Documents of any of its rights under any such Financing Document or any remedies pursuant to the Financing Documents, other than with respect to the exercise by any Holder of its right to convert the Option to Option Shares under the Option Agreement which may require filing under the HSR Act or with FERC or the exercise of the foreclosure rights with respect to the stock of NEG, Inc. or the LLC Interests which may require filing with FERC and certain state regulatory agencies. -19- (b) No right of first refusal, preemptive right, right of first offer or other similar rights to acquire (each a "Preferential Right") are required to ------------------ be complied with by any Covered Party or any of its Subsidiaries in connection with the execution, delivery or performance of the Financing Documents or the consummation of the transactions contemplated by the Financing Documents. 5.5 Compliance with Law. Each of the Borrower and each member of the ------------------- NEG Group and each Scheduled Project has been and on the Closing Date is in compliance in all material respects with all Laws, Governmental Approvals, orders, writs, injunctions or decrees or its Charter Documents applicable to or otherwise concerning such Person and such Scheduled Project. 5.6 Litigation Claims. Except as set forth on Schedule 5.6, there ----------------- are no legal or arbitral proceedings or investigations, or any proceedings by or before any Governmental Authority or any Person, pending or threatened against the transactions contemplated by the Financing Documents or any document executed in connection therewith which could reasonably be expected to have a Material Adverse Effect, and there are no other legal or arbitral proceedings or investigations, or any proceedings by or before any Governmental Authority or any Person pending against the Borrower, LLC, NEG, Inc. or the Significant Subsidiaries which could reasonably be expected to result in a Material Adverse Change to the Borrower, or a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole. 5.7 Contracts and Commitments. (a) Schedule 5.7 reflects a complete ------------------------- and accurate list of all material contracts, agreements or letters of intent or written understandings (including all amendments and supplements thereto) entered into by any Covered Party (collectively, the "Covered Contracts") (it being understood that any contract, agreement or letter of intent or written understanding (i) entered in the ordinary course of business of the Covered Parties, or (ii) with respect to Indebtedness of any such Covered Party that is non-recourse to such Covered Party, or (iii) requiring aggregate payments of less than $10,000,000 or (iv) with a fixed term of less than three hundred and sixty-four (364) days shall not be deemed to be a "material" contract, agreement or letter of intent or written understanding). (b) Except as otherwise set forth on Part E of the Disclosure Letter, (i) each of the Covered Contracts is a valid and binding obligation of the Covered Party which is a party thereto and enforceable by the Covered Parties (as applicable) in accordance with its terms, except as enforcement may be limited by bankruptcy, insolvency, reorganization or similar laws or equitable principles relating to creditors' rights generally; (ii) none of the Covered Parties party to any Covered Contract is in default or alleged to be in default under any Covered Contract, and no other asserted or, to the best knowledge of the Borrower, LLC and NEG, Inc., unasserted claim or dispute under any Covered Contract exists; and (iv) to the best knowledge of the Borrower, there exists no event, condition or occurrence that, after notice or lapse of time, or both, would constitute such a default, claim or dispute by the Covered Parties or, to the best knowledge of the Borrower, any other party to any such Covered Contract. -20- 5.8 Liens. Except as set forth on Schedule 5.8, none of the ----- Properties of the Borrower, LLC or NEG, Inc. are subject to any Lien, other than the Liens created by this Agreement and the Security Documents. 5.9 Insurance. All insurance policies and fidelity bonds relating to --------- the Covered Parties and their Properties, including summary descriptions and the termination dates thereof, in force as of the date of this Agreement are set forth on Schedule 5.9. The insurance coverage provided by such policies will not terminate or lapse as a result of the transactions contemplated by this Agreement or the other Financing Documents. Except as set forth on Schedule 5.9, all such insurance policies and fidelity bonds are in the name of the Borrower, LLC, NEG, Inc. or a NEG Subsidiary (as indicated on Schedule 5.9). None of the Covered Parties or, to the best knowledge of the Borrower, any other party to any such policy or bond is in breach, violation or default (including with respect to the payment of premiums or the giving of notices), and, to the best knowledge of the Borrower, no event has occurred that, with notice or the lapse of time or both, could constitute such a breach, violation or default by the Covered Parties or any other party, or permit termination, modification or acceleration, under such policy or bond, except where any such breach, violation, default, termination, modification or acceleration could not reasonably be expected to have a Material Adverse Effect. 5.10 Capitalization and Ownership. (a) As of the Closing Date, the ---------------------------- Borrower and Energy NEG Corp. are the sole members of LLC, with the Borrower owning all of the Class A membership interests of the LLC, which entitle the Borrower to 100% of the economic interest in LLC, and Energy NEG Corp. owning all of the Class B membership interests of LLC, which entitle Energy NEG Corp. to vote solely on certain bankruptcy matters of LLC as provided for in the LLC Agreement. The Borrower is (and at all times prior to the Closing Date from and after January 12, 2001, was) the owner of 100% of the Class A membership interests in LLC and is (and at all times prior to the Closing Date from and after January 12, 2001, was) the indirect owner (through the Limited Liability Company Interests) of 100% of NEG, Inc. and the NEG Subsidiaries. (b) LLC is (and at all times prior to the Closing Date from and after January 12, 2001,was) the sole direct owner of all of the outstanding Capital Stock of NEG, Inc., free and clear of all Liens and adverse claims, other than the Liens in favor of the Collateral Agent created by the Security Documents. (c) NEG, Inc. is (and at all times prior to the Closing Date from and after January 1, 1999, was) the ultimate sole parent other than companies owning NEG, Inc. directly or indirectly, of all Significant Subsidiaries and other NEG Subsidiaries. (d) (i) All of the Limited Liability Company Interests have been duly authorized and, at the Closing Date, are and will be validly issued, free and clear of all Liens and adverse claims, other than the Liens in favor of the Collateral Agent created by the Security Documents. (ii) All shares of the Capital Stock of NEG, Inc. have been duly authorized and, at the Closing Date, are and will be validly issued and fully paid and nonassessable and are -21- owned by LLC, free and clear of all Liens and adverse claims, other than the Liens in favor of the Collateral Agent created by the Security Documents. (e) Except as set forth in Schedule 5.10(e), no Person other than a member of the NEG Group owns (i) any outstanding option, warrant, purchase right, subscription right, conversion right, exchange right or other contract, commitment, arrangement or understanding relating to the issuance by or purchase from the Borrower of its LLC Interests, LLC, NEG, Inc. or any Significant Subsidiary of its Equity Interests (as defined below), or (ii) any outstanding stock appreciation, phantom stock, profit participation or similar rights with respect to LLC, NEG, Inc. or any Significant Subsidiary, and there are no voting trusts, proxies or other agreements or understandings with respect to the voting of LLC Interests or Equity Interests to which the Borrower, LLC, NEG, Inc. or any Significant Subsidiary is party. (f) Schedule 5.10(f) sets forth for each of the Borrower, LLC, NEG, Inc. and the NEG Subsidiaries a complete and accurate listing of (i) its name and jurisdiction of organization, (ii) its form of organization and (iii) the percentage (and, where applicable, the amount) of capital stock, partnership interests (general and limited), membership interests or other equity interests ("Equity Interests") held directly or indirectly by the Borrower. 5.11 Financial Statements; Absence of Certain Changes. (a) Prior to ------------------------------------------------ the execution of this Agreement, the Borrower has delivered to the Administrative Agent and each Lender the following financial statements, each of which has been certified by the Chief Financial Officer of the relevant Person specified below: (i) (x) the audited consolidated financial statements of the Borrower as at December 31, 1999, and (y) the unaudited consolidated financial statements of the Borrower as at June 30, 2000 and September 30, 2000, and the unaudited consolidating balance sheet and income statement of the Borrower as at November 30, 2000, which statement has been prepared on a management basis and does not include accompanying notes; (ii) (x) the audited financial statements of each of the FI Subsidiaries as at December 31, 1999, and (y) the unaudited financial statements of each of the FI Subsidiaries as at June 30, 2000 and September 30, 2000, and the unaudited draft financial statements of each such FI Subsidiary as at December 31, 2000; (iii) the unaudited consolidated balance sheet and income statements of NEG, Inc. as at December 31, 1999 and the estimated unaudited financial statements of NEG, Inc. as at December 31, 2000. Any audited financial statements (the "Audited Financial Statements") described in this Section 5.11(a) (complete with any appropriate footnote disclosures) present fairly the financial position of the relevant Person as at December 31, 1999, and were prepared in accordance with GAAP, consistently applied. Any unaudited financial statements (the "Unaudited Financial Statements") described in this Section 5.11(a) present fairly the financial position of the relevant Person as at -22- such dates. Such Audited Financial Statements and Unaudited Financial Statements have been prepared from the books of account and financial records of the relevant Person. (b) Since December 31, 2000 and except as disclosed in the SEC Filings by the Borrower since December 31, 2000 but prior to the Closing Date, the Borrower and all members of the NEG Group have conducted their business only in the ordinary course of business, and there has not been (i) any event or development that could, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect or (ii) any damage, destruction or loss, whether or not covered by insurance, that could, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. Except as set forth in the Audited Financial Statements or otherwise disclosed in writing to each Lender in the Disclosure Letter or incurred in the ordinary course of business, none of the Covered Parties or any other NEG Subsidiary has any outstanding claims, liabilities or indebtedness, contingent or otherwise. 5.12 Taxes. (a) Each of the Covered Parties and its Subsidiaries has filed ----- or caused to be filed with the appropriate taxing authorities all material federal, state and local tax returns ("Returns") which are required to be filed by or with respect to each such Covered Party, its Subsidiaries, or any assets thereof. The Returns accurately reflect (or will accurately reflect) all liabilities for Taxes of each such Covered Party or Subsidiary for the periods covered thereby in all material respects. All material Taxes due by or with respect to each such Covered Party or Subsidiary, or any assets thereof, whether or not shown on any Return, have been or will be timely paid in full on or prior to the Closing Date or accrued and provided for on the books and records of each such Person, as applicable, in accordance with GAAP. There is no dispute or claim concerning any liability for Taxes of each of the Covered Parties, its Subsidiaries, or any assets thereof that has been claimed or raised by any Governmental Authority, except for disputes or claims for Taxes that have been provided for on the books and records of each such Person, as applicable, in accordance with GAAP. No Return of any of the Covered Parties, their Subsidiaries, or the affiliated group of the Borrower is currently, or has been, the subject of an audit by any taxing authority and no notice of such an audit has been received, except for audits with respect to Taxes that have been provided for on the books and records of each such Covered Party and its Subsidiaries, as applicable, in accordance with GAAP. None of the Covered Parties or any of their Subsidiaries have waived any statute of limitations in respect of Taxes or agreed to any extension of time with respect to a Tax assessment or deficiency, except with respect to Taxes that have been provided for on the books and records of each such Covered Party and its Subsidiaries, as applicable, in accordance with GAAP. (b) All material Taxes which a Covered Party or any of its Subsidiaries is (or was) required by Law to withhold or collect with respect to any payments made in connection with its Property have been duly withheld or collected, and have been timely paid over to the appropriate authorities to the extent due and payable. 5.13 Disclosure. All documents, reports or other written information ---------- pertaining to the Covered Parties or its Affiliates that have been furnished to the Lenders by or on behalf of the Covered Parties, taken as a whole, are true and correct in all material respects and do not contain any untrue statement of a material fact or omit to state any material fact necessary to make the statements contained therein not misleading. There is no fact, event or circumstance -23- that has not been disclosed to the Lenders in writing, the existence of which could reasonably be expected to have a Material Adverse Effect or a Material Adverse Change of NEG, Inc. and the NEG Subsidiaries, taken as a whole. 5.14 Environmental Matters. Except as set forth in Schedule 5.14, (a) each --------------------- of the Borrower and the members of the NEG Group is in compliance in all material respects with all applicable Environmental Laws, (b) there is no Environmental Claim outstanding or pending against the Borrower or any member of the NEG Group or, to the best knowledge of the Borrower, threatened against the Borrower or any member of the NEG Group, which, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect or to result in a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken as a whole, and (c) to the best knowledge of the Borrower, LLC and NEG, Inc., none of the Covered Parties or other NEG Subsidiary has made any past or present releases, emissions, discharges or disposals of any Hazardous Material in violation of any Environmental Laws or that would give rise to any liability which, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect or a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken as a whole. 5.15 Brokers' or Finders' Fees. Except as set forth in Schedule 5.15 (as to ------------------------- which the Borrower is solely responsible for the payment of any such investment banker's, brokers' or finders' fee or other commission or similar fee), no agent, broker, investment banker, Person or firm acting on behalf of the Covered Parties or any of their Affiliates or under the authority of the Borrower or any of its Affiliates is or will be entitled to any brokers' or finders' fee or any other commission or similar fee directly or indirectly from any of the parties hereto in connection with any of the transactions contemplated hereby. 5.16 Certain Regulatory Matters. (a) Neither Borrower nor any Subsidiary of -------------------------- Borrower is a "registered holding company" or a "subsidiary company" or an "affiliate" of a "registered holding company" or a company which is required to be registered as a "holding company" as such terms are defined under PUHCA. (b) Each member of the NEG Group that owns assets subject to the jurisdiction of FERC pursuant to the FPA or sells power at wholesale in the United States is and at all relevant times has been either: (i) a QF; (ii) certified by FERC as an EWG, has been granted by FERC the waivers from regulation under the FPA typically granted to EWGs with market rate authority, and has been granted by FERC market rate authority without qualifications, conditions or restrictions other than those typically imposed on utility affiliates; or (iii) a power marketer which owns no physical assets used for the generation, transmission or distribution of electric energy as such terms are used in PUHCA, has been granted by FERC the waivers from regulation under the FPA typically granted to power marketers, and has been granted by FERC market rate authority without qualifications, conditions or restrictions other than those typically imposed on utility affiliates. The applications and additional information submitted in connection with the certifications for QF status, applications for EWG certification, applications for power marketer status, and applications for market rate authority were accurate and complete in all material respects when made and, as amended or supplemented from time-to-time, remained at all relevant times and currently remain accurate and complete in all respects affecting the eligibility for QF -24- status, EWG status, power marketer status, or market rate authority as applicable, and each such FERC authorization or certification is in full force and effect. (c) Each member of the NEG Group (other than a QF during the period during which it was a QF) that owns assets subject to the jurisdiction of FERC pursuant to the FPA or sells power at wholesale in the United States has charged rates or provided services only pursuant to either: (i) one or more rate schedules on file with FERC; or (ii) market rate contracts in compliance with such entity's market rate authority from FERC. Each QF during the period it was a QF has sold power only in a manner consistent with its status as a QF. (d) Each member of the NEG Group which owns natural gas assets, sells natural gas or provides services subject to the jurisdiction of FERC pursuant to the Natural Gas Act, as amended, or the Natural Gas Policy Act of 1978, as amended, (i) has a rate schedule on file with FERC; (ii) has charged rates and provided services only pursuant to such filed rates; and (iii) has complied and complies in all material respects with the requirements of FERC orders applicable to such member of the NEG Group. (e) No member of the NEG Group is subject to Utility Regulation other than as set forth in Schedule 5.16(e). (f) Neither the Borrower nor LLC directly owns any assets subject to the jurisdiction of FERC pursuant to the FPA. (g) Except with respect to material licenses issued for the Brayton Point and Salem Harbor Stations for monitoring equipment used to measure coal supply, no member of the NEG Group is subject to regulation under the Atomic Energy Act of 1954. (h) The Borrower and each of its Subsidiaries is in material compliance with all orders of the CPUC applicable to it, including without limitation, the conditions set forth in the orders setting forth the conditions for the creation of the Borrower and any subsequent CPUC proceedings, Pacific Gas and Electric ------------------------ Company, 69 CPUC2nd 167 (Nov. 6, 1996), Pacific Gas and Electric Company, 194 - ------- -------------------------------- PUR4th 1 (April 22, 1999), and all other CPUC orders purporting to apply to the Borrower or its Subsidiaries regardless of whether the CPUC had jurisdiction. (i) The Borrower and each of its Subsidiaries subject to Utility Regulations is in material compliance with the requirements of Utility Regulation applicable to it. (j) None of the Borrower or any member of the NEG Group is subject to any statute or regulation which would prohibit or require approval of the transactions contemplated under this Agreement and the other Financing Documents, including any Utility Regulation. 5.17 Transactions With Affiliates. Except as set forth on Schedule 5.17, ---------------------------- neither the Borrower nor any of its Subsidiaries is a party to any material contract (i) with PGE Utility on the one hand and Borrower or any member of the NEG Group on the other, or (ii) with the Borrower on the one hand and any member of the NEG Group on the other. -25- 5.18 Use of Proceeds. The proceeds of the Loans will be used for the --------------- Refinancing in accordance with the provisions of this Agreement. The Borrower is not engaged principally, or as one of its important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of buying or carrying Margin Stock and no part of the proceeds of the Loans will be used to purchase or carry any Margin Stock. Neither the making of the Loans nor the use of the proceeds thereof will violate or be inconsistent with the provisions of Regulation U or Regulation X. 5.19 Compliance with ERISA. (i) Schedule 5.19 sets forth each Plan; each --------------------- Plan (and each related trust, insurance contract or fund) is in substantial compliance with its terms and with all applicable laws, including without limitation ERISA and the Code; each Plan (and each related trust, if any) which is intended to be qualified under Section 401(a) of the Code has received a determination letter from the Internal Revenue Service to the effect that it meets the requirements of Sections 401(a) and 501(a) of the Code; no Reportable Event has occurred; no Plan which is a multiemployer plan (as defined in Section 4001(a)(3) of ERISA) is insolvent or in reorganization; no Plan has an Unfunded Current Liability; no Plan which is subject to Section 412 of the Code or Section 302 of ERISA has an accumulated funding deficiency, within the meaning of such sections of the Code or ERISA, or has applied for or received a waiver of an accumulated funding deficiency or an extension of any amortization period, within the meaning of Section 412 of the Code or Section 303 or 304 of ERISA; all contributions required to be made with respect to a Plan have been timely made; neither the Borrower nor any Subsidiary of the Borrower nor any ERISA Affiliate has incurred any material liability (including any indirect, contingent or secondary liability) to or on account of a Plan pursuant to Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201, 4204 or 4212 of ERISA or Section 401(a)(29), 4971 or 4975 of the Code or expects to incur any such liability under any of the foregoing sections with respect to any Plan; no condition exists which presents a material risk to the Borrower or any Subsidiary of the Borrower or any ERISA Affiliate of incurring a liability to or on account of a Plan pursuant to the foregoing provisions of ERISA and the Code; no proceedings have been instituted to terminate or appoint a trustee to administer any Plan which is subject to Title IV of ERISA; no action, suit, proceeding, hearing, audit or investigation with respect to the administration, operation or the investment of assets of any Plan (other than routine claims for benefits) is pending, expected or threatened; using actuarial assumptions and computation methods consistent with Part 1 of subtitle E of Title IV of ERISA, the aggregate liabilities of the Borrower and its Subsidiaries and its ERISA Affiliates to all Plans which are multiemployer plans (as defined in Section 4001(a)(3) of ERISA) in the event of a complete withdrawal therefrom, as of the close of the most recent fiscal year of each such Plan ended prior to the date of the most recent Credit Event, would not exceed $100,000; each group health plan (as defined in Section 607(1) of ERISA or Section 4980B(g)(2) of the Code) which covers or has covered employees or former employees of the Borrower, any Subsidiary of the Borrower, or any ERISA Affiliate has at all times been operated in compliance with the provisions of Part 6 of subtitle B of Title I of ERISA and Section 4980B of the Code; no lien imposed under the Code or ERISA on the assets of the Borrower or any Subsidiary of the Borrower or any ERISA Affiliate exists or is likely to arise on account of any Plan; and the Borrower and its Subsidiaries may cease contributions to or terminate any employee benefit plan maintained by any of them without incurring any material liability. -26- (ii) Each Foreign Pension Plan has been maintained in substantial compliance with its terms and with the requirements of any and all applicable laws, statutes, rules, regulations and orders and has been maintained, where required, in good standing with applicable regulatory authorities. All contributions required to be made with respect to a Foreign Pension Plan have been timely made. Neither the Borrower nor any of its Subsidiaries has incurred any obligation in connection with the termination of, or withdrawal from, any Foreign Pension Plan. The present value of the accrued benefit liabilities (whether or not vested) under each Foreign Pension Plan, determined as of the end of the Borrower's most recently ended fiscal year on the basis of actuarial assumptions, each of which is reasonable, did not exceed the current value of the assets of such Foreign Pension Plan allocable to such benefit liabilities. 5.20 Investment Company Act. The Borrower is not an "investment company," ---------------------- or an "affiliated person" of, or "promoter" or "principal underwriter" for, an "investment company," as such terms are defined in the Investment Company Act of 1940, as amended. Neither the making of any Loan, nor the application of the proceeds or repayment thereof by the Borrower, nor the consummation of the other transactions contemplated hereby will violate any provisions of such Act or any rule, regulation or order of the SEC thereunder. 5.21 Regulation. Solely by virtue of the execution, delivery and ---------- performance of, or the consummation of the transactions contemplated by the Financing Documents (including, without limitation, the assignment of or transfer into any trust, or any realization or foreclosure upon, any of the LLC Interests pledged under the LLC Pledge Agreement or any of the collateral pledged under the Stock Pledge Agreement, or the exercise of any right under the Option Agreement), neither any Holder nor any Lender shall be or become subject to regulation (i) as a "holding company," or an "affiliate" of a "holding company" or a "subsidiary company" of a "holding company," within the meaning of the Public Utility Holding Company Act of 1935, (ii) under the Federal Power Act of 1920, or (iii) as a "public utility" or "public service corporation" or the equivalent under the applicable Law of any Governmental Authority, except with respect to the exercise of the foreclosure rights with respect to the stock of NEG, Inc. or the LLC Interests which may require filing with FERC and certain state regulatory agencies. 5.22 Security Documents. The provisions of the Security Documents are ------------------ effective to create, in favor of the Collateral Agent, for the benefit of the Lenders, legal, valid and enforceable Liens on or in all of the collateral intended to be covered thereby, and all necessary recordings and filings have been made in all necessary public offices and all other necessary and appropriate action has been taken so that the Liens created by each Security Document constitute perfected Liens on or in the collateral intended to be covered thereby, prior and superior to all other Liens, and all necessary consents to the creation, effectiveness, priority and perfection of each such Lien have been obtained. No mortgage or financing statement or other instrument or recordation covering all or any part of the collateral is on file in any recording office, except such as may have been filed in favor of the Collateral Agent, for the benefit of the Lenders. 5.23 Certain Scheduled Projects. Schedule 5.23 sets forth a complete list -------------------------- of all projects owned directly or indirectly by the Borrower, LLC, NEG, Inc. and the NEG Subsidiaries ("Scheduled Projects") and a summary of material ------------------ information with respect thereto, including the name, location, capacity and classification of each Scheduled Project as a QF, EWG or otherwise, -27- the equity structure, and the amount of Indebtedness, with respect to each Scheduled Project and such other information requested by the Lenders. 5.24 Environmental Matters. (a) The Borrower, LLC, NEG, Inc. and the NEG --------------------- Subsidiaries have complied and are now complying in all material respects with (i) all Environmental Laws applicable to the Scheduled Projects and (ii) the requirements of any Governmental Approvals issued under such Environmental Laws with respect to the Scheduled Projects. (b) Except as set forth in Schedule 5.14, there are no facts, circumstances, conditions or occurrences regarding any of the Scheduled Projects that (i) to the best knowledge of the Borrower, could reasonably be anticipated to form the basis of an Environmental Claim against such Scheduled Project, the Borrower, LLC, NEG, Inc. or any NEG Subsidiary or, to the best knowledge of the Borrower, or any other Person occupying or conducting operations on or about such Scheduled Project which if adversely determined could reasonably be expected to have a Material Adverse Effect or a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken as a whole, (ii) could reasonably be anticipated to cause such Scheduled Project to be subject to any material restrictions on its ownership, occupancy, use or transferability under any Environmental Law or (iii) could be reasonably anticipated to require the filing or recording of any material notice, registration, permit or disclosure document under any Environmental Law. (c) Except as set forth in Schedule 5.14, there are no past, pending, or, to the best knowledge of the Borrower, threatened, Environmental Claims against the Borrower, LLC, NEG, Inc., or any of the Scheduled Projects, which if adversely determined could reasonably be expected to have a Material Adverse Effect or a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken as a whole. (d) Hazardous Materials have not at any time been generated, used, treated, recycled, stored on, or transported to or from, or Released, deposited or disposed of on all or any portion of any Scheduled Project other than in compliance at all times with all applicable Environmental Laws, except to the extent such non-compliance, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect or a Material Adverse Change to NEG, Inc., and the NEG Subsidiaries, taken as a whole. (e) There are not now and, to the best knowledge of the Borrower, never have been any underground storage tanks located on the Scheduled Projects and there is no asbestos contained in, forming part of, or contaminating, any part of the Scheduled Projects, and no polychlorinated biphenyls (PCBs) are used, stored, located at or contaminate any part of the Scheduled Projects, the existence of which, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect or a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken as a whole. 5.25 Intellectual Property. Each of the Covered Parties owns or has the --------------------- right to use all patents, trademarks, permits, service marks, trade names, copyrights, franchises, formulas, licenses and other rights with respect thereto, and has obtained assignment of all licenses and other rights of whatsoever nature necessary for the operation of its business as currently contem- -28- plated without any conflict with the rights of others. To the best knowledge of the Borrower, no product, process, method, substance, part or other material sold or employed or presently contemplated to be sold by or employed by any of the Covered Parties in connection with its business infringes or will infringe any patent, trademark, permit, service mark, trade name, copyright, franchise, formula, license or other intellectual property right. 5.26 No Default. No Default or Event of Default has occurred and is ---------- continuing. 5.27 Single-Purpose Entity. LLC has not engaged in any business other than --------------------- the ownership of 100% of the capital stock of NEG, Inc. LLC has established offices at 7500 Old Georgetown Road, Bethesda, MD 20814-6161, and does not have a place of business at any other location. LLC has no Indebtedness and no significant assets other than the common stock of NEG, Inc. 5.28 Trust Indenture Act. The offering, issuance, sale and delivery of the ------------------- Notes under the circumstances contemplated by this Agreement and the other Financing Documents will not require this Agreement to be qualified under the Trust Indenture Act of 1939, as amended. 5.29 [OMITTED] 5.30 Ratings Letter. Since January 19, 2001, none of NEG, Inc. or any -------------- Significant Subsidiary has knowledge of or received any notice of a downgrade of the credit rating of its long-term senior unsecured indebtedness or its being placed on "credit watch" by Moody's or Standard & Poor's. 5.31 Certain Indebtedness. Part A of the Disclosure Letter sets forth a -------------------- true and complete list of all Indebtedness of the Borrower and the amount thereof immediately prior to the Closing Date. Part B of the Disclosure Letter sets forth a true and complete list of all agreements with respect to the Indebtedness of the Borrower and the amount thereof existing on the Closing Date which, subject to Section 7.4, is to remain outstanding after the Closing Date (the "Existing Indebtedness Agreements"). Except as set forth on Part B, C and D -------------------------------- of the Disclosure Letter, all Indebtedness of the Borrower will be Refinanced and repaid in full as at the Closing Date and all commitments in respect thereof and all Liens and guaranties in connection therewith are terminated, and no Person shall have any claim against the Borrower and the Borrower shall have no further obligations with respect thereto. NEG, Inc. has made all reasonable efforts to offer to repay, refinance or otherwise release the obligations of the Borrower under such Indebtedness listed on Clauses I, II and III of Part B of the Disclosure Letter, including the obligations of the Borrower under the Equity Infusion Agreement and the Trading Contracts. Except as set forth in Part B of the Disclosure Letter, none of the obligations of the Borrower under the Existing Indebtedness Agreements are due and payable as of the Closing Date, and there has been no demand on the Borrower, and the Borrower is not currently liable, for any payment under such Existing Indebtedness Agreements. -29- SECTION 6. AFFIRMATIVE COVENANTS. --------------------- The Borrower hereby covenants and agrees that in the case of the covenants described below on and after the Closing Date and until the Loans and the Notes together with interest, fees and all other Obligations incurred hereunder and thereunder are paid in full (other than any indemnity, not then due and payable, which by its terms shall survive such termination and payment): 6.1 Information Covenants. The Borrower will, or will cause the --------------------- Covered Parties to, furnish to each Lender: (a) Quarterly Financial Statements. Within 45 days after the close of ------------------------------ the first three quarterly accounting periods in each fiscal year of the relevant Person specified below, (i) the consolidated and consolidating balance sheets of each of (x) the Borrower and its consolidated subsidiaries, (y) NEG, Inc. and its consolidated subsidiaries, and (ii) the condensed consolidated balance sheets of the Significant Subsidiaries and their consolidated subsidiaries, as at the end of such quarterly accounting period and the related consolidated and consolidating statements of income and cash flows, in each case for such quarterly accounting period and for the elapsed portion of the fiscal year ended with the last day of such quarterly accounting period, and in each case, setting forth comparative figures for the related periods in the prior fiscal year, all of which shall be certified by the Chief Financial Officer of the relevant Person, subject to normal year-end audit adjustments. (b) Annual Financial Statements. Within 90 days after the close of --------------------------- each fiscal year commencing with the fiscal year 2001, and within 110 days after the close of the fiscal year 2000, of the relevant Person specified below, (i) the consolidated balance sheets of each of (x) the Borrower and its consolidated subsidiaries, (y) NEG, Inc. and its consolidated subsidiaries, and (ii) the balance sheets of each of the FI Subsidiaries as at the end of such fiscal year and in each case, the related statements of income and retained earnings and of cash flows for such fiscal year, consolidated or otherwise, as applicable, setting forth comparative figures for the preceding fiscal year and in the case of all such balance sheets certified by Deloitte & Touche LLP, or such other independent certified public accountants of recognized national standing reasonably acceptable to the Lenders, together with a report of such accounting firm stating that in the course of its regular audit of the financial statements of any of (A) the Borrower and its consolidated subsidiaries, or (B) NEG, Inc. or any of its consolidated subsidiaries or (C) any of the FI Subsidiaries, as the case may be, which audit was conducted in accordance with generally accepted auditing standards, such accounting firm obtained no knowledge of any Default or Event of Default which has occurred and is continuing or, if in the opinion of such accounting firm such a Default or Event of Default has occurred and is continuing, a statement as to the nature thereof, and (iii) management's discussion and analysis of the Borrower of the important operational and financial developments during such fiscal year. -30- (c) Management Letters. Promptly after the receipt thereof by the ------------------ Borrower or any of its Subsidiaries, a copy of any "management letter" received by any such Person from its certified public accountants and the management's responses thereto. (d) [OMITTED] ------- (e) Officer's Certificates. At the time of the delivery of the ---------------------- financial statements provided for in Section 6.1(a) and (b), a certificate of the Chairman of the Board, the President or Chief Financial Officer of the Borrower to the effect that, to the best of such officer's knowledge, no Default or Event of Default has occurred and is continuing or, if any Default or Event of Default has occurred and is continuing, specifying the nature and extent thereof. (f) Notice of Default or Litigation, etc. Promptly, and in any event ------------------------------------ within three (3) Business Days after an officer of the Borrower or any other Covered Party obtains knowledge thereof, notice of (i) the occurrence of any event which constitutes a Default or Event of Default, (ii) any litigation or governmental investigation or proceeding pending or threatened (x) against the Borrower or any of its Subsidiaries which would reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole, (y) with respect to any Indebtedness in excess of $10,000,000 of the Borrower or any of its Subsidiaries or (z) with respect to any Financing Document, (iii) downgrade of the credit rating of the long-term senior unsecured indebtedness of the Borrower or any other Covered Party or "negative watch" by Moody's or Standard & Poor's, and (iv) demand for satisfaction of any guaranty or other Contingent Obligations of the Borrower or any other Covered Party. (g) Other Reports and Filings. Promptly, copies of all financial ------------------------- information, proxy materials and other information and reports, if any, which the Borrower or any of its Subsidiaries shall receive from FERC, CPUC or SEC or file with FERC, CPUC or SEC, which could reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole, or deliver to holders of its material Indebtedness pursuant to the terms of the documentation governing such Indebtedness (or any trustee, agent or other representative therefor) and holders of their capital stock in their capacity as such. (h) Environmental Matters. Promptly upon, and in any event within --------------------- thirty (30) days after, an officer of the Borrower or any other Covered Party obtains knowledge thereof, notice of one or more of the following environmental matters which occurs after the Closing Date, unless such environmental matters would not, individually or when aggregated with all other such environmental matters, be reasonably expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole: -31- (i) any Environmental Claim pending or threatened in writing against the Borrower or any of its Subsidiaries or any Real Estate owned or operated or occupied by the Borrower or any of its Subsidiaries; (ii) any condition or occurrence on or arising from any Real Estate owned or operated or occupied by the Borrower or any of its Subsidiaries that (a) results in noncompliance by the Borrower or any of its Subsidiaries with any applicable Environmental Law or (b) would reasonably be expected to form the basis of an Environmental Claim against the Borrower or any of its Subsidiaries or any such Real Estate; (iii) any condition or occurrence on any Real Estate owned or operated or occupied by the Borrower or any of its Subsidiaries that would reasonably be expected to cause such Real Estate to be subject to any restrictions on the ownership, occupancy, use or transferability by the Borrower or any of its Subsidiaries of such Real Estate under any Environmental Law; and (iv) the taking of any removal or remedial action in response to the actual or alleged presence of any Hazardous Material on any Real Estate owned or operated or occupied by the Borrower or any of its Subsidiaries as required by any Environmental Law or any governmental or other administrative agency; provided that in any -------- event the Borrower shall deliver to each Lender all material notices received by it or any of its Subsidiaries from any government or governmental agency under, or pursuant to, CERCLA. All such notices shall describe in reasonable detail the nature of the claim, investigation, condition, occurrence or removal or remedial action and the Borrower's or such Subsidiary's response thereto. In addition, the Borrower will provide each Lender, from time to time, with copies of periodic environmental audit and associated final closeout reports audited by the environmental management system of any member of the NEG Group and annual environmental compliance report prepared by any member of the NEG Group, and copies of all material communications with any government or governmental agency and all material communications with any Person relating to any Environmental Claim as to which notice is required to be given pursuant to this Section 6.1(h), and such detailed reports of any such Environmental Claim as to which notice is required, as may reasonably be requested by any Lender. (i) [OMITTED] ------- (j) Intercompany Transaction. From time to time, such information or ------------------------ document with respect to any commitment, memorandum of understanding or agreement, whether in writing or not, with respect to material transactions between (i) any of the Borrower and any member of the NEG Group or (ii) between or among any of the Borrower and any member of the NEG Group, on one hand and PGE Utility and any of its Subsidiaries, on the other hand. -32- (k) Certain Other Information. Concurrently therewith, any financial ------------------------- information provided by NEG, Inc. to its lenders, noteholders or bondholders pursuant to the terms of the credit agreement, loan agreement or other equivalent instrument. (l) Quarterly Meetings with Lender. At the request of the ------------------------------ Administrative Agent, within 50 days after the close of each fiscal quarter the Borrower shall hold a meeting at a reasonable time and place selected by the Borrower and acceptable to each Lender at which meeting shall be reviewed the financial results of the previous fiscal quarter and the financial condition of the Borrower and its Subsidiaries and the budgets presented for the current fiscal quarter of the Borrower and its Subsidiaries. (m) Cash Reserve Certificate. At the time of delivery of the ------------------------ quarterly financial statements pursuant to clause (a) above, a certificate of an officer of the Borrower certifying that it is in compliance with Section 6.18 and setting forth in reasonable detail the calculation and the amount of cash and Cash Equivalents held by the Borrower with respect to such compliance at such time. (n) Other Information. From time to time, such other information or ----------------- documents (financial or otherwise) with respect to the Borrower or its Subsidiaries as the Administrative Agent or any Lender may reasonably request in writing. 6.2 Books, Records and Inspections. The Borrower will, and will ------------------------------ cause all members of the NEG Group to, keep proper books of record and account in which are made full, true and correct entries in conformity with generally accepted accounting principles and all requirements of law. The Borrower will, and will cause the other Covered Parties to, permit officers and designated representatives of any Lender to visit and inspect, during regular business hours and under guidance of officers of the Borrower, any of the properties of the Borrower and the other Covered Parties in whomsoever's possession, and to examine the books of account of the Borrower and the other Covered Parties and discuss the affairs (including environmental matters), finances and accounts of the Borrower and the other Covered Parties with, and be advised as to the same by, its and their officers and independent accountants, all upon reasonable advance notice and at such reasonable times and intervals and to such reasonable extent as such Lender may request, provided, that so long as no Default or Event -------- of Default has occurred and is continuing, the Borrower shall have the right to participate in any discussions of the Lender with any independent accountants of the Borrower. 6.3 Maintenance of Property; Insurance. The Borrower will, and will ---------------------------------- cause all members of the NEG Group to, (i) keep all material properties and equipment used in its business in good working order and condition (ordinary wear and tear and loss or damage by casualty or condemnation excepted), (ii) maintain in full force and effect insurance with reputable and solvent insurance carriers on all its property in at least such amounts, against at least such risks and with such deductibles or self-insured retentions as is consistent and in accordance with industry practice and (iii) furnish to each Lender, upon written request, full information as to the insurance carried. In addition to the requirements to the immediately preceding sentence, the Borrower will at all time cause insurance of the types described in Schedule 5.9 to be maintained with no less scope of coverage or greater deductibles as are described in Schedule 5.9 unless Borrower can -33- show that such insurance is no longer available to the Borrower at a commercially reasonable cost. Such insurance shall include physical damage insurance on all real and personal property (whether now or hereafter acquired) on an all risk basis and business interruption insurance. 6.4 Corporate Franchises. The Borrower will, and will cause all -------------------- members of the NEG Group, to do or cause to be done, all things necessary to preserve and keep in full force and effect its existence and its material rights, franchises, licenses and patents used in its business. 6.5 Compliance with Statutes, etc. The Borrower will, and will cause ----------------------------- all members of the NEG Group to, comply with all applicable Law, in respect of the conduct of its business and the ownership of its Property, except such noncompliances as could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole. 6.6 Compliance with Environmental Laws. (a) The Borrower will ---------------------------------- comply, and will cause all members of the NEG Group to comply, in all material respects with all Environmental Laws applicable to the operation of its business or to the ownership or use of Real Estate now or hereafter owned or operated by the Borrower and the other Covered Parties, will within a reasonable time period pay or cause to be paid all costs and expenses incurred in connection with such compliance (except to the extent being contested in good faith), and will undertake all reasonable efforts to keep or cause to be kept all such Real Estate free and clear of any Liens imposed pursuant to such Environmental Laws, except such noncompliances as could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect or a Material Adverse Change of LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole. The Borrower will not and will cause the other Covered Parties not to generate, use, treat, store, release or dispose of, or permit the generation, use, treatment, storage, release or disposal of Hazardous Materials on any Real Estate now or hereafter owned or operated or occupied by the Borrower or any of the other Covered Parties, or transport or permit the transportation of Hazardous Materials to or from any such Real Estate except in compliance with all applicable Environmental Laws (except such noncompliances as could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole) and reasonably required in connection with the operation, use and maintenance of any such Real Estate or otherwise in connection with their businesses. (b) At the written request of any Lender upon a reasonable belief by such Lender that the Borrower or any of its Subsidiaries has breached any representation or covenant contained herein relating to environmental matters, which request shall specify in reasonable detail the basis therefor, the Borrower will provide, at the Borrower's sole cost and expense, an environmental audit, reasonable in scope, concerning the subject matter of such representation or covenant and any Real Estate now or hereafter owned, operated or occupied by the Borrower or any of its Subsidiaries, prepared by an environmental consulting firm reasonably acceptable to such Lender, indicating (if relevant to such breach) the presence or absence of Hazardous Materials and the potential cost of any removal or remedial action in connection with any Hazardous Materials on such Real Estate; provided, that such request may be made only if (i) there has -------- occurred and is continuing a Default, (ii) such Lender reasonably believes that the -34- Borrower or any such Real Estate is not in compliance with Environmental Law and such circumstances would reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole, or (iii) circumstances exist that reasonably could be expected to form the basis of a material Environmental Claim against the Borrower or any of its Subsidiaries or any such Real Estate. If the Borrower fails to provide the same within a reasonable period, not to exceed 90 days, after such request was made, a Lender may order the same, and the Borrower shall grant and hereby grants to such Lender and its agents access to such Real Estate and specifically grants such Lender an irrevocable non-exclusive license, subject to the rights of tenants, to undertake such an assessment, all at the Borrower's expense. 6.7 ERISA. As soon as possible and, in any event, within ten (10) ----- days after the Borrower, any Subsidiary of the Borrower or any ERISA Affiliate knows or has reason to know of the occurrence of any of the following, the Borrower will deliver to each Lender a certificate of the Chief Financial Officer of the Borrower setting forth the full details as to such occurrence and the action, if any, that the Borrower, such Subsidiary or such ERISA Affiliate is required or proposes to take, together with any notices required or proposed to be given or filed by such Borrower, such Subsidiary, the Plan administrator or such ERISA Affiliate to or with the PBGC or any other government agency, or a Plan participant and any notices received by such Borrower, such Subsidiary or ERISA Affiliate from the PBGC or any other government agency, or a Plan participant with respect thereto: that a Reportable Event has occurred (except to the extent that the Borrower has previously delivered to each Lender a certificate and notices (if any) concerning such event pursuant to the next clause hereof); that a contributing sponsor (as defined in Section 4001(a)(13) of ERISA) of a Plan subject to Title IV of ERISA is subject to the advance reporting requirement of PBGC Regulation Section 4043.61 (without regard to subparagraph (b)(1) thereof), and an event described in subsection .62, .63, .64, .65, .66, .67 or .68 of PBGC Regulation Section 4043 is reasonably expected to occur with respect to such Plan within the following 30 days; that an accumulated funding deficiency, within the meaning of Section 412 of the Code or Section 302 of ERISA, has been incurred or an application may be or has been made for a waiver or modification of the minimum funding standard (including any required installment payments) or an extension of any amortization period under Section 412 of the Code or Section 303 or 304 of ERISA with respect to a Plan; that any contribution required to be made with respect to a Plan or Foreign Pension Plan has not been timely made; that a Plan has been or may be terminated, reorganized, partitioned or declared insolvent under Title IV of ERISA; that a Plan has an Unfunded Current Liability; that proceedings may be or have been instituted to terminate or appoint a trustee to administer a Plan which is subject to Title IV of ERISA; that a proceeding has been instituted pursuant to Section 515 of ERISA to collect a delinquent contribution to a Plan; that the Borrower, any Subsidiary of the Borrower or any ERISA Affiliate will or may incur any liability (including any indirect, contingent, or secondary liability) to or on account of the termination of or withdrawal from a Plan under Section 4062, 4063, 4064, 4069, 4201, 4204 or 4212 of ERISA or with respect to a Plan under Section 401(a)(29), 4971, 4975 or 4980 of the Code or Section 409, 502(i) or 502(l) of ERISA or with respect to a group health plan (as defined in Section 607(1) of ERISA or Section 4980B(g)(2) of the Code) under Section 4980B of the Code; or that the Borrower or any Subsidiary of the Borrower may incur any material liability pursuant to any employee welfare benefit plan (as defined in Section 3(1) of ERISA) that provides -35- benefits to retired employees or other former employees (other than as required by Section 601 of ERISA) or any Plan or any Foreign Pension Plan. The Borrower will deliver to each Lender copies of any records, documents or other information that must be furnished to the PBGC with respect to any Plan pursuant to Section 4010 of ERISA. Upon the reasonable request of the Required Waiver Lenders, the Borrower will also deliver to each Lender a complete copy of the annual report (on Internal Revenue Service Form 5500-series) of each Plan (including, to the extent required, the related financial and actuarial statements and opinions and other supporting statements, certifications, schedules and information) required to be filed with the Internal Revenue Service. In addition to any certificates or notices delivered to each Lender pursuant to the first sentence hereof, copies of annual reports and any records, documents or other information required to be furnished to the PBGC or any other government agency, and any material notices received by the Borrower, any Subsidiary of the Borrower or any ERISA Affiliate with respect to any Plan or Foreign Pension Plan shall be delivered to each Lender no later than ten (10) days after the date such annual report has been filed with the Internal Revenue Service or such records, documents and/or information has been furnished to the PBGC or any other government agency or such notice has been received by the Borrower, the Subsidiary or the ERISA Affiliate, as applicable. The Borrower and each of its applicable Subsidiaries shall ensure that all Foreign Pension Plans administered by it or into which it makes payments obtains or retains (as applicable) registered status under and as required by applicable law and is administered in a timely manner in all respects in compliance with all applicable laws except where the failure to do any of the foregoing would not be reasonably likely to result in a material adverse effect upon the business, operations, condition (financial or otherwise) or prospects of the Borrower or any Subsidiary of the Borrower. 6.8 End of Fiscal Years; Fiscal Quarters. The Borrower shall cause ------------------------------------ (i) each of its, and each of the other Covered Party's, fiscal years to end on December 31 and (ii) its fiscal quarters to end on March 31, June 30, September 30 and December 31. 6.9 Payment of Taxes. The Borrower (a) will pay and discharge, and ---------------- will cause each of its Subsidiaries to pay and discharge, all material federal and state income and franchise taxes imposed upon it or upon its income or profits, or upon any properties belonging to it, prior to the date on which penalties attach thereto, and all lawful claims for sums related thereto that have become due and payable which, if unpaid, might become a Lien not otherwise permitted hereunder, and (b) will pay and discharge, and will cause each Subsidiary to pay and discharge, all other material taxes, assessments and governmental charges or levies imposed upon it or upon its income or profits, or upon any properties belonging to it, prior to the date on which penalties attach thereto, and all lawful claims for sums that have become due and payable which, if unpaid, might become a Lien not otherwise permitted hereunder, provided that -------- neither the Borrower nor any of its Subsidiaries shall be required to pay any such tax, assessment, charge, levy or claim which is being contested in good faith and by proper proceedings if it has maintained adequate reserves with respect thereto in accordance with GAAP, and provided, further, that this -------- ------- section 6.9 shall not apply with respect to any taxes of PG&E Utility or any Subsidiary of PG&E Utility for which Borrower has no liability under applicable law. 6.10 [OMITTED] ------- -36- 6.11 Performance of Obligations. The Borrower will, and will cause -------------------------- each member of the NEG Group to, perform all of its obligations under the terms of each mortgage, indenture, security agreement, loan agreement or credit agreement and each other material agreement, contract or instrument by which it is bound, except such non-performances as could not, either individually or in the aggregate, reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the NEG Subsidiaries taken as a whole. 6.12 Use of Proceeds. The Borrower will use the proceeds of the --------------- Loans only as provided in Section 4.1(s). 6.13 Regulatory Compliance. Borrower will take all actions and cause --------------------- its Subsidiaries to take all actions reasonably required to comply in all material respects with applicable Utility Regulations and each order issued pursuant thereto; provided that, the foregoing shall not prevent Borrower or a -------- Subsidiary from challenging the validity or effect of any Utility Regulation or order in any proceeding provided the manner of such challenge could not reasonably be expected to cause a Material Adverse Effect. 6.14 Financial Covenants. (a) The long-term unsecured debt ------------------- obligations of NEG, Inc. shall be rated at least BBB- by Standard & Poor's or Baa3 by Moody's. (b) The ratio of the Fair Market Value of NEG, Inc. to the aggregate amount of principal then outstanding under the Loan (the "Required FMV Ratio") ------------------ shall be at least 2:1. The Required FMV Ratio may be determined in accordance with the procedure set forth in the succeeding paragraph at any time at the request and expense of the requesting Lender by delivering a notice to the Borrower no more frequently than once per fiscal quarter of the Borrower. For purposes hereof, the "Fair Market Value" of NEG, Inc. shall mean the price at which a willing buyer would buy and a willing seller would sell the Pledged Interests having full knowledge of the facts, and assuming each party acts on an arm's-length basis with the expectation of concluding the purchase or sale within a reasonable time, which determination shall be made by an Approved Appraiser selected by the Tranche A Lender and the Tranche B Lender (the "Appraiser"). The Borrower will cooperate and deliver such document and provide --------- such information as may be reasonably requested by the Tranche A Lender, the Tranche B Lender or the Appraiser with respect to the determination of the Required FMV Ratio. 6.15 Charter Documents. The Borrower will, and will cause LLC and ----------------- the other Specified Subsidiaries to, comply with their respective Charter Documents in all material respects. 6.16 Further Assurances; etc. The Borrower will, and will cause the ----------------------- other Covered Parties, at the expense of the Borrower, make, execute, endorse, acknowledge, file and/or deliver to each Lender from time to time such confirmatory assignments, conveyances, financing statements, transfer endorsements, powers of attorney, certificates, reports, and other assurances or instruments and take such further steps as are necessary or desirable in order to carry out the intent, purpose, provisions of this Agreement and the other Financing Document, including any assignment or syndication by any Lender of its Loan. Furthermore, the Borrower -37- will deliver to each Lender such opinions of counsel and other related documents as may be reasonably requested by any Lender to assure itself that this Section 6.16 has been complied with. 6.17 Tax Refund. The Borrower shall upon receipt of the tax refund ---------- for the fiscal year 2000 use such refund in the manner set forth in Part G of the Disclosure Letter. 6.18 Cash Reserve. The Borrower shall at all times commencing after ------------ the first anniversary of the Closing Date and until the Loans are repaid in full own cash or Cash Equivalents in its name in an amount no less than 15% of the total principal amount of Loans then outstanding, free and clear of all Liens . SECTION 7. NEGATIVE COVENANTS. ------------------ The Borrower covenants and agrees that on and after the Closing Date and until the Loans and the Notes, together with interest, fees and all other obligations incurred hereunder and thereunder, are paid in full (other than any indemnity, not then due and payable, which by its terms shall survive such termination and payment): 7.1 Liens. The Borrower will not, and will not permit any of the ----- other Covered Parties to, create, incur, assume or suffer to exist any Lien upon or with respect to any Property or assets (real or personal, tangible or intangible) of the Borrower or any of the other Covered Parties, whether now owned or hereafter acquired, or sell any such Property or assets subject to an understanding or agreement, contingent or otherwise, to repurchase such Property or assets (including sales of accounts receivable with recourse to the Borrower or any of the other Covered Parties), or assign any right to receive income or permit the filing of any financing statement under the UCC or any other similar notice of Lien under any similar recording or notice statute; provided that the -------- provisions of this Section 7.1 shall not prevent the creation, incurrence, assumption or existence of the following (Liens described below are herein referred to as "Permitted Liens"): --------------- (i) inchoate Liens for taxes, assessments or governmental charges or levies not yet due and payable or Liens for taxes, assessments or governmental charges or levies being contested in good faith and by appropriate proceedings for which adequate reserves have been established in accordance with generally accepted accounting principles in the United States; (ii) Liens in respect of Property or assets of the Covered Parties imposed by law, which arise or were incurred in the ordinary course of business and do not secure Indebtedness for borrowed money, such as carriers', workmen's, repairmen's, warehousemen's, materialmen's and mechanics' liens, collecting bank's liens, charge back rights of depository banks for uncollected items and other similar Liens arising or incurred in the ordinary course of business, and (x) which do not in the aggregate materially detract from the value of the property or assets of the Borrower or the other Covered Parties and do not materially impair the use thereof in the operation of the business of the Borrower or the other Covered Parties or (y) which are being contested in good faith by appropriate proceedings, which proceedings (or orders entered in connection with such proceedings) -38- have the effect of preventing the forfeiture or sale of the property or assets subject to any such Lien; (iii) Subject to Section 7.4(ii), Liens in existence on the Closing Date which are listed, and the Property subject thereto described, in Schedule 7.1; (iv) Liens created pursuant to this Agreement and the Security Documents; (v) licenses, leases or subleases granted to other Persons in the ordinary course of business not materially interfering with the conduct of the business of the Borrower and the other Covered Parties, taken as a whole; (vi) easements, rights-of-way, restrictions (including zoning restrictions), covenants, encroachments, protrusions and other similar charges or encumbrances, and minor title deficiencies, in each case whether now or hereafter in existence, not securing Indebtedness and not materially interfering with the conduct of the business of the Borrower and the other Covered Parties, taken as a whole; (vii) statutory, contractual and common law landlords' liens under leases or subleases permitted by this Agreement; (viii) Liens (other than any Lien imposed by ERISA) (x) incurred or deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance and other types of social security, (y) to secure the performance of tenders, statutory obligations (other than excise taxes), surety, stay, customs and appeal bonds, statutory bonds, bids, leases, government contracts, trade contracts, performance and return of money bonds and other similar obligations (exclusive of obligations for the payment of borrowed money) or (z) arising by virtue of deposits made in the ordinary course of business to secure liability for premiums to insurance carriers, provided that the aggregate -------- amount of deposits at any time pursuant to sub-clauses (y) and (z) shall not exceed $25,000,000 in the aggregate; (ix) any interest or title of a lessor, sublessor, licensee or licensor under any lease or license agreement permitted by this Agreement; (x) attachment or judgment Liens in an aggregate amount outstanding at any one time not in excess of the amount of $1,000,000; (xi) attachment or judgment Liens paid or fully covered by insurance which are not outstanding for more than sixty (60) days; (xii) Liens arising from precautionary Uniform Commercial Code financing statement filings with respect to operating leases or consignment arrangements entered into by the Borrower or any of the other Covered Parties in the ordinary course of business; and -39- (xiii) other than by LLC, any Lien attendant to transactions described by the Business Plan. 7.2 Consolidation, Merger, Purchase or Sale of Assets, etc. The ------------------------------------------------------- Borrower will not, and will not permit any member of the NEG Group to, wind up, liquidate or dissolve its affairs or enter into any transaction of merger or consolidation, or convey, sell, lease or otherwise dispose of (or agree to do any of the foregoing at any future time) all or any part of its Property or assets, or enter into any sale-leaseback transactions, or purchase or otherwise acquire (in one or a series of related transactions) any part of the Property or assets (other than purchases or other acquisitions of inventory in the ordinary course of business) of any Person (or agree to do any of the foregoing at any future time), except to the extent attendant to transactions described by the Business Plan and except that: (i) any NEG Subsidiary may in the ordinary course of business, sell, lease or otherwise dispose of any assets which, in the reasonable judgment of such Person, are obsolete, worn out or otherwise no longer useful in the conduct of such Person's business; (ii) each of the Borrower and any member of the NEG Group may lease (as lessee) real or personal property in the ordinary course of business (so long as any such lease does not create a Capital Lease Obligation); (iii) any NEG Subsidiary may make sales or transfers of inventory, energy and related products in the ordinary course of business and consistent with past practices; (iv) any NEG Subsidiary may sell or discount, in each case without recourse and in the ordinary course of business, overdue accounts receivable arising in the ordinary course of business, but only in connection with the compromise or collection thereof consistent with customary industry practice (and not as part of any bulk sale); (v) each of the Borrower and any member of the NEG Group may license or sublicense software, trademarks and other intellectual property in the ordinary course of business which do not materially interfere with the business of the Borrower, LLC, NEG, Inc. and the NEG Subsidiaries, taken as a whole; (vi) each of the Borrower, LLC, NEG, Inc. or any NEG Subsidiary may transfer assets or lease to or acquire or lease assets from the Borrower, LLC, NEG, Inc. or any other NEG Subsidiary and LLC, NEG, Inc. or any NEG Subsidiary may be merged into LLC, NEG, Inc. or any other NEG Subsidiary; (vii) any NEG Subsidiary may sell or otherwise dispose of additional assets, provided that (x) each such sale or disposition shall be for an -------- amount at least equal to the fair market value thereof (as determined in good faith by the senior management of such Person), (y) each such sale (other than any like-kind exchange) results in consideration at least 75% of which shall be in the form of cash (for such purpose, taking into account the amount of cash, the principal amount of any promissory notes and the fair market value, as determined in good faith by the senior management of the Borrower, of any other -40- consideration), and (z) the Net Sale Proceeds therefrom shall be applied pursuant to Section 3.2; (viii) subject to Section 3.2(f), each of the Borrower and any member of the NEG Group may make transfers of any proceeds of insurance resulting from any casualty or condemnation of property or assets; and (ix) the Borrower may sell or otherwise dispose of any assets other than assets owned by any member of the NEG Group. 7.3 Dividends. The Borrower will not, and will not permit any of the --------- other Covered Parties to, authorize, declare or pay any Dividends (other than the Dividend being Refinanced hereunder), except that any Subsidiary of the Borrower may pay cash Dividends to the Borrower or to LLC, NEG, Inc. or any NEG Subsidiary and NEG, Inc. may distribute a note to LLC or the Borrower, and LLC may distribute any such note to the Borrower, solely in connection with the IPO or LLC may authorize, declare and pay Dividends to the Borrower in connection with a Spin-Off of NEG, Inc. 7.4 Indebtedness. The Borrower will not, and will not permit any ------------ member of the NEG Group to, contract, create, incur, assume or suffer to exist any Indebtedness, except: (i) Indebtedness incurred pursuant to this Agreement and the other Financing Documents; (ii) Existing Indebtedness outstanding on the Closing Date and listed on Schedule 5.23 or with respect to the Borrower, Part B (I) and (II) of the Disclosure Letter and with respect to the Covered Parties (other than the Borrower), Part B (III) of the Disclosure Letter (as reduced by any repayments of principal thereof), without giving effect to any subsequent extension, renewal or refinancing thereof; provided that no -------- later than four (4) months from the Closing Date, the obligations of the Borrower under the Equity Infusion Agreements shall be fully released and terminated and no Person shall have any claim against the Borrower and the Borrower shall have no further obligations with respect thereto, and the Contingent Obligations of the Borrower to the Trading Counterparties under the Trading Contracts shall not exceed $50,000,000 in the aggregate and the amount of such Indebtedness shall not be extended, renewed or refinanced; (iii) Indebtedness resulting from the endorsement of negotiable instruments in the ordinary course of business; (iv) Indebtedness among Borrower or any member of the NEG Group (other than LLC) and any other NEG Subsidiary from intercompany transfers of assets made in the ordinary course of business or to the extent permitted under Sections 7.2 and 7.5; (v) Indebtedness of a Covered Party (other than LLC) secured by Liens permitted under Sections 7.1(i), (ii), (vii) and (viii); (vi) in the case of the Borrower, Specified Rated Indebtedness; and -41- (vii) in the case of any member of the NEG Group (other than LLC), to the extent described by the Business Plan. 7.5 Advances, Investments and Loans. The Borrower will not, and will ------------------------------- not permit any member of the NEG Group to, directly or indirectly, lend money or credit or make advances to any other Person, or purchase or acquire any stock, obligations or securities of, or any other interest in, or make any capital contribution to, any other Person, or purchase or own a futures contract or otherwise become liable for the purchase or sale of currency or other commodities at a future date in the nature of a futures contract, or hold any cash or Cash Equivalents (each of the foregoing an "Investment" and, ---------- collectively, "Investments"), except that the following shall be permitted: ----------- (i) the Borrower and the other Covered Parties may acquire and hold accounts receivables owing to any of them, if created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms of the Borrower or such other Covered Parties; (ii) the Borrower and the other Covered Parties may acquire and hold cash and Cash Equivalents; (iii) the Borrower and the other Covered Parties may acquire and own investments (including debt obligations) received in connection with the bankruptcy or reorganization of suppliers and customers and in good faith settlement of delinquent obligations of, and other disputes with, customers and suppliers arising in the ordinary course of business; (iv) any Investment by a Covered Party (other than LLC) to the extent described by the Business Plan; (v) any Investment by the Borrower in PGE Utility if the Borrower reasonably determines that such Investment is required by applicable Law; (vi) any Investment by the Borrower in PGE Utility if the Borrower reasonably determines that such Investment is required by the Holding Company Conditions; (vii) loans and advances by the Covered Parties (other than LLC) to their respective directors, officers and employees in a principal amount not exceeding the amount of $100,000, on an individual basis, and $1,000,000, on an aggregate basis, at any one time outstanding; (viii) any NEG Subsidiary and NEG, Inc. may distribute a note to LLC or the Borrower, and LLC may distribute any such note to the Borrower, solely in connection with the IPO; (ix) any Investment made by any of LLC, NEG, Inc. or any NEG Subsidiary pursuant to Section 3.2(b)(iii), 3.2(c)(iii), 3.2(e)(iii) or 3.2(f)(ii); -42- (x) any Investment made by the Borrower or any member of the NEG Group in a wholly-owned Subsidiary; and (xi) in addition to the Investments permitted by clauses (i)-(x) above, the Borrower may make other Investments for operations of the Borrower or its Subsidiaries not otherwise related to PGE Utility or any of its Subsidiaries in an amount not to exceed $15,000,000 in the aggregate for the period commencing March 1, 2001 and ending December 31, 2001, and $10,000,000 in the aggregate for any subsequent fiscal year. Notwithstanding anything provided herein or in the Business Plan to the contrary, no investment may be made by the Borrower or any member of the NEG Group in the nuclear generation business. 7.6 Transactions with Affiliates. Except as disclosed on Schedule ---------------------------- 5.17, the Borrower will not, and will not permit any member of the NEG Group and any other NEG Subsidiaries to, enter into any transaction or series of related transactions with any Affiliate of the Borrower or any of its Subsidiaries, other than (a) in the ordinary course of business and on terms and conditions substantially as favorable to the Borrower or such Subsidiary as would reasonably be obtained by the Borrower or such Subsidiary at that time in a comparable arm's-length transaction with a Person other than an Affiliate, except for provision of cash, credit or other financial assistance or support by the Borrower or any member of the NEG Group to PGE Utility or any of its Subsidiaries (unless such assistance or support is made to the extent provided in the Business Plan), (b) as reasonably determined by the Borrower that such transaction is required by applicable Law or the Holding Company Conditions, (c) among the Borrower and the other Covered Parties and any other NEG Subsidiaries and among the NEG Group, (d) any other transactions with Affiliates provided at cost where the difference between the arms-length price and cost is less than $5,000,000 in the aggregate, (e) the payment of reasonable and customary fees and reimbursements of expenses payable to directors of any member of the NEG Group or (f) the employment arrangements with respect to the procurement of services of directors, officers and employees of any member of the NEG Group in the ordinary course of business and payment of reasonable and customary fees in connection therewith. 7.7 Capital Expenditures. The Borrower will not, and will not permit -------------------- any member of the NEG Group to, make any Capital Expenditures, except to the extent (a) the Borrower reasonably determines that such Capital Expenditures by the Borrower in PGE Utility is required by applicable Law, (b) the Borrower reasonably determines that such Capital Expenditures by the Borrower in PGE Utility is required by the Holding Company Conditions, (c) that such Capital Expenditures are made by a Covered Party (other than LLC) attendant to transactions described by the Business Plan, (d) related to Investment made by any of LLC, NEG, Inc. or any NEG Subsidiary pursuant to Section 3.2(b)(iii), 3.2(c)(iii), 3.2(e) (iii) or 3.2(f)(ii) or (e) provided in the cash-flow forecast of the Borrower attached to the solvency certificate of the Borrower delivered on the Closing Date. 7.8 Limitations on Liens on Collateral; Modifications of Certain ------------------------------------------------------------ Indebtedness; Modifications of Certificate of Incorporation, By-Laws and Certain - -------------------------------------------------------------------------------- Other Agreements, etc. (a) - ---------------------- -43- The Borrower will not, and will not permit any of the Covered Parties and the Specified Subsidiaries to: (i) create or suffer to exist any Lien on any of the Collateral; (ii) amend or modify, or permit the amendment or modification of, any provision of any Existing Indebtedness Agreements which could reasonably be expected to have a Material Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the NEG Subsidiaries, taken as a whole; (iii) except as provided in the Business Plan with respect to the IPO or the Spin-Off of NEG, Inc., (w) except to the extent it would not cause an adverse effect on any Lender, amend, modify or change any material provision of its certificate or articles of incorporation (including, without limitation, by the filing or modification of any certificate or articles of designation), certificate of formation, limited liability company agreement or by-laws (or the equivalent organizational documents), as applicable, or (x) amend, modify or change any agreement entered into by it with respect to its capital stock or other equity interests (including any shareholders' agreement), or (y) enter into any new agreement with respect to its capital stock or other equity interests or (z) amend the Business Plan; (iv) terminate, cancel or suspend any license, contract or material franchise agreements which would result in a Material Adverse Effect or a Material Adverse Change to LLC, NEG, Inc. and the NEG Subsidiaries, taken as a whole; or (v) create any Subsidiary of the Borrower which will be a direct or indirect parent of LLC or create any Subsidiary of LLC which will be a direct or indirect parent of NEG, Inc. or create any Subsidiary of NEG, Inc. which would own, directly or indirectly, all or substantially all of the assets or shares of the NEG Subsidiaries. 7.9 Limitation on Issuance of Capital Stock. (a) Except as --------------------------------------- otherwise permitted by Sections 7.3 and 7.5 or to the extent attendant to transactions described by the Business Plan, the Borrower will not permit any of the Covered Parties (other than the Borrower) to issue (i) any participating preferred stock or other participating preferred equity interests or preferred stock or other preferred equity interests convertible to common stock or common equity interest or (ii) any redeemable common stock or other redeemable common equity interest other than common stock or other redeemable common equity interest that is redeemable at the sole option of the Borrower or such Covered Party, as the case may be. (b) Except as otherwise permitted by Sections 7.3 and 7.5, the Borrower will not permit any of the Covered Parties (other than the Borrower) to issue any capital stock or other equity interests (including by way of sales of treasury stock) or any options (other than the Option) or warrants to purchase, or securities convertible into, capital stock or other equity interests, except (other than LLC) (i) for transfers and replacements of then outstanding shares of capital stock or other equity interests, (ii) for stock splits, stock dividends and issuances which do not decrease the percentage ownership of any of the Covered Parties in any class of the capital stock or other equity interests of such other Covered Parties, (iii) pursuant to employee stock -44- option plans, (iv) to the extent the Borrower reasonably determines that such issuance is required by applicable Law, or (v) to the extent attendant to transactions described by the Business Plan. 7.10 Business. The Borrower will not, and will not permit any of the -------- other Covered Parties to, engage in any business other than the current businesses engaged in by the Borrower and the other Covered Parties as of the date hereof or to the extent within the scope of business described by the Business Plan. 7.11 Regulatory Compliance. The Borrower will not take any actions or --------------------- allow any of its Subsidiaries to take any action which would materially violate any applicable Utility Regulations or order issued pursuant thereto; provided -------- that, the foregoing shall not prevent the Borrower or a Subsidiary from - ---- challenging the validity or effect of any Utility Regulation or order in any proceeding provided the manner of such challenge could not reasonably be expected to cause a Material Adverse Effect. The Borrower will not take any actions or allow any of its Subsidiaries to take any actions that would prevent Borrower from reaffirming the representations of Sections 5.16(b), (c), (d), (e) and (g) as of any date prior to repayment of the Loans in full. SECTION 8. EVENTS OF DEFAULT AND REMEDIES. ------------------------------ 8.1 Events of Default. The occurrence of any of the following events ----------------- or circumstances shall constitute an "Event of Default" hereunder: ---------------- (a) The Borrower shall (i) default in the payment when due of any principal of any Loan or any Note or (ii) default, and such default shall continue unremedied for three or more Business Days, in the payment when due of any interest on any Loan or Note or any fees or any other amounts owing hereunder or under any other Financing Document; or (b) Any representation, warranty or statement made or deemed made by the Borrower or any other Covered Party herein or in any other Financing Document or in the Disclosure Letter or in any certificate delivered to the Administrative Agent or any Lender pursuant hereto or thereto shall prove to be untrue in any material respect on the date as of which made or deemed made; or (c) The Borrower or any of the other Covered Parties shall (i) default in the due performance or observance by it of any term, covenant or agreement contained in Section 6 (other than Sections 6.1 and 6.2) or Section 7; provided, however that a Default under Section 6.14(b) shall not constitute an Event of Default hereunder unless such Default shall continue unremedied for sixty (60) days and the Appraiser, at the Required Acceleration Lenders' request, again reaffirms that the Required FMV Ratio is below 2:1 after such sixty (60) day period or (ii) except as set forth in clause (iii) and Section 8.1(g), default in the due performance or observance by it of any other term, covenant or agreement contained in this Agreement or in any other Financing Document (other than those set forth in clauses (a) and (b) of this Section 8.1) and such default shall continue unremedied for a period of 30 days after written notice thereof to the defaulting party by -45- any Lender or (iii) default in the due performance or observance by it of any term, covenant or agreement contained in the Option Agreement; or (d) (i) Any of the Covered Parties shall default in any payment of any Indebtedness when due, or (ii) any of the Covered Parties shall default in the observance or performance of any agreement or condition relating to any Indebtedness or any other event or condition shall occur or exist, the effect of which event or condition is to cause, or permit the holder or holders of such Indebtedness to cause any such Indebtedness to become due prior to its stated maturity, or (iii) any Indebtedness of any of the Covered Parties shall be declared to be (or shall become) due and payable, or required to be prepaid other than by regularly scheduled prepayment, prior to the stated maturity thereof, provided it shall not be a Default or -------- an Event of Default under this clause (d) unless the aggregate principal amount of all Indebtedness as described in preceding subclauses (i), (ii) and (iii) is at least $100,000,000; or (e) The Borrower or any of the other Covered Parties shall commence a voluntary case concerning itself under Title 11 of the United States Code entitled "Bankruptcy," as now or hereafter in effect, or any successor thereto (the "Bankruptcy Code"); or an involuntary case is commenced --------------- against the Borrower or any of the other Covered Parties, and the petition is not controverted within 10 days, or is not dismissed within 45 days, after commencement of the case; or a custodian (as defined in the Bankruptcy Code) is appointed for, or takes charge of, all or substantially all of the property of the Borrower or any of the other Covered Parties; or the Borrower or any of the other Covered Parties commences any other proceeding under any reorganization, arrangement, adjustment of debt, relief of debtors, dissolution, insolvency or liquidation or similar law of any jurisdiction whether now or hereafter in effect relating to the Borrower or any of the other Covered Parties; or there is commenced against the Borrower or any of the other Covered Parties any such proceeding which remains undismissed for a period of 60 days; or the Borrower or any of the other Covered Parties is adjudicated insolvent or bankrupt; or any order of relief or other order approving any such case or proceeding is entered; or the Borrower or any of the other Covered Parties suffers any appointment of any custodian or the like for it or any substantial part of its property to continue undischarged or unstayed for a period of 45 days; or the Borrower or any of the other Covered Parties makes a general assignment for the benefit of creditors; or any corporate, limited liability company or similar action is taken by the Borrower or any of the other Covered Parties for the purpose of effecting any of the foregoing; or (f) (i) Any Plan shall fail to satisfy the minimum funding standard required for any plan year or part thereof under Section 412 of the Code or Section 302 of ERISA or a waiver of such standard or extension of any amortization period is sought or granted under Section 412 of the Code or Section 303 or 304 of ERISA, a Reportable Event shall have occurred, a contributing sponsor (as defined in Section 4001(a)(13) of ERISA) of a Plan subject to Title IV of ERISA shall be subject to the advance reporting requirement of PBGC Regulation Section 4043.61 (without regard to subparagraph (b)(1) thereof) and an event described in subsection .62, .63, .64, .65, .66, .67 or .68 of PBGC Regulation Section 4043 shall be reasonably expected to occur with respect to such Plan within the -46- following 30 days, any Plan which is subject to Title IV of ERISA shall have had or is likely to have a trustee appointed to administer such Plan, any Plan which is subject to Title IV of ERISA is, shall have been or is likely to be terminated or to be the subject of termination proceedings under ERISA, any Plan shall have an Unfunded Current Liability, a contribution required to be made with respect to a Plan or a Foreign Pension Plan has not been timely made, the Borrower or any Subsidiary of the Borrower or any ERISA Affiliate has incurred or is likely to incur any liability to or on account of a Plan under Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201, 4204 or 4212 of ERISA or Section 401(a)(29), 4971 or 4975 of the Code or on account of a group health plan (as defined in Section 607(1) of ERISA or Section 4980B(g)(2) of the Code) under Section 4980B of the Code, or the Borrower or any Subsidiary of the Borrower has incurred or is likely to incur liabilities pursuant to one or more employee welfare benefit plans (as defined in Section 3(1) of ERISA) that provide benefits to retired employees or other former employees (other than as required by Section 601 of ERISA) or Plans or Foreign Pension Plans, a "default" within the meaning of Section 4219(c)(5) of ERISA shall occur with respect to any Plan, any applicable law, rule or regulation is adopted, changed or interpreted, or the interpretation or administration thereof is changed, in each case after the date hereof, by any governmental authority or agency or by any court (a "Change in Law"), or, as a result of a Change in Law, an event occurs following a Change in Law, with respect to ------------- or otherwise affecting any Plan; (ii) there shall result from any such event or events the imposition of a lien, the granting of a security interest, or a liability or a material risk of incurring a liability; and (iii) such lien, security interest or liability, either individually and/or in the aggregate, has had, or could reasonably be expected to have, a Material Adverse Effect; or (g) Any of the Security Documents or the Option Agreement shall cease to be in full force and effect, or shall cease to give the Collateral Agent and each Lender or the Holders the Liens, rights, powers and privileges purported to be created thereby (including, without limitation, a perfected security interest in, and Lien on, all of the Collateral, in favor of the Collateral Agent and each Lender, superior to and prior to the rights of all third Persons and subject to no other Liens), or any Covered Party shall default in the due performance or observance of any term, covenant or agreement on its part to be performed or observed pursuant to any Security Document and such default shall continue beyond the period of grace, if any, specifically applicable thereto pursuant to the terms of such Security Document; or (h) One or more judgments or decrees shall be entered against the Borrower or any other Covered Party involving in the aggregate for the Borrower and the other Covered Parties a liability (not paid or fully covered by a reputable and solvent insurance company) of $100,000,000 or more and such judgments and decrees either shall be final and non- appealable or shall not be vacated, discharged or stayed or bonded pending appeal for any period of 60 consecutive days; or (i) Any final and non-appealable order shall be issued by FERC, CPUC or other Governmental Authority that could reasonably be expected to have a Material -47- Adverse Effect or result in a Material Adverse Change to the Borrower, LLC, or NEG, Inc. and the Significant Subsidiaries, taken as a whole; or (j) The Required FMV Ratio is below 1.25:1 on any date, unless, within five (5) Business days after such date, the Required Acceleration Lenders shall have determined and shall have advised the Administrative Agent that, there shall not be an acceleration of the Loans and other amounts owing under the Financing Documents. 8.2 Acceleration. (a) If an Event of Default specified in Section ------------ 8.1(e) with respect to the Borrower or 8.1(j) shall occur, automatically the Loans (with accrued interest thereon) and all other amounts owing under the Financing Documents shall immediately become due and payable. (b) If any Event of Default (other than an Event of Default referred to in Section 8.1(e) or 8.1(j)) shall occur, then the Administrative Agent (acting upon the instructions of the Required Acceleration Lenders) may by notice to the Borrower either declare the Loans, all accrued and unpaid interest thereon and all other amounts owing to the Lenders under the Financing Documents to be due and payable, whereupon the same shall become immediately due and payable. (c) Except as expressly provided above in this Section 8.2, presentment, demand, protest and all other notices and other formalities of any kind are hereby expressly waived by the Borrower. 8.3 Other Remedies. Upon the occurrence and during the continuation -------------- of an Event of Default, the Administrative Agent (acting upon the instructions of the Required Acceleration Lenders) may exercise any or all rights and remedies at law or in equity (in any combination or order that the Administrative Agent may elect), including without limitation or prejudice to any Lender's other rights and remedies, any and all rights and remedies available under any of the Financing Documents; provided that any Lender may -------- exercise any or all rights and remedies at law or in equity as provided hereunder upon the occurrence and during the continuation of an Event of Default described in Section 8.1(a) or 8.1(e) above. SECTION 9. MISCELLANEOUS. ------------- 9.1 Costs and Expenses. The Borrower shall, whether or not the ------------------ transactions contemplated hereby are consummated and whether or not any of the following are incurred before or after the Closing Date, pay, within five Business Days after demand, all reasonable costs and expenses (including reasonable fees and expenses of counsel and consultants) of the Administrative Agent, the Lead Arranger, the Co-Arranger, the Book Manager, each Lender, the Collateral Agent and each Holder in connection with the preparation, issuance, delivery, filing, recording and administration of this Agreement, the other Financing Documents, and any other documents which may be delivered in connection herewith or therewith, including, without limitation, (a) any and all amounts which the Administrative Agent, each Lender, the Collateral Agent and each Holder has paid relative to curing any Event of Default resulting from the acts or omissions of the Borrower under this Agreement or any other Financing Document, (b) the -48- exercise, enforcement or attempted exercise, enforcement of, or the investigation or preservation of any rights or remedies under, this Agreement or any other Financing Document, or (c) any amendment, waiver or consent with respect to any provision contained in this Agreement or any other Financing Document. In addition, the Borrower shall pay any and all stamp and other taxes and fees payable or determined to be payable in connection with the execution, delivery, filing and recording of this Agreement or any other Financing Document, or any other document which may be delivered in connection with this Agreement, and agrees to save the Administrative Agent, the Lead Arranger, the Co-Arranger, the Book Manager, each Lender, the Collateral Agent and each Holder harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such taxes and fees. 9.2 Indemnity. Whether or not the transactions contemplated hereby --------- are consummated: (a) The Borrower shall pay, indemnify, and hold each of the Administrative Agent, the Lead Arranger, the Co-Arranger, the Book Manager, each Lender, the Collateral Agent and each Holder and each of their respective officers, directors, employees, counsel, agents and attorneys-in-fact and Affiliates (each, an "Indemnified Person") harmless from and against any and all ------------------ liabilities, obligations, losses, damages, penalties, claims, actions, judgments, suits, costs, charges, expenses or disbursements (including reasonable legal fees and expenses and reasonable fees and expenses of consultants) of any kind or nature whatsoever which may at any time (including at any time following repayment of the Loan or the termination, resignation or replacement of any Administrative Agent, Lead Arranger, Co-Arranger, Book Manager, Lender, Collateral Agent or Holder) be imposed on, incurred by or asserted against any such Person in any way relating to or arising out of this Agreement or any other Financing Document, including the Security Documents and any other document or instrument contemplated by or referred to herein or therein, or the transactions contemplated hereby and thereby, or any action taken or omitted by any such Person under or in connection with any of the foregoing, including with respect to the exercise by the Administrative Agent, the Lead Arranger, the Co-Arranger, the Book Manager, any Lender, the Collateral Agent and any Holder of any of its respective rights or remedies under any of the Financing Documents, and any investigation, litigation or proceeding (including any bankruptcy, insolvency, reorganization or other similar proceeding or appellate proceeding) related to this Agreement or any other Financing Document or the Loan, or the use of the proceeds thereof, whether or not any Indemnified Person is a party thereto (all the foregoing, collectively, the "Indemnified Liabilities"); provided, that the Borrower shall have no ----------------------- -------- obligation hereunder to any Indemnified Person with respect to Indemnified Liabilities arising from the gross negligence or willful misconduct of such Indemnified Person. (b) Environmental Indemnity. ----------------------- (i) Without in any way limiting the generality of the other provisions contained in this Section 9.2, the Borrower agrees to defend, protect, indemnify, save and hold harmless each Indemnified Person, whether as beneficiary of any of the Security Documents, as a mortgagee in possession, or as successor-in-interest to the Borrower by foreclosure deed or deed in lieu of foreclosure, or otherwise, from and against any and all liabilities, obligations, losses, damages (including foreseeable and unforeseeable conse- -49- quential damages and punitive claims), penalties, fees, claims, actions, judgments, suits, costs, disbursements (including, without limitation, reasonable legal fees and expenses and consultants' fees and disbursements) and expenses (collectively, "Losses") of any kind or nature whatsoever that ------ may at any time be incurred by, imposed on, asserted or awarded against any such Indemnified Person directly or indirectly based on, or arising out of or resulting from, (A) the actual or alleged presence of Hazardous Materials on, in, under or affecting all or any portion of any Property of the Borrower or any member of the NEG Group whether or not the same originates or emanates from any such Property or any property adjoining or adjacent to any such Property or from properties at which any Hazardous Materials generated, stored or handled by the Borrower were Released or disposed of, (B) any Environmental Claim relating to any such Property or (C) the exercise of any Secured Party's rights under any of the provisions of the Security Documents (the "Indemnified Matters"), whether any of the ------------------- Indemnified Matters arise before or after foreclosure of any of the security interests or other taking of title to all or any portion of the Collateral by the Collateral Agent or any Lender, including, without limitation, (x) the costs of removal of any and all Hazardous Materials from all or any portion of any such Property or any property adjoining or adjacent to any such Property, (y) additional costs required to take reasonable precautions to protect against the Release of Hazardous Materials on, in, under or affecting any such Property into the air, any body of water, any other public domain or any surrounding areas, and (z) costs incurred to comply, in connection with all or any portion of any such Property or any surrounding areas, with all applicable Environmental Laws with respect to Hazardous Materials, except to the extent that any such Indemnified Matter arises from the gross negligence or willful misconduct of such Indemnified Person. (ii) In no event shall any site visit, observation, or testing by any Indemnified Person (or any representative of any such Person) be deemed to be a representation or warranty that Hazardous Materials are or are not present in, on, or under, any Property of the Borrower or any member of the NEG Group, or that there has been or shall be compliance with any Environmental Law. Neither the Borrower nor any other Person is entitled to rely on any site visit, observation, or testing by any Indemnified Person. No Indemnified Person owes any duty of care to protect the Borrower or any other Person against, or to inform the Borrower or any other Person of, any Hazardous Materials or any other adverse condition affecting any such Property. No Indemnified Person shall be obligated to disclose to the Borrower or any other Person any report or findings made as a result of, or in connection with, any site visit, observation, or testing by any Indemnified Person. (c) Survival; Defense. The obligations in this Section 9.2 shall ----------------- survive payment of the Loans and all other obligations hereunder. At the election of any Indemnified Person, the Borrower's indemnification obligations under this Section 9.2 shall include the obligation to defend such Indemnified Person using legal counsel satisfactory to such Indemnified Person, at the sole cost and expense of the Borrower. All amounts owing under this Section 9.2 shall be paid within 30 days after demand. -50- (d) Contribution. To the extent that any undertaking in the preceding ------------ paragraphs of this Section 9.2 may be unenforceable because it is violative of any law or public policy, the Borrower will contribute the maximum portion that it is permitted to pay and satisfy under applicable Law to the payment and satisfaction of such undertaking. (e) Settlement. So long as the Borrower is in compliance with its ---------- obligations under this Section 9.2, the Borrower shall not be liable to any Indemnified Person under this Section 9.2 for any settlement made by such Indemnified Person without the Borrower's consent. 9.3 Notices. (a) All notices, requests and other communications ------- provided for hereunder shall be in writing (including, unless the context expressly otherwise provides, by facsimile transmission, provided that any -------- matter transmitted by the Borrower by facsimile (i) shall be immediately confirmed by a telephone call to the recipient at the number specified on Schedule 9.3, and (ii) shall be followed promptly by a hard copy original thereof by express courier) and faxed or delivered, to the address or facsimile number specified for notices on Schedule 9.3 or to such other address as shall be designated by such party in a written notice to the other parties hereto. (b) All such notices, requests and communications (i) sent by express courier will be effective upon delivery to or refusal to accept delivery by the addressee, and (ii) transmitted by facsimile will be effective when sent and facsimile confirmation received; except that all notices and other communications to the Administrative Agent or any Lender shall not be effective until actually received. (c) The Borrower acknowledges and agrees that any agreement of the Administrative Agent or any Lender to receive certain notices by telephone and facsimile is solely for the convenience and at the request of the Borrower. The Administrative Agent and each Lender shall be entitled to rely on the authority of any Person purporting to be a Person authorized by the Borrower to give such notice and the Administrative Agent and each Lender shall not have any liability to the Borrower or other Person on account of any action taken or not taken by any of the Administrative Agent or such Lender in reliance upon such telephonic or facsimile notice. 9.4 Benefit of Agreement. This Agreement shall be binding upon and -------------------- inure to the benefit of and be enforceable by the respective successors and permitted assigns of the parties hereto. The Borrower may not assign or otherwise transfer any of its rights under this Agreement or any of the other Financing Documents. 9.5 No Waiver; Remedies Cumulative. No failure or delay on the part ------------------------------ of the Administrative Agent or any Lender or the holder of any Note in exercising any right, power or privilege hereunder or under any other Financing Document and no course of dealing between the Borrower and the Administrative Agent or any Lender or the holder of any Note shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege hereunder or under any other Financing Document preclude any other or further exercise thereof or the exercise of any other right, power or privilege hereunder or thereunder. No notice to or demand on the Borrower in any case shall entitle the Borrower to any other or further notice or demand in -51- similar or other circumstances or constitute a waiver of the rights of the Administrative Agent or any Lender or the holder of any Note to take any other or further action in any circumstances without notice or demand. All remedies, either under this Agreement or any other Financing Document or pursuant to any applicable Law or otherwise afforded to the Administrative Agent or any Lender shall be cumulative and not alternative. 9.6 No Third Party Beneficiaries. The agreement of any Lender to ---------------------------- make extensions of credit to the Borrower on the terms and conditions set forth in this Agreement and the other Financing Documents is solely for the benefit of the Borrower, and no other Person shall have any rights hereunder against such Lender with respect to the Loans, the proceeds thereof or otherwise. 9.7 Reinstatement. To the extent that the Administrative Agent or ------------- any Lender receives any payment by or on behalf of the Borrower, which payment or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required to be repaid to the Borrower or to its estate, trustee, receiver, custodian or any other party under any Bankruptcy Law or otherwise, then to the extent of the amount so required to be repaid, the obligation or part thereof which has been paid, reduced or satisfied by the amount so repaid shall be reinstated by the amount so repaid and shall be included within the Obligations as of the date such initial payment, reduction or satisfaction occurred. 9.8 No Immunity. To the extent that the Borrower may be entitled, in ----------- any jurisdiction in which judicial proceedings may at any time be commenced with respect to this Agreement or any other Financing Document, to claim for itself or its revenues, assets or Properties any immunity from suit, the jurisdiction of any court, attachment prior to judgment, attachment in aid of execution of judgment, set-off, execution of a judgment or any other legal process, and to the extent that in any such jurisdiction there may be attributed to such Person such an immunity (whether or not claimed), the Borrower hereby irrevocably agrees not to claim and hereby irrevocably waives such immunity to the fullest extent permitted by the Law of the applicable jurisdiction. 9.9 Counterparts. This Agreement may be executed in any number of ------------ counterparts and by the different parties hereto on separate counterparts, each of which when so executed and delivered by facsimile or otherwise shall be an original, but all of which shall together constitute one and the same instrument. 9.10 Amendment or Waiver. (a) No provision of this Agreement or any ------------------- other Financing Document may be amended, supplemented, modified or waived, except by a written instrument signed by the Required Waiver Lenders and the Borrower and each Covered Party that is a party thereto, and, to the extent that its rights or obligations may be affected thereby, the Administrative Agent. Notwithstanding the foregoing provisions, no such waiver and no such amendment, supplement or modification shall (i) increase or extend the Commitment of any Lender (it being understood that waivers or modifications after the Closing Date of covenants, Defaults or Events of Default shall not constitute a change in the terms of any Commitment of any Lender), without the prior written consent of such Lender, (ii) postpone or delay any date fixed by this Agreement or any other Financing Document for any payment of principal, interest, fees or -52- other amounts due to any Lender hereunder or under any other Financing Document (it being understood that waivers or modifications after the Closing Date of covenants, Defaults or Events of Default shall not constitute a postponement or delay in any date fixed by this Agreement or any other Financing Document for any payment of principal, interest, fees or other amounts due to any Lender hereunder or under any other Financing Document), without the prior written consent of such Lender, (iii) reduce the principal of, or the rate of interest specified in any Financing Document on, any Loan of any Lender, without the prior written consent of such Lender, (iv) release all or substantially all of the Collateral except as shall be otherwise provided in any Security Document or other Financing Document or consent to the assignment or transfer by the Borrower of any of its respective obligations under this Agreement or any other Financing Document, without the prior written consent of each Lender, (v) amend, modify or waive any provision of this Section 9.10 or Section 9.1 or 9.2, without the prior written consent of each Lender, or (vi) reduce the percentage specified in or otherwise amend the definition of Required Waiver Lenders or Required Acceleration Lenders, without the prior written consent of each Lender. (b) Any waiver and any amendment, supplement or modification made or entered into in accordance with Section 9.10(a) shall be binding upon the Borrower, the Administrative Agent, the Lenders and their successors and assigns. 9.11 Assignments, Participations, etc. (a) Each Lender may, without --------------------------------- the consent of the Borrower, but with prior notice to the Administrative Agent, sell or assign any part of the Loan of such Lender and the other rights and obligations of such Lender to any Person or any assignee thereof (an "Assignee") unless the sale or assignment of the Loan and such other rights and obligations of such Lender would reasonably put the business of the Borrower at a competitive disadvantage, then such sale or assignment shall require the consent of the Borrower. The assigning Lender and the Assignee shall enter into an assignment agreement, in form and substance satisfactory to the Administrative Agent (an "Assignment and Acceptance"), with respect to the sale or assignment ------------------------- of the Loan to be assigned and, subject to paragraphs (e) and (f) of this Section 9.11, upon execution and delivery of such Assignment and Acceptance, (i) the Assignee thereunder shall be a party hereto and, to the extent that rights and obligations hereunder have been assigned to it pursuant to such Assignment and Acceptance, shall have the rights and obligations of a Lender hereunder and under the other Financing Documents, and this Agreement shall be deemed to be amended to the extent, but only to the extent, necessary to effect the addition of the Assignee, and any reference to the assigning Lender hereunder or under the other Financing Documents shall thereafter refer to such Lender and to the Assignee to the extent of their respective interests, and (ii) the assigning Lender shall, to the extent that rights and obligations hereunder and under the other Financing Documents have been assigned by it pursuant to such assignment agreement, relinquish its rights and be released from its obligations under the Financing Documents. (b) Each Lender may sell participations to one or more banks or other entities (other than the Borrower or any of its Affiliates) in or to all or a portion of its rights and obligations under this Agreement and such Lender's Note; provided, however, that (i) such Lender's obligations under this -------- ------- Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) such Lender -53- shall remain the holder of any such Note for all purposes of this Agreement, (iv) the Borrower and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement and (v) no participant under any such participation shall have any right to approve any amendment or waiver of any provision of this Agreement or any Note, or any consent to any departure by the Borrower therefrom, except to the extent that such amendment, waiver or consent would reduce the principal of, or interest on, the Note or any fees or other amounts payable hereunder, or release of all or substantially all of the Collateral, in each case to the extent subject to such participation, or postpone any date fixed for any payment of principal of, or interest on, the Notes or any fees or other amounts payable hereunder, in each case to the extent subject to such participation. (c) A Lender may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 9.11, disclose to the assignee or participant or proposed assignee or participant, any information relating to the Borrower furnished to such Lender by or on behalf of the Borrower; provided, that prior to any such disclosure, the assignee or -------- participant or proposed assignee or participant shall agree to preserve the confidentiality of any confidential information relating to the Borrower received by it from such Lender. (d) Notwithstanding any other provision contained in this Agreement or any other Financing Document to the contrary, any Lender may assign all or any portion of the Loan held by it as collateral security, provided that any -------- payment in respect of such assigned Loan or Note made by the Borrower to or for the account of the assigning or pledging Lender in accordance with the terms of this Agreement shall satisfy the Borrower's obligations hereunder in respect to such assigned Loan or Note to the extent of such payment. No such assignment shall release the assigning Lender from its obligations hereunder. (e) The Borrower hereby designates the Administrative Agent to serve as the Borrower's agent, solely for purposes of this Section 9.11, to maintain a register (the "Register") on which it will record the Loans made by each of the Lenders and each repayment in respect of the principal amount of the Loans of each Lender. Failure to make any such recordation, or any error in such recordation shall not affect the Borrower's obligations in respect of such Loans. With respect to any Lender, the transfer of the rights to the principal of, and interest on, any Loan shall not be effective until such transfer is recorded on the Register maintained by the Administrative Agent with respect to ownership of such Loans and prior to such recordation all amounts owing to the transferor with respect to such Loans shall remain owing to the transferor. The registration of assignment or transfer of all or part of any Loans shall be recorded by the Administrative Agent on the Register only upon the acceptance by the Administrative Agent of a properly executed and delivered Assignment and Acceptance pursuant to Section 9.11(a). The Borrower agrees to indemnify the Administrative Agent from and against any and all losses, claims, damages and liabilities of whatsoever nature which may be imposed on, asserted against or incurred by the Administrative Agent in performing its duties under this Section 9.11(e). (f) Upon its receipt of an Assignment and Acceptance executed by an assigning Lender and an Assignee (and, in any case where the consent of the Borrower is required by this Section, by the Borrower) together with payment to the Administrative Agent of a registration and processing fee of $3,500, the Administrative Agent shall (i) promptly accept such -54- Assignment and Acceptance and (ii) on the effective date determined pursuant thereto record the information contained therein in the Register and give notice of such acceptance and recordation to the Borrower. On or prior to such effective date, the Borrower, at its own expense, upon request, shall execute and deliver to the Administrative Agent (in exchange for the Note of the assigning Lender) a new Note to the order of such Assignee in an amount equal to the Loan acquired by it pursuant to such Assignment and Acceptance and, if such assigning Lender has retained a Loan, a new Note to the order of such assigning Lender in an amount equal to the Loan retained by it hereunder. 9.12 Survival. All indemnities set forth herein, including, without -------- limitation, Section 9.2, shall survive the execution and delivery of this Agreement and the Notes and the making and repayment of the Loans. In addition, each representation and warranty made or deemed to be made pursuant hereto shall survive the making of such representation and warranty, and no Lender shall be deemed to have waived, by reason of making any extension of credit, any Default or Event of Default which may arise by reason of such representation or warranty proving to have been false or misleading, notwithstanding that such Lender may have had notice or knowledge or reason to believe that such representation or warranty was false or misleading at the time such extension of credit was made. 9.13 WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO HEREBY -------------------- KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVES THE RIGHT ANY OF THEM MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED ON, OR ARISING OUT OF, UNDER OR IN CONNECTION WITH, THIS AGREEMENT, THE NOTES OR ANY OTHER FINANCING DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF ANY PARTY RELATING HERETO OR THERETO. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE LENDERS TO ENTER INTO THIS AGREEMENT. 9.14 Right of Set-off. In addition to any rights now or hereafter ---------------- granted under applicable Law or otherwise, and not by way of limitation of any such rights, upon the occurrence of an Event of Default, each Lender is hereby authorized at any time or from time to time, without presentment, demand, protest or other notice of any kind to the Borrower or to any other Person, any such notice being hereby expressly waived, to set off and to appropriate and apply any and all deposits (general or special) and any other Indebtedness at any time held or owing by such Lender (including without limitation by branches and agencies of such Lender wherever located), to or for the credit or the account of the Borrower against and on account of the Obligations or liabilities of the Borrower to such Lender under this Agreement or any of the other Financing Documents, including all claims of any nature or description arising out of or connected with this Agreement or any other Financing Document, irrespective of whether such Lender shall have made any demand hereunder and although said Obligations, liabilities or claims, or any of them, shall be contingent or unmatured. 9.15 Severability. Any provision hereof which is prohibited or ------------ unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or -55- unenforceability without invalidating the remaining provisions hereof and without affecting the validity or enforceability of any provision in any other jurisdiction. 9.16 Governing Law; Submission to Jurisdiction. (a) THIS AGREEMENT ----------------------------------------- AND EACH OF THE OTHER FINANCING DOCUMENTS (UNLESS SUCH DOCUMENT EXPRESSLY STATES OTHERWISE THEREIN) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF (OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW). (b) The Borrower hereby submits to the nonexclusive jurisdiction of the United States District Court for the Southern District of New York and of any New York State court sitting in New York City for the purposes of all legal proceedings arising out of or relating to this Agreement, any other Financing Document or the transactions contemplated hereby or thereby. The Borrower hereby irrevocably waives, to the fullest extent permitted by applicable Law, any objection which it may now or hereafter have to the laying of the venue of any such proceeding brought in such a court and any claim that any such proceeding brought in such a court has been brought in an inconvenient forum. The Borrower hereby irrevocably appoints CT Corporation System (the "Process Agent"), with ------------- an office on the date hereof at 111 Eighth Avenue, New York, New York 10011, as its agent to receive on its behalf and on behalf of its Property, service of copies of the summons and complaint and any other process that may be served in any such action or proceeding. Service upon the Process Agent shall be deemed to be personal service on the Borrower and shall be legal and binding upon the Borrower for all purposes notwithstanding any failure to mail copies of such legal process to the Borrower, or any failure on the part of the Borrower to receive the same. Nothing herein shall affect the right to serve process in any other manner permitted by applicable Law or any right to bring legal action or proceedings in any other competent jurisdiction, including judicial or non- judicial foreclosure of real property interests which are part of the Collateral. The Borrower further agrees that the aforesaid courts of the State of New York and of the United States of America for the Southern District of New York shall have exclusive jurisdiction with respect to any claim or counterclaim of the Borrower based upon the assertion that the rate of interest charged by or under this Agreement or under the other Financing Documents is usurious. To the extent permitted by applicable Law, the Borrower further irrevocably agrees to the service of process of any of the aforementioned courts in any suit, action or proceeding by the mailing of copies thereof by certified mail, postage prepaid, return receipt requested, to the Borrower at the address referenced in Section 9.3, such service to be effective upon the date indicated on the postal receipt returned from the Borrower. (c) The Borrower agrees that it will at all times continuously maintain an agent to receive service of process in the State of New York on behalf of itself and its Properties, and, in the event that for any reason the agent mentioned above shall not serve as agent for the Borrower to receive service of process in the State of New York on its behalf, the Borrower shall promptly appoint a successor satisfactory to the Administrative Agent so to serve, advise the Administrative Agent thereof, and deliver to the Administrative Agent evidence in writing of the successor agent's acceptance of such appointment. The foregoing provisions constitute, among other things, a special arrangement for service among the parties to this Agreement for the purposes of 28 U.S.C. (S) 1608. -56- 9.17 Waiver by Borrower. The Borrower waives any claim it may now or ------------------ hereafter have against the Administrative Agent, the Collateral Agent, any Lender and any Holder for any consequential, exemplary or punitive damage under or in connection with or relating to this Agreement or any of the Financing Documents. 9.18 Recourse. This Agreement is made with full recourse to the -------- Borrower and pursuant to and upon all the representations, warranties, covenants and agreements on the part of the Borrower contained herein and in the other Financing Documents to which the Borrower is a party and otherwise in writing in connection herewith and therewith. 9.19 Complete Agreement. THIS AGREEMENT, THE OTHER FINANCING ------------------ DOCUMENTS, THE FEE LETTER AND THE LEHMAN FEE LETTER REPRESENT THE FINAL AND COMPLETE AGREEMENT OF THE PARTIES HERETO AND THERETO WITH RESPECT TO THE LOANS, AND ALL PRIOR NEGOTIATIONS, REPRESENTATIONS, UNDERSTANDINGS, WRITINGS AND STATEMENTS OF ANY NATURE WITH RESPECT TO THE LOANS ARE HEREBY SUPERSEDED IN THEIR ENTIRETY BY THE TERMS OF THIS AGREEMENT AND THE OTHER FINANCING DOCUMENTS. 9.20 Publicity. Except as otherwise required by law, none of the --------- parties hereto shall issue any press release relating to, connected with or arising out of this Agreement and the other Financing Documents or the matters contained herein or therein, without obtaining the prior approval of each other party hereto to the contents and the manner of presentation and publication thereof. No references to any party hereto shall be made by any party hereto in any public statement without its consent except as otherwise required by Law. 9.21 Effectiveness. This Agreement and the other Financing Documents ------------- shall be effective as of the Effective Date. 9.22 Certain Representations and Warranties. Each of the Tranche A -------------------------------------- Lender and the Tranche B Lender by reason of its business or financial experience, has the capacity to protect its own interests (within the meaning of Section 25102(f)(2) of the California Corporations Code) in connection with the transactions contemplated by the Financing Documents. 9.23 Confidentiality. Each Lender agrees to keep confidential in --------------- accordance with such Lender's customary practices (and in any event in compliance with applicable law respecting material non-public information) all information obtained by it pursuant hereto and the other Financing Documents identified as confidential in writing at the time of delivery and agrees that it will only use such information in connection with the transactions contemplated by this Agreement and the other Financing Documents and not disclose any of such information other than (a) to such Lender's employees, representatives, directors, attorneys, auditors, agents, professional advisors, trustees or indirect contractual counterparty in swap agreements or such contractual counterparty's professional advisor (so long as such contractual counterparty or professional advisor to such contractual counterparty agrees to be bound by the provision of this Section 9.23 or is bound by a confidentiality agreement containing substantially equivalent provisions), (b) to the extent such information presently is or hereafter becomes available to such -57- Lender on a non-confidential basis from any source or such information that is in the public domain at the time of disclosure, (c) to the extent disclosure is required by law (including applicable securities laws), regulations, subpoena or judicial order or process (provided that notice of such requirement or order -------- shall be promptly furnished to the Borrower unless such notice is legally prohibited) or requested or required by bank, securities, insurance or investment company regulations or auditors or any administrative body or commission (including the Securities Valuation Office of the National Association of Insurance Commissioners) to whose jurisdiction such Lender may be subject, (d) to any rating agency to the extent required in connection with any rating to be assigned to such Lender, (e) to Assignees or prospective Assignees or participants or prospective participants who agree to be bound by the provisions of this Section 9.23 or who are subject to confidentiality agreements containing substantially equivalent provisions, (f) to the extent required in connection with any litigation between any party hereto or thereto and any Lender with respect to the Loans or this Agreement and the other Financing Documents or (g) with the Borrower's prior written consent. The agreements in this Section 9.23 shall survive repayment of the Loans and all other amounts payable hereunder. SECTION 10. THE ADMINISTRATIVE AGENT; THE LEAD ARRANGER, THE CO- --------------------------------------------------- ARRANGER AND THE BOOK MANAGER. - ----------------------------- 10.1 Appointment. Lehman Commercial Paper Inc. shall be the ----------- Administrative Agent and shall act as specified herein and in the other Financing Documents. Each Lender hereby irrevocably authorizes, and the holder of any Note by the acceptance of such Note shall be deemed irrevocably to authorize, the Administrative Agent to take such action on its behalf under the provisions of this Agreement, the other Financing Documents and any other instruments and agreements referred to herein or therein and to exercise such powers and to perform such duties hereunder and thereunder as are specifically delegated to or required of the Administrative Agent by the terms hereof and thereof and such other powers as are reasonably incidental thereto. The Administrative Agent may perform any of its duties hereunder by or through its officers, directors, agents or employees. 10.2 Nature of Duties. The Administrative Agent shall have no duties ---------------- or responsibilities except those expressly set forth in this Agreement and the Security Documents. Neither the Administrative Agent nor any of its officers, directors, agents or employees shall be liable for any action taken or omitted by it or them hereunder or under any other Financing Document or in connection herewith or therewith, unless caused by its or their gross negligence or willful misconduct. The duties of the Administrative Agent shall be mechanical and administrative in nature; the Administrative Agent shall not have by reason of this Agreement or any other Financing Document, or by reason of the use of the term "agent" with reference to the Administrative Agent, a fiduciary relationship in respect of any Lender or the holder of any Note; and nothing in this Agreement or any other Financing Document, expressed or implied, is intended to or shall be so construed as to impose upon the Administrative Agent any obligations in respect of this Agreement or any other Financing Document except as expressly set forth herein. 10.3 Lack of Reliance on the Administrative Agent. Independently and -------------------------------------------- without reliance upon the Administrative Agent, each Lender and each holder of any Note, to the extent it -58- deems appropriate, has made and shall continue to make (i) its own independent investigation of the financial condition and affairs of the Borrower in connection with the making and the continuance of the Loans and the taking or not taking of any action in connection herewith and (ii) its own appraisal of the creditworthiness of the Borrower, except as expressly provided in this Agreement, the Administrative Agent shall have no duty or responsibility, either initially or on a continuing basis, to provide any Lender or the holder of any Note with any credit or other information with respect thereto, whether coming into its possession before the making of the Loans or at any time or times thereafter. The Administrative Agent shall not be responsible to any Lender or the holder of any Note for any recitals, statements, information, representations or warranties herein or in any document, certificate or other writing delivered in connection herewith or for the execution, effectiveness, genuineness, validity, enforceability, perfection, collectibility, priority or sufficiency of this Agreement or any other Financing Document or the financial condition of the Borrower or be required to make any inquiry concerning either the performance or observance of any of the terms, provisions or conditions of this Agreement or any other Financing Document, or the financial condition of the Borrower or the existence or possible existence of any Default or Event of Default. 10.4 Certain Rights of the Administrative Agent. If the ------------------------------------------ Administrative Agent shall request instructions from the Required Waiver Lenders or Required Acceleration Lenders, as the case may be, with respect to any act or action (including failure to act) in connection with this Agreement or any other Financing Document, the Administrative Agent shall be entitled to refrain from such act or taking such action unless and until the Administrative Agent shall have received instructions from the Required Waiver Lenders or Required Acceleration Lenders, as the case may be, and the Administrative Agent shall not incur liability to any Person by reason of so refraining. Without limiting the foregoing, no Lender or the holder of any Note shall have any right of action whatsoever against the Administrative Agent as a result of the Administrative Agent acting or refraining from acting hereunder or under any other Financing Document in accordance with the instructions of the Required Waiver Lenders or Required Acceleration Lenders, as the case may be. 10.5 Reliance. The Administrative Agent shall be entitled to rely, -------- and shall be fully protected in relying, upon any note, writing, resolution, notice, statement, certificate, telex, teletype or telecopier message, cablegram, radiogram, order or other document or telephone message signed, sent or made by any Person that the Administrative Agent believed to be the proper Person, and, with respect to all legal matters pertaining to this Agreement and any other Financing Document its duties hereunder and thereunder, upon advice of counsel selected by it. 10.6 Indemnification. To the extent the Administrative Agent is not --------------- reimbursed and indemnified by the Borrower, each Lender will reimburse and indemnify the Administrative Agent, in proportion to its respective Loan, for and against any and all liabilities, obligations, losses, damages, penalties, claims, actions, judgments, suits, costs, expenses or disbursements of whatsoever kind or nature which may be imposed on, asserted against or incurred by the Administrative Agent in performing its duties hereunder or under any other Financing Document, or in any way relating to or arising out of this Agreement or any other Financing Document; provided, however, that no Lender shall be liable for any portion of such liabilities, obligations, -59- losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent's gross negligence or willful misconduct. 10.7 The Administrative Agent in its Individual Capacity. With --------------------------------------------------- respect to its obligation to make Loans under this Agreement, and with respect to any Loan held by it or made by it, the Administrative Agent shall have the rights and powers specified herein for a "Lender" and may exercise the same rights and powers as though it were not performing the duties specified herein; and the term "Lender," "Required Waiver Lenders", "Required Acceleration Lenders", "holder of Note" or any similar terms shall, unless the context clearly otherwise indicates, include the Administrative Agent in its individual capacity. The Administrative Agent may accept deposits from, lend money to, and generally engage in any kind of banking, trust or other business with the Borrower or any Affiliate of the Borrower as if it were not performing the duties specified herein, and may accept fees and other consideration from the Borrower for services in connection with this Agreement and otherwise without having to account for the same to the Lenders. 10.8 Holders. The Administrative Agent may deem and treat the payee ------- of any Note as the owner thereof for all purposes hereof unless and until a written notice of the assignment, transfer or endorsement thereof, as the case may be, shall have been filed with the Administrative Agent. Any request, authority or consent of any Person who, at the time of making such request or giving such authority or consent, is the holder of any Note shall be conclusive and binding on any subsequent holder, transferee, assignee or indorsee, as the case may be, of such Note or of any Note or Notes issued in exchange therefor. 10.9 Resignation by the Administrative Agent. (a) The --------------------------------------- Administrative Agent may resign from the performance of all its functions and duties hereunder and/or under the other Financing Documents at any time by giving 15 Business Days' prior written notice to the Borrower and each Lender. Such resignation shall take effect upon the appointment of a successor Administrative Agent pursuant to clauses (b) and (c) below or as otherwise provided below. (b) Upon any such notice of resignation, the Required Waiver Lenders shall appoint a successor Administrative Agent hereunder or thereunder who shall be a commercial bank, trust company or other financial institution which is a Lender and which (unless an Event of Default shall be continuing) shall be subject to the reasonable approval of the Borrower. (c) If a successor Administrative Agent shall not have been so appointed within such 15 Business Day period, the Administrative Agent, with the consent of the Borrower, may then appoint a successor Administrative Agent who shall serve as Administrative Agent hereunder or thereunder until such time, if any, as the Required Waiver Lenders appoint a successor Administrative Agent as provided above. (d) If no successor Administrative Agent has been appointed pursuant to clause (b) or (c) above by the 20th Business Day after the date such notice of resignation was given by the Administrative Agent, the Administrative Agent's resignation shall become effective and the Required Waiver Lenders shall thereafter perform all the duties of the Administrative -60- Agent hereunder and/or under any other Financing Document until such time, if any, as the Required Waiver Lenders appoint a successor Administrative Agent as provided above. 10.10 The Lead Arranger, Co-Arranger and Book Manager. None of the ----------------------------------------------- Lead Arranger, the Co-Arranger and the Book Manager, in such respective capacities, shall have any duties or responsibilities under this Agreement or any other Financing Document, nor shall any of such Persons, in such respective capacities, have any obligations or liabilities hereunder or under any other Financing Document. * * * -61- IN WITNESS WHEREOF, the parties hereto have caused their duly authorized officers to execute and deliver this Agreement as of the date first above written. PG&E CORPORATION By: /s/ [ILLEGIBLE]^^ ------------------------------------ Name: Title: GENERAL ELECTRIC CAPITAL CORPORATION, as a Lender and Co-Arranger By: /s/ Mark T Mellana ------------------------------------ Name: Mark T Mellana Title: Attorney-in-fact LEHMAN COMMERCIAL PAPER INC., as a Lender and Administrative Agent By: /s/ G. Andrew Keith ------------------------------------ Name: G. Andrew Keith Title: Authorized Signatory LEHMAN BROTHERS INC., as Lead Arranger and Book Manager By: /s/ G. Andrew Keith ------------------------------------ Name: G. Andrew Keith Title: Authorized Signatory G. Andrew Keith Senior Vice President APPENDIX A to Credit Agreement ---------------- DEFINED TERMS AND RULES OF INTERPRETATION ----------------------------------------- 1. Defined Terms. ------------- "Affiliate" shall mean, with respect to any Person, (a) any other --------- Person that is directly or indirectly Controlled by, under common Control with or Controls such Person; (b) any other Person owning beneficially or Controlling five percent or more of the Voting Stock of such Person; or (c) any officer, director or partner of such Person, except with respect to any officer or director of the Borrower. "Administrative Agent" shall mean Lehman Commercial Paper Inc., acting -------------------- in its capacity as agent for the Lenders pursuant to the Credit Agreement, and any successor in such capacity. "Applicable Margin" shall mean (a) as to the Base Rate Loan, (i) ----------------- during the period commencing on the Closing Date to but excluding the date eighteen (18) months from the Closing Date, 2.50% per annum and (ii) during the period commencing on the date eighteen (18) months from the Closing Date and thereafter, 4.00% per annum, and (b) as to the Eurodollar Loan, (i) during the period commencing on the Closing Date to but excluding the date eighteen (18) months from the Closing Date, 2.50% and (ii) during the period commencing the date eighteen (18) months from the Closing Date and thereafter, 4.00%. "Appraiser" shall have the meaning provided in Section 6.14 of the --------- Credit Agreement. "Approved Appraiser" shall mean any independent nationally recognized ------------------ investment bank experienced in the valuation of equity interests of a company similar to NEG, Inc. as may be reasonably proposed by the Borrower at the request of any Lender; provided that the Borrower shall always propose at least -------- two alternate investment banks. "Asset Sale" shall mean any sale, transfer or other disposition of any ---------- Property of the Borrower and any member of the NEG Group. "Assignee" shall have the meaning provided in Section 9.11 of the -------- Credit Agreement. "Audited Financial Statements" shall have the meaning provided in ---------------------------- Section 5.11 of the Credit Agreement. "Authorized Officer" shall mean (i) with respect to any Person that is ------------------ a corporation or a limited liability company, the Chairman, President, any Vice President or Secretary of such Person and (ii) with respect to any Person that is a partnership, the President, any Vice President or Secretary (or Assistant Secretary) of a general partner or managing partner of such Person and Appendix A Page 2 in each case whose name appears on a certificate of incumbency of such Person delivered in accordance with the Credit Agreement, as such certificate may be amended from time to time. "Bankruptcy Code" shall have the meaning provided in Section 8.1(e) of --------------- the Credit Agreement. "Bankruptcy Law" shall mean the Bankruptcy Code and any other Law of -------------- any jurisdiction relating to bankruptcy, insolvency, liquidation, reorganization, moratorium, winding-up or composition or readjustment of debts or any similar Law. "Base Rate", for any day, shall mean the rate per annum equal to the --------- higher of (a) the Federal Funds Rate for such day plus one-half of one percent (.5%) and (b) the Prime Rate for such day. Any changes in the Base Rate due to a change in the Prime Rate or the Federal Funds Rate shall be effective on the effective date of such change in the Prime Rate or Federal Funds Rate. "Base Rate Loans" shall mean the Loans or any portion thereof which --------------- bears interest based upon the Base Rate. "Book Manager" shall mean Lehman Brothers Inc., a Delaware ------------ corporation. "Borrower" shall mean PG&E Corporation, a California corporation. -------- "Borrowing" shall mean the borrowing of Loans of one Type from a --------- Lender on a given date, provided that Base Rate Loans incurred pursuant to -------- Section 2.7(b) shall be considered part of the related Borrowing of Eurodollar Loans. "Business Day" shall mean (i) for all purposes other than as covered ------------ by clause (ii) below, any day except Saturday, Sunday and any day which shall be in New York City, a legal holiday or a day on which banking institutions are authorized or required by law or other government action to close in such city, and (ii) with respect to all notices and determinations in connection with, and payments of principal and interest on, any Eurodollar Loan, any day which is a Business Day described in clause (i) above and which is also a day for trading by and between banks in the London interbank eurodollar market. "Business Plan" shall mean the certified copy of the business plan of ------------- NEG, Inc., dated the Closing Date, as delivered to the Lenders. "CA Fee" shall mean the fees and expenses of the Collateral Agent set ------ forth in the Schedule of Fees with the Collateral Agent dated the Closing Date. "Capital Expenditure" shall mean, with respect to any Person, all ------------------- expenditures by such Person which should be capitalized in accordance with generally accepted accounting principles, including all such expenditures with respect to fixed or capital assets (including, without limitation, expenditures for maintenance and repairs which should be capitalized in accordance with generally accepted accounting principles) and the amount of Capital Lease Obligations incurred by such Person. Appendix A Page 3 "Capital Lease Obligations" shall mean, for any Person, the ------------------------- obligations of such Person to pay rent or other amounts under a lease of (or other agreement conveying the right to use) real or personal Property which obligations are required to be classified and accounted for as a capital lease on a balance sheet of such Person under U.S. GAAP (including Statement of Financial Accounting Standards No. 13 of the Financial Accounting Standards Board ("Statement No. 13")) and, for purposes of the Credit Agreement, the amount of such obligations shall be the capitalized amount thereof, determined in accordance with U.S. GAAP (including such Statement No. 13). "Capital Stock" shall mean, with respect to any Person, any and all ------------- shares, interests, participations and/or rights in or other equivalents (however designated, whether voting or nonvoting, ordinary or preferred) in the equity or capital of such Person, now or hereafter outstanding, and any and all rights, warrants or options exchangeable for or convertible into any thereof. "Cash Equivalents" shall mean, as to any Person, (i) securities issued ---------------- or directly and fully guaranteed or insured by the United States or any agency or instrumentality thereof (provided that the full faith and credit of the -------- United States is pledged in support thereof) having maturities of not more than one year from the date of acquisition, (ii) time deposits and certificates of deposit of any commercial bank having, or which is the principal banking subsidiary of a bank holding company organized under the laws of the United States, any State thereof or the District of Columbia having capital, surplus and undivided profits aggregating in excess of $200,000,000, with maturities of not more than one year from the date of acquisition by such Person, (iii) repurchase obligations with a term of not more than 90 days for underlying securities of the types described in clause (i) above entered into with any bank meeting the qualifications specified in clause (ii) above, (iv) commercial paper issued by any Person incorporated in the United States rated at least A-1 or the equivalent thereof by Standard & Poor's or at least P-1 or the equivalent thereof by Moody's and in each case maturing not more than one year after the date of acquisition by such Person, and (v) investments in money market funds substantially all of whose assets are comprised of securities of the types described in clauses (i) through (iv) above. "CERCLA" shall mean the Comprehensive Environmental Response, ------ Compensation, and Liability Act of 1980, as the same may be amended from time to time, 42 U.S.C. (S) 9601 et seq. -- ---- "Charter Documents" shall mean, with respect to any Person, (i) the ----------------- articles of incorporation or other similar organizational document of such Person, (ii) the by-laws or other similar document of such Person, (iii) any certificate of designation or instrument relating to the rights of preferred shareholders or other holders of Capital Stock of such Person and (iv) any shareholder rights agreement or other similar agreement. "Closing Date" shall mean the date upon which the conditions precedent ------------ set forth in Section 4.1 of the Credit Agreement have been satisfied (or waived by all the Lenders). "Co-Arranger" shall mean General Electric Capital Corporation, a New ----------- York corporation. Appendix A Page 4 "Code" shall mean the Internal Revenue Code of 1986, as amended from ---- time to time, and the regulations promulgated and rulings issued thereunder. Section references to the Code are to the Code as in effect at the date of the Credit Agreement and any subsequent provisions of the Code, amendatory thereof, supplemental thereto or substituted therefor. "Collateral" shall mean all Property that, in accordance with the ---------- terms of the Security Documents, is intended to be subject to any Lien in favor of the Collateral Agent, for the benefit of each Lender. "Collateral Agent" shall mean Bankers Trust Company, acting as ---------------- collateral agent for the benefit of the Lenders. "Commitment" shall mean individually or collectively, as the context ---------- may require, the Tranche A Commitment or the Tranche B Commitment. "Commitment Fees" shall mean (i) the fee payable to the Tranche A --------------- Lender pursuant to the Fee Letter and (ii) the commitment fees payable to the Tranche B Lender pursuant to the Lehman Fee Letter. "Compliance" shall have the meaning provided in Section 13 of the LLC ---------- Agreement, attached hereto as Annex A. "Contingent Obligation" shall mean, as to any Person, any obligation --------------------- of such Person guaranteeing or intending to guarantee any Indebtedness, leases, dividends or other obligations ("primary obligations") of any other Person (the "primary obligor") in any manner, whether directly or indirectly, including, without limitation, any obligation of such Person, whether or not contingent, (a) to purchase any such primary obligation or any property constituting direct or indirect security therefor, (b) to advance or supply funds (i) for the purchase or payment of any such primary obligation or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (c) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation or (d) otherwise to assure or hold harmless the owner of such primary obligation against loss in respect thereof. The amount of any Contingent Obligation shall be deemed to be an amount equal to the aggregate current exposure pursuant to each applicable agreement net of the fair market value of any posted collateral thereunder. "Control" shall mean possession, directly or indirectly, of the power ------- to direct or cause the direction of the management and policies of a Person, whether through the ownership of partnership interests or voting securities, by contract or otherwise. "Covered Contracts" shall have the meaning provided in Section 5.7 of ----------------- the Credit Agreement. "Covered Parties" shall have the meaning provided in Section 5.1 of --------------- the Credit Agreement. Appendix A Page 5 "CPUC" shall mean the California Public Utilities Commission or its ---- successor. "Credit Agreement" shall mean the Credit Agreement, dated as of March ---------------- 1, 2001 among the Borrower, the Lenders party thereto, General Electric Capital Corporation, as Co-Arranger, Lehman Commercial Paper Inc., as Administrative Agent and Lehman Brothers Inc., as Lead Arranger and Book Manager, as amended, modified or supplemented from time to time. "Date Certain" shall mean the Initial Date Certain, as such date may ------------ be extended pursuant to Section 2.9 of the Credit Agreement. "Default" shall mean any event or circumstance which with notice or ------- lapse of time or both would become an Event of Default. "Dividend" shall mean, with respect to any Person, that such Person -------- has declared or paid a dividend, distribution or returned any equity capital to its stockholders, partners or members or authorized or made any other distribution, payment or delivery of property (other than common equity of such Person) or cash to its stockholders, partners or members as such, or redeemed, retired, purchased or otherwise acquired, directly or indirectly, for a consideration any shares of any class of its capital stock or any partnership or membership interests outstanding on or after the Closing Date (or any options or warrants issued by such Person with respect to its capital stock or other equity interests), or set aside any funds for any of the foregoing purposes, or shall have permitted any of its Subsidiaries to purchase or otherwise acquire for a consideration any shares of any class of the capital stock or any partnership or membership interests of such Person outstanding on or after the Closing Date (or any options or warrants issued by such Person with respect to its capital stock or other equity interests). Without limiting the foregoing, "Dividends" with respect to any Person shall also include all payments made or required to be made by such Person with respect to any stock appreciation rights, plans, equity incentive or achievement plans or any similar plans or setting aside of any funds for the foregoing purposes. "Disclosure Letter" shall mean the letter from the Borrower, addressed ----------------- to the Administrative Agent and the Lenders, dated the Closing Date, with respect to certain disclosure of the Borrower. "Distribution" shall have the meaning provided in Section 13 of the ------------ LLC Agreement, attached hereto as Annex A. "Dollars" and the sign "$" shall each mean freely transferable, lawful ------- - money of the United States. "Effective Date" shall mean March 1, 2001. -------------- "Environmental Claim" shall mean, with respect to any Person, (i) any ------------------- notice, claim, administrative, regulatory or judicial or equitable action, suit, Lien, judgment or demand by any other Person or (ii) any other written communication by any Governmental Authority, in either case alleging or asserting such Person's liability for investigatory costs, cleanup costs, consultants' fees, governmental response costs, damages to natural resources (including, without limitation, wetlands, wildlife, aquatic and terrestrial species and vegetation) or other Property, Appendix A Page 6 property damages, personal injuries, fines or penalties arising out of, based on or resulting from (x) the presence, or Release into the environment, of any Hazardous Material at any location, whether or not owned by such Person or (y) circumstances forming the basis of any violation, or alleged violation, of any Environmental Law or Governmental Approval issued under any Environmental Law. "Environmental Laws" shall mean any and all Laws, now or hereafter in ------------------ effect, and any judicial or administrative interpretation thereof, including any judicial or administrative order, consent decree or judgment, relating to the environment, human health or safety, or to emissions, discharges, releases or threatened releases of pollutants, contaminants, chemicals, or toxic or hazardous substances or wastes into the environment including, without limitation, ambient air, surface water, groundwater, or land, or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport, or handling of pollutants, contaminants, chemicals, or toxic or hazardous substances or wastes. "Equity Infusion Agreements" shall mean the agreements identified as -------------------------- such on Part B of the Disclosure Letter. "Equity Interest" shall have the meaning provided in Section 5.10(f) --------------- of the Credit Agreement. "ERISA" shall mean the Employee Retirement Income Security Act of ----- 1974, as amended from time to time, and the regulations promulgated and rulings issued thereunder. Section references to ERISA are to ERISA, as in effect at the date of the Credit Agreement and any subsequent provisions of ERISA, amendatory thereof, supplemental thereto or substituted therefor. "ERISA Affiliate" shall mean each person (as defined in Section 3(9) --------------- of ERISA) which together with the Borrower or a Subsidiary of the Borrower would be deemed to be a "single employer" (i) within the meaning of Section 414(b),(c),(m) or (o) of the Code or (ii) as a result of the Borrower or a Subsidiary of the Borrower being or having been a general partner of such person. "Escrow Agreement" shall mean the Escrow Agreement, dated as of March ---------------- 1, 2001, among the Borrower, the Lenders party thereto and Bankers Trust Company, as escrow agent, setting forth the payment and account information in connection with the Refinancing of the Indebtedness of the Borrower. "Eurodollar Loan" shall mean any Loan or any portion thereof which --------------- bears interest based on the Eurodollar Rate. "Eurodollar Rate" shall mean, with respect to each Interest Period in --------------- respect of a Eurodollar Loan, the rate per annum (rounded upwards, if necessary, to the nearest 1/1000 of 1%) determined by the Administrative Agent to be equal to the quotient obtained by dividing (a) the Eurorate for such Eurodollar Loan for such Interest Period by (b) 1 minus the Reserve Requirement for such Eurodollar Loan for such Interest Period. Appendix A Page 7 As used herein, "Eurorate" shall mean, with respect to each Interest Period in respect of a Eurodollar Loan, as determined by the Administrative Agent, the rate per annum (rounded upwards, if necessary, to the nearest 1/1000 of 1%) appearing on Telerate Page 3750 (or any successor page) as the London interbank offered rate for deposits in Dollars at approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period for a term comparable to such Interest Period. If for any reason such rate is not available, the term "Eurorate" shall mean, for any Eurodollar Loan for any -------- Interest Period therefor, the rate per annum (rounded upwards, if necessary, to the nearest 1/1000 of 1%) appearing on Reuters Screen LIBO Page as the London interbank offered rate for deposits in Dollars at approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period for a term comparable to such Interest Period; provided, however, if more than -------- ------- one rate is specified on Reuters Screen LIBO Page, the applicable rate shall be the arithmetic mean of all such rates (rounded upwards, if necessary, to the nearest 1/1000 of 1%). "Event of Default" shall have the meaning provided in Section 8.1 of ---------------- the Credit Agreement. "EWG" shall mean an "exempt wholesale generator" as defined under --- PUHCA. "Existing Indebtedness Agreements" shall have the meaning provided in -------------------------------- Section 5.31 of the Credit Agreement. "Expense Sharing Agreement" shall mean each of the agreements entitled ------------------------- "Continuing Services Agreement" listed and marked with "*" on Schedule 5.17. "Extended Date Certain" shall mean each of (i) the date which is six --------------------- months after the Initial Date Certain or (ii) the date which is twelve months after the Initial Date Certain. "Extension Fee" shall have the meaning set forth in the Fee Letter or ------------- the Lehman Fee Letter. "Federal Funds Rate" shall mean, for any day, the rate per annum ------------------ (rounded upwards, if necessary, to the nearest 1/1000 of 1%) equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided, that (i) if the day for which such rate is -------- to be determined is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day and (ii) if such rate is not so published for any day, the Federal Funds Rate for such day shall be the average rate charged to the Administrative Agent (in its individual capacity) on such day on such transactions as determined by the Administrative Agent. "Fee Letter" shall mean the Fee Letter dated March 1, 2001 between the ---------- Borrower and the Tranche A Lender. "FERC" shall mean the Federal Energy Regulatory Commission or its ---- successor. Appendix A Page 8 "FI Subsidiaries" shall mean any of PG&E Energy Trading Holdings --------------- Corp., a California corporation, PG&E Gas Transmission, Northwest Corporation, a California corporation and PG&E Generating Company LLC, a Delaware limited liability company. "Financing Documents" shall mean, collectively, the Credit Agreement, ------------------- the Note, the Fee Letter, the Lehman Fee Letter, the Escrow Agreement, the Security Documents and the Option Agreement. "First Interest Period" shall have the meaning provided in Section --------------------- 2.5(d). "Foreign Pension Plan" shall mean any plan, fund (including, without -------------------- limitation, any superannuation fund) or other similar program established or maintained outside the United States of America by the Borrower or any one or more of its Subsidiaries primarily for the benefit of employees of the Borrower or such Subsidiaries residing outside the United States of America, which plan, fund or other similar program provides, or results in, retirement income, a deferral of income in contemplation of retirement or payments to be made upon termination of employment, and which plan is not subject to ERISA or the Code. "FPA" shall mean the Federal Power Act, as amended, and the rules and --- regulations promulgated thereunder. "Governmental Approval" shall mean any authorization, consent, --------------------- approval, license, ruling, permit, tariff, rate, certification, exemption, filing, variance, claim, order, judgment, decree, publication, notice to, declaration of or with, or registration by or with, any Governmental Authority. "Governmental Authority" shall mean any government, governmental ---------------------- department, commission, board, bureau, agency, regulatory authority, instrumentality, judicial or administrative body, domestic or foreign, federal, state or local having jurisdiction over the matter or matters in question. "Hazardous Material" shall mean any substance that is regulated or ------------------ could lead to liability under any Environmental Law, including, but not limited to, any petroleum or petroleum product, asbestos in any form that is or could become friable, transformers or other equipment that contain dielectric fluid containing levels of polychlorinated biphenyls (PCB's), hazardous waste, hazardous material, hazardous substance, toxic substance, contaminant or pollutant, as defined or regulated as such under, any applicable Environmental Law. "Hedging Agreement" means any agreement in respect of any interest ----------------- rate swap transaction, basis swap, forward rate transaction, commodity swap, commodity option, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, currency swap transaction, cross-currency rate swap transaction, currency option or any other similar transaction (including any option with respect to any of the foregoing transactions) or any combination of the foregoing transactions entered into by the Borrower. "Holder" shall have the meaning provided in the Option Agreement. ------ Appendix A Page 9 "Holding Company Conditions" shall mean the conditions set forth by -------------------------- the CPUC in Decision 96-11-017 or Decision 99-04-068 and any decision of the CPUC which imposes a requirement or condition on the Borrower affecting the Borrower's relationship with PGE Utility. "HSR Act" shall mean the Hart-Scott-Rodino Antitrust Improvements Act ------- of 1976. "Indebtedness" of any Person shall mean (i) all indebtedness of such ------------ Person for borrowed money, (ii) the deferred purchase price of assets or services which in accordance with U.S. GAAP would be shown on the liability side of the balance sheet of such Person, (iii) the face amount of all letters of credit issued for the account of such Person and, without duplication, all drafts drawn thereunder, (iv) all Indebtedness of a second Person secured by any Lien on any Property owned by such first Person, whether or not such Indebtedness has been assumed, (v) all Capital Lease Obligations of such Person, (vi) all obligations of such Person to pay a specified purchase price for goods or services whether or not delivered or accepted, i.e., take-or-pay and similar ---- obligations, (vii) all net obligations of such Person under Hedging Agreements and (viii) all Contingent Obligations of such Person; provided that Indebtedness -------- shall not include trade payables arising in the ordinary course of business so long as such trade payables are payable within 90 days of the date the respective goods are delivered or the respective services are rendered and are not overdue. "Indemnified Liabilities" shall have the meaning provided in Section ----------------------- 9.2(a) of the Credit Agreement. "Indemnified Matters" shall have the meaning provided in Section ------------------- 9.2(b) of the Credit Agreement. "Indemnified Person" shall have the meaning provided in Section 9.2 of ------------------ the Credit Agreement. "Initial Date Certain" shall mean the second anniversary of the -------------------- Closing Date. "Insurance Proceeds" shall mean all amounts payable to the Borrower or ------------------ the Collateral Agent in respect of any insurance required to be maintained (or caused to be maintained) by the Borrower pursuant to Section 5.9 of the Credit Agreement (other than general liability insurance, delayed completion insurance and business interruption insurance), regardless of whether such payments are received from any insurer or from either EPC Contractor pursuant to the EPC Contracts or otherwise. "Interest Determination Date" shall mean, with respect to any --------------------------- Eurodollar Loan, the second Business Day prior to the commencement of any Interest Period relating to such Eurodollar Loan. "Interest Period" shall have the meaning provided in Section 2.6 of --------------- the Credit Agreement. Appendix A Page 10 "Interest Prepaid Amount" shall mean $73,500,000, which is the total ----------------------- amount of interest payable on the Loans based on a one-year Eurodollar Rate as of the Closing Date discounted to present value as of the Closing Date using a discount rate of 4.25%. "Investment" in any Person shall mean, without duplication: (a) the ---------- acquisition (whether for cash, securities, other Property, services or otherwise) or holding of capital stock, bonds, notes, debentures, partnership or other ownership interests or other securities of such Person, or any agreement to make any such acquisition or to make any capital contribution to such Person; or (b) the making of any deposit with, or advance, loan or other extension of credit to, such Person. "Investments" shall have the meaning provided in Section 7.5 of the ----------- Credit Agreement. "IPO" shall mean the sale, in an initial underwritten offering, --- registered under the Securities Act, of shares of NEG, Inc.'s common stock, where after such offering, the common stock sold in such offering is traded on the Nasdaq National Market or a national securities exchange. "Law" shall mean, with respect to any Person (i) any statute, law, --- regulation, ordinance, rule, judgment, order, decree, permit, concession, grant, franchise, license, agreement or other governmental restriction or any interpretation or administration of any of the foregoing by any Governmental Authority (including, without limitation, Governmental Approvals) applicable to such Person and (ii) any directive, guideline, policy, requirement or any similar form of decision of or determination by any Governmental Authority which is binding on such Person, in each case, whether now or hereafter in effect (including, without limitation, in each case, any Environmental Law). "Lead Arranger" shall mean Lehman Brothers Inc., a Delaware ------------- corporation. "Lehman Fee Letter" shall mean the Lehman Fee Letter dated March 1, ----------------- 2001 among the Borrower, Lehman Brothers Inc. and Lehman Commercial Paper Inc. "Lender" shall mean, individually or collectively, as the context may ------ require, the Tranche A Lender or the Tranche B Lender and any Assignee thereof pursuant to Section 9.11 of the Credit Agreement. "Lien" shall mean, with respect to any Property of any Person, any ---- mortgage, lien, deed of trust, hypothecation, fiduciary transfer of title, assignment by way of security, lien, pledge, charge, lease, sale and lease-back arrangement, easement, servitude, trust arrangement, or security interest or encumbrance of any kind in respect of such Property, or any preferential arrangement having the practical effect of constituting a security interest with respect to the payment of any obligation with, or from the proceeds of, any Property of any kind (and a Person shall be deemed to own subject to a Lien any Property that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such Property). Appendix A Page 11 "Limited Liability Company Interest" shall have the meaning provided ---------------------------------- in the LLC Pledge Agreement. "LLC" shall mean PG&E National Energy Group, LLC, a Delaware limited --- liability company. "LLC Agreement" shall mean the Amended and Restated Limited Liability ------------- Company Agreement dated as of March 1, 2001 of PG&E National Energy Group LLC. "LLC Interests" shall mean, as to LLC, any and all shares of the ------------- profits and losses of such Person, any and all rights to receive distributions of such Person's assets, and any and all rights, benefits or privileges pertaining to any of the foregoing, including, without limitation, voting rights and the right to participate in management. "LLC Pledge Agreement" shall mean the LLC Pledge Agreement dated as of -------------------- March 1, 2001, among the Borrower, as pledgor, NEG, Inc., as issuer, the Lenders and Bankers Trust Company, as pledgee, as Collateral Agent for the benefit of the Lenders, as amended, modified or supplemented from time to time. "Loan" shall mean each of the Tranche A Loan and the Tranche B Loan, ---- and shall also mean, where the context requires, any portion of any such loan held by a Lender or subject to a particular Interest Period or interest rate option. "Losses" shall have the meaning provided in Section 9.2(b) of the ------ Credit Agreement. "Margin Stock" shall mean margin stock within the meaning of ------------ Regulation U and Regulation X. "Material Adverse Change" shall mean, with respect to any Person, a ----------------------- material adverse change in the condition (financial or otherwise), results of operations, business, Properties, liabilities, management or prospects of such Person. "Material Adverse Effect" shall mean a material adverse effect on (i) ----------------------- the condition (financial or otherwise), results of operations, business, Properties, liabilities, management or prospects of the Borrower, (ii) the ability of the Borrower, LLC or NEG, Inc. to timely perform any of its obligations under any of the Financing Documents to which it is a party, (iii) the legality, validity or enforceability of any material provision of any Financing Document, (iv) the rights and remedies of the Collateral Agent, the Administrative Agent, any Holder or any Lender under any of the Financing Documents or (v) the security interests provided under the Security Documents or the value thereof; provided that a Utility Event or defaults on Indebtedness to -------- be Refinanced as of the Closing Date and other events of default described in the SEC Filings of the Borrower since December 31, 2000 but prior to the Closing Date, shall not constitute a Material Adverse Effect. "Material Agreements" shall have the meaning provided in Section ------------------- 4.1(g)(iii) of the Credit Agreement. Appendix A Page 12 "Moody's" shall mean Moody's Investors Service, Inc. ------- "NAIC" shall mean the National Association of Insurance Commissioners. ---- "NEG Group" means LLC and each of its subsidiaries and each ---------- corporation, company or partnership in which any of the foregoing own a Controlling equity interest. "NEG, Inc." shall mean PG&E National Energy Group, Inc., a Delaware --------- corporation. "NEG Subsidiary" shall mean, as the context may require, any or all -------------- Subsidiaries of NEG, Inc. "Net Debt Proceeds" shall mean, with respect to any incurrence of ----------------- Indebtedness for borrowed money, the cash proceeds received by any Person (net of any tax, underwriting discounts and commissions and reasonable costs paid by such Person associated therewith) from the respective incurrence of such Indebtedness for borrowed money. "Net Equity Proceeds" shall mean, with respect to each issuance or ------------------- sale of any equity by any Person or any capital contribution to such Person, the cash proceeds received by any Person (net of any tax, underwriting discounts and commissions and reasonable costs paid by such Person associated therewith) from the respective sale or issuance of its equity or from the respective capital contribution. "Net Insurance Proceeds" shall mean, with respect to any Recovery ---------------------- Event, the cash proceeds received by any Person (net of reasonable costs and taxes paid by such Person associated therewith) in connection with such Recovery Event. "Net IPO Proceeds" shall mean, with respect to the IPO, the cash ---------------- proceeds received by the respective Person from such IPO (net of underwriting discounts and commissions and other reasonable costs paid by such Person associated therewith). "Net Sale Proceeds" shall mean, for any Asset Sale, the gross cash ----------------- proceeds (including any cash received by way of deferred payment pursuant to a promissory note, receivable or otherwise, but only as and when received) received by any Person from such sale of assets (net of the fees and commissions and other reasonable costs paid by such Person associated therewith) relating to the assets sold. "Note" shall have the meaning provided in Section 2.4 of the Credit ---- Agreement. "Notice of Borrowing" shall have the meaning provided in Section 2.2 ------------------- of the Credit Agreement. "Obligations" shall mean, collectively, (i) all loans, advances, ----------- debts, liabilities, and obligations, howsoever arising, owed by the Borrower under a Financing Document or otherwise to the Administrative Agent or any Lender of every kind and description (whether or not evidenced by any note or instrument and whether or not for the payment of money), direct or Appendix A Page 13 indirect, absolute or contingent, due or to become due, now existing or hereafter arising, including all interest, fees, charges, expenses, attorneys' fees and consultants' fees chargeable to the Borrower; (ii) any and all sums advanced by the Collateral Agent, the Administrative Agent or any Lender in order to preserve the Collateral; and (iii) the reasonable expenses of retaking, holding, preparing for sale or lease, selling or otherwise disposing of or realizing on the Collateral, or of any exercise by the Collateral Agent, the Administrative Agent or any Lender of its rights under the Security Documents, together with reasonable attorneys' fees and court costs. "Officer's Certificate" shall mean an officer's certificate signed by --------------------- an Authorized Officer of the Borrower. "Option" shall have the meaning provided in the Option Agreement. ------ "Option Agreement" shall mean the Option Agreement dated as of March ---------------- 1, 2001 among LLC, NEG, Inc., GPSF-F Inc., a Delaware corporation and LB I Group Inc., a Delaware corporation. "Option Shares" shall have the meaning provided in the Option ------------- Agreement. "Payment Office" shall mean the office specified from time to time by -------------- the Administrative Agent as its payment office by notices to the Borrower and the Lenders. "PBGC" shall mean the Pension Benefit Guaranty Corporation established ---- pursuant to Section 4002 of ERISA, or any successor thereto. "Permitted Lien" shall have the meaning provided in Section 7.1 of the -------------- Credit Agreement. "Person" shall mean any individual, corporation, limited liability ------ company, company, voluntary association, partnership, joint venture, trust, or other enterprises or unincorporated organization or government (or any agency, instrumentality or political subdivision thereof). "PGE Utility" shall mean Pacific Gas and Electric Company, a ----------- California corporation. "Plan" shall mean any pension plan as defined in Section 3(2) of ---- ERISA, which is maintained or contributed to by (or to which there is an obligation to contribute of) the Borrower or a Subsidiary of the Borrower or an ERISA Affiliate, and each such plan for the five-year period immediately following the latest date on which the Borrower, or a Subsidiary of the Borrower or an Affiliate maintained, contributed to or had an obligation to contribute to such plan. "Pledged Interest" shall mean the Limited Liability Company Interests ---------------- pledged under the LLC Pledge Agreement. "Preferential Rights" shall have the meaning provided in Section ------------------- 5.4(b) of the Credit Agreement. Appendix A Page 14 "Prime Rate" shall mean the per annum rate of interest established ---------- from time to time by Bankers Trust Company as its prime rate, which rate may not be the lowest rate of interest charged by Bankers Trust Company to its customers. "Process Agent" shall have the meaning provided in Section 9.16(b) of ------------- the Credit Agreement. "Property" shall mean any property or asset of any kind whatsoever, -------- whether real, personal or mixed and whether tangible or intangible, and any right or interest therein. "PUHCA" shall mean the Public Utility Holding Company Act of 1935, as ----- amended, and rules and regulations promulgated thereunder. "QF" shall mean a "qualifying cogeneration facility" or a "qualifying -- small power production facility" as defined under the Public Utility Regulatory Policies Act of 1978, as amended. "Quarterly Dates" shall mean the last Business Day of each of March, --------------- June, September and December. "Real Estate" shall mean, with respect to any Person, all real estate ----------- assets, real property interests, including all easements, rights of way, feehold interests, leasehold interests and any options with respect to any of the foregoing, owned by such Person. "Recovery Event" shall mean the receipt by any Person of any cash -------------- insurance proceeds or condemnation awards payable (i) by reason of theft, loss, physical destruction, damage, taking or any other similar event with respect to any Property or assets of such Person or (ii) under any policy of insurance, except in the case of the Borrower, excluding such proceeds or awards attributable to PGE Utility or any Subsidiary of PGE Utility. "Refinance" or "Refinancing" shall mean the refinancing of the --------- ----------- Indebtedness of the Borrower as set forth on Part A of the Disclosure Letter in accordance with the requirements of Section 4.1(s) of the Credit Agreement. "Register" shall have the meaning provided in Section 9.11(e) of the -------- Credit Agreement. "Regulation D" shall mean Regulation D of the Board of Governors of ------------ the Federal Reserve system (or any successor). "Regulation U" shall mean Regulation U of the Board of Governors of ------------ the Federal Reserve system (or any successor). "Regulation X" shall mean Regulation X of the Board of Governors of ------------ the Federal Reserve system (or any successor). Appendix A Page 15 "Release" shall mean any spilling, leaking, pumping, pouring, ------- emitting, emptying, discharging, injecting, escaping, leaching, dumping, or disposing into the environment (including the abandonment or discarding of barrels, containers, and other closed receptacles containing any Hazardous Material, but excluding (i) emissions from the engine exhaust of a motor vehicle and (ii) the normal application of fertilizer). "Reportable Event" shall mean an event described in Section 4043(c) of ---------------- ERISA with respect to a Plan that is subject to Title IV of ERISA other than those events as to which the 30-day notice period is waived under subsection .22, .23, .25, .27 or .28 of PBGC Regulation Section 4043. "Required Acceleration Lenders" shall mean, at any time, the holders ----------------------------- of at least 66 2/3% in principal amount of the Loans then outstanding. "Required FMV Ratio" shall have the meaning provided in Section 6.14 ------------------ of the Credit Agreement. "Required Waiver Lenders" shall mean, at any time, at least two ----------------------- Lenders which (a) are not Affiliates of each other and (b) together hold, in the aggregate, more than 66 2/3% in principal amount of the Loans then outstanding. "Reserve Requirement" shall mean, at any time, the maximum rate at ------------------- which reserves (including, without limitation, any marginal, special, supplemental, or emergency reserves) are required to be maintained under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) by member banks of the Federal Reserve System against "Eurocurrency liabilities" (as such term is used in Regulation D). Without limiting the effect of the foregoing, the Reserve Requirement shall reflect any other reserves required to be maintained by such member banks with respect to (i) any category of liabilities which includes deposits by reference to which the Eurodollar Rate is to be determined, or (ii) any category of extensions of credit or other assets which include Eurodollar Loans. The Eurodollar Rate shall be adjusted automatically on and as of the effective date of any change in the Reserve Requirement. "Return" shall have the meaning provided in Section 5.12 of the Credit ------ Agreement. "Scheduled Project" shall have the meaning provided in Section 5.23 of ----------------- the Credit Agreement. "SEC" shall mean the Securities and Exchange Commission. --- "SEC Filings" shall mean the filings listed on Schedule 4.1(k). ----------- "Securities Act" shall mean the Securities Act of 1933, as amended, -------------- and the rules and regulations promulgated by the SEC thereunder. "Security Documents" shall mean, collectively, the LLC Pledge ------------------ Agreement, the Stock Pledge Agreement and all Uniform Commercial Code financing statements and other Appendix A Page 16 filings, recordings or regulations required by the Credit Agreement or the LLC Pledge Agreement or the Stock Pledge Agreement to be filed or made in respect of any such Security Document. "Selected Interest Amount" shall have the meaning provided in Section ------------------------ 2.6(b). "Selected Interest Period" shall have the meaning provided in Section ------------------------ 2.6(b). "Significant Subsidiaries" shall mean any of PG&E Gas Transmission, ------------------------ Northwest Corporation, a California corporation, PG&E Energy Trading Holdings Corporation, a California corporation, PG&E Generating Company, LLC, a Delaware limited liability company and USGen New England, Inc., a Delaware corporation. "Source" of a Lender shall mean the source from which such Lender is ------ obtaining funds in connection with the funding or maintenance of its Eurodollar Loan. "Specified Rated Indebtedness" shall mean any long-term unsecured ---------------------------- Indebtedness for borrowed money which (a) has a credit rating of no less than BBB- by Standard & Poor's or Baa3 by Moody's, and (b) a maturity date no earlier than the Date Certain and (c) such Indebtedness may not be accelerated or prepaid prior to a repayment and satisfaction in full of all Obligations of the Borrower under the Credit Agreement and the other Financing Documents. "Specified Subsidiaries" shall mean any of GTN Holdings LLC, a ---------------------- Delaware limited liability company and PG&E Energy Trading Holdings, LLC, a Delaware limited liability company. "Spin-Off" of NEG, Inc. shall mean a spin-off, divestiture, -------- reorganization or other form of restructuring that results in NEG, Inc. no longer being a Subsidiary of LLC or the Borrower. "Standard & Poor's" shall mean Standard & Poor's Ratings Services, a ----------------- division of The McGraw-Hill Companies, Inc. "Stock Pledge Agreement" shall mean the Stock Pledge Agreement dated ---------------------- as of March 1, 2001, among the Borrower, the Lenders party thereto and Bankers Trust Company, as pledgee, as Collateral Agent for the Lenders, as amended, modified or supplemented from time to time. "Subsidiary" shall mean, for any Person, any corporation, partnership ---------- or other entity of which at least a majority of the securities or other ownership interests having by the terms thereof ordinary voting power to elect a majority of the board of directors or other persons performing similar functions of such corporation, partnership or other entity (irrespective of whether or not at the time securities or other ownership interests of any other class or classes of such corporation, partnership or other entity shall have or might have voting power by reason of the happening of any contingency) is at the time directly or indirectly owned or controlled by such Person or one or more Subsidiaries of such Person or by such Person and one or more Subsidiaries of such Person. Appendix A Page 17 "Tax" shall have the meaning provided in Section 3.4 of the Credit --- Agreement. "Trading Contracts" shall mean the agreements identified as such on ----------------- Part A of the Disclosure Letter. "Trading Counterparties" shall mean parties to the Trading Contracts ---------------------- identified as such on Part B of the Disclosure Letter. "Tranche A Commitment" shall mean $600,000,000. -------------------- "Tranche A Lender" shall mean General Electric Capital Corporation, a ---------------- New York corporation. "Tranche A Loan" shall mean the Loan provided by the Tranche A Lender -------------- on the Closing Date. "Tranche B Commitment" shall mean $400,000,000. -------------------- "Tranche B Lender" shall mean Lehman Commercial Paper Inc., a New York ---------------- corporation. "Tranche B Loan" shall mean the Loan provided by the Tranche B Lender -------------- on the Closing Date. "Type" shall mean the type of Loan determined with regard to the ---- interest option applicable thereto, i.e., whether a Base Rate Loan or a Eurodollar Loan. "U.S. GAAP" shall mean generally accepted accounting principles and --------- practices as in effect from time to time in the United States. "Unaudited Financial Statements" shall have the meaning provided in ------------------------------ Section 5.11 of the Credit Agreement. "Unfunded Current Liability" of any Plan shall mean the amount, if -------------------------- any, by which the value of the accumulated plan benefits under the Plan determined on a plan termination basis in accordance with actuarial assumptions at such time consistent with those prescribed by the PBGC for purposes of Section 4044 of ERISA, exceeds the fair market value of all plan assets allocable to such liabilities under Title IV of ERISA (excluding any accrued but unpaid contributions). "United States" and "U.S." shall each mean the United States of ------------- ---- America. "Utility Event" shall mean any event, fact or circumstance which ------------- relates solely to and affects solely PGE Utility (including any voluntary filing for bankruptcy or dissolution concerning PGE Utility or its Subsidiaries under the Bankruptcy Code). "Utility Regulation" means any law, regulation or rule of the Federal ------------------ government, any state, or any agency or political subdivision of the foregoing which is applicable to an entity Appendix A Page 18 by virtue of (i) such entity's ownership or operation of assets used for the generation, transmission, distribution or sale of electric energy, (ii) such entity's transportation of natural or manufactured gas, gasoline, oil, or similar fuels, steam, chilled water or other products resulting in regulation similar to that imposed on the foregoing, (iii) such entity's engaging in the sale or provision of electric energy, natural gas or similar fuels, steam, water, chilled water, or telephone or other public utility services; provided -------- that, such term shall not include laws, regulations or rules of general applicability with respect to protection of the environment, hazardous waste, or public health or safety. "Voting Stock", with respect to any Person, shall mean Capital Stock ------------ the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors (or persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of a contingency. 2. Rules of Interpretation. In each Financing Document, unless ----------------------- otherwise indicated: (a) each reference to, and the definition of, any document (including any Financing Document) shall be deemed to refer to such document as it may be amended, supplemented, revised or modified from time to time in accordance with its terms and, to the extent applicable, the terms of the Credit Agreement; (b) each reference to a Law or Governmental Approval shall be deemed to refer to such Law or Governmental Approval as the same may be amended, supplemented or otherwise modified from time to time; (c) any reference to a Person in any capacity includes a reference to its permitted successors and assigns in such capacity and, in the case of any Governmental Authority, any Person succeeding to any of its functions and capacities; (d) references to days shall refer to calendar days unless Business Days are specified; references to weeks, months or years shall be to calendar weeks, months or years, respectively; (e) all references to a "Section," "Appendix," "Annex," "Schedule" or "Exhibit" are to a Section of such Financing Document or to an Appendix, Annex, Schedule or Exhibit attached thereto; (f) the table of contents and Section headings and other captions therein are for the purpose of reference only and do not affect the interpretation of such Financing Document; (g) defined terms in the singular shall include the plural and vice versa, and the masculine, feminine or neuter gender shall include all genders; Appendix A Page 19 (h) the words "hereof", "herein" and "hereunder", and words of similar import, when used in any Financing Document, shall refer to such Financing Document as a whole and not to any particular provision of such Financing Document; (i) the words "include," "includes" and "including" are deemed to be followed by the phrase "without limitation"; (j) where the terms of any Financing Document require that the approval, opinion, consent or other input of any Secured Party be obtained, such requirement shall be deemed satisfied only where the requisite approval, opinion, consent or other input is given by or on behalf of the relevant party in writing; (k) where the terms of any Financing Document require or permit any action to be taken by the Collateral Agent, such action shall be taken strictly in accordance with the applicable provisions of the relevant Financing Documents; (l) whenever the phrase "material compliance" is used, it shall be interpreted to mean that either the entity is in full compliance with the requirement or that any failure of the entity to be in compliance in all respects with the requirement could not reasonably be expected alone or together will all other such failures and all of the facts and circumstances to have a Material Adverse Effect; and (m) all reference to "knowledge" of a Person shall mean the knowledge or actual awareness of such Person of the subject matter in question after due inquiry and investigation and "knowledge" of the Borrower shall mean and include knowledge of the other Covered Parties. EXHIBIT A --------- FORM OF NOTICE OF BORROWING [DATE] [Address of Administrative Agent/Lender] -------------------------------------- Attention: __________________________ Gentlemen: The undersigned, PG&E Corporation, refers to the Credit Agreement, dated as of March __, 2001 (as amended from time to time, the "Credit Agreement," the terms defined therein being used herein as therein defined), among the undersigned, the Lenders, [and you, as Administrative Agent for the Lenders,] and hereby gives you notice, irrevocably, pursuant to Section 2.2 of the Credit Agreement, that the undersigned hereby requests a Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowing (the "Proposed Borrowing") as required by Section 2.2 of the Credit Agreement: (i) The Business Day of the Proposed Borrowing is March __, 2001. (ii) The aggregate principal amount of the Proposed Borrowing is [________]. (iii) The Proposed Borrowing is to consist of a Eurodollar Loan. (iv) The initial Interest Period for the Proposed Borrowing is [_________]. The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing: (A) the representations and warranties contained in Section 5 of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing and to the application of the proceeds thereof, as though made on and as of such date; and (B) no Default or Event of Default has occurred and is continuing, or would result from such Proposed Borrowing or from the application of the proceeds thereof. Very truly yours, PG&E Corporation By_____________________________ Title: EXHIBIT B --------- FORM OF NOTE THIS NOTE MAY NOT BE ASSIGNED EXCEPT IN ACCORDANCE WITH SECTION 9.11 OF THE CREDIT AGREEMENT $ _____________ New York, New York March __, 2001 FOR VALUE RECEIVED, PG&E CORPORATION, a corporation organized and existing under the laws of California (the "Borrower"), hereby promises to pay to the order of [_____________________] (the "Lender") or its registered assigns, in lawful money of the United States of America in immediately available funds, at the Payment Office (as defined in the Agreement described below) on the earlier of (a) the date of a Spin-Off of NEG, Inc. and (b) the Date Certain, the principal sum of __________________ United States dollars or, if less, the unpaid principal amount of all Loans (as defined in the Agreement) made by the Lender pursuant to the Agreement. The Borrower promises also to pay interest on the unpaid principal amount of the Loans in like money at said office from the date such Loans are made until paid at the rates and at the times provided in the Agreement. This Note is one of the Notes referred to in the Credit Agreement, dated as of March [__], 2001, among the Borrower, the Lenders party thereto, General Electric Capital Corporation, as Co-Arranger, Lehman Commercial Paper Inc., as Administrative Agent and Lehman Brothers Inc., as Lead Arranger and Book Manager (as amended and as from time to time in effect, the "Agreement") and is entitled to the benefits thereof. Capitalized terms used herein and not defined shall have the meanings set forth in Appendix A to the Agreement. This Note is secured by the Security Documents (as defined in the Agreement). As provided in the Agreement, this Note is subject to voluntary and mandatory prepayment, in whole or in part. In case an Event of Default (as defined in the Agreement) shall occur and be continuing, the principal of and accrued interest on this Note may be declared to be due and payable in the manner and with the effect provided in the Agreement. The Borrower hereby waives presentment, demand, protest or notice of any kind in connection with this Note. THIS NOTE SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAW OF THE STATE OF NEW YORK. PG&E Corporation By_____________________________ Name: Title: (ii) EXHIBIT C --------- Section 3.4(b)(ii) Certificate ------------------------------ Reference is hereby made to the Credit Agreement, dated as of March 1, 2001, among PG&E Corporation, a California corporation, as the Borrower, General Electric Capital Corporation, a New York corporation, as a Lender and Co- Arranger, Lehman Commercial Paper Inc., as a Lender and Administrative Agent and Lehman Brothers Inc., as Lead Arranger and Book Manager (the "Credit Agreement"). Pursuant to the provisions of Section 3.4(b)(ii) of the Credit Agreement, the undersigned hereby certifies that it is not a "bank" as such term is used in Section 881(c)(3)(A) of the Internal Revenue Code of 1986, as amended. [NAME OF LENDER] By__________________________________ Name: Title: EXHIBIT D --------- CT CORPORATION SYSTEM March 1, 2001 PG&E Corporation One Market Spear Street Tower, Suite 2400 San Francisco, CA 94105 Attention: Vice President and Corporate Secretary PG&E National Energy Group, LLC One Market Spear Street Tower, Suite 2400 San Francisco, CA 94105 Attention: Secretary PG&E National Energy Group, Inc. One Market Spear Street Tower, Suite 2400 San Francisco, CA 94105 Attention: Secretary General Electric Capital Corporation 120 Long Ridge Road Stamford, CT 06927 Lehman Commercial Paper Inc. Three World Financial Center 200 Vesey Street New York, NY 10285 Lehman Brothers Inc. Three World Financial Center 200 Vesey Street New York, NY 10285 Ladies and Gentlemen: Reference is made to the Credit Agreement, dated as of March 1, 2001 (the "Credit Agreement"), among PG&E Corporation, a California ("PG&E Corp."), General Electric Capital Corporation, Lehman Commercial Paper Inc. and Lehman Brothers Inc. Unless otherwise defined herein, terms defined in the Credit Agreement are used herein as therein defined. Pursuant to Section 9.16(b) of the Credit Agreement and the other Financing Documents, PG&E Corp., PG&E National Energy Group, LLC and PG&E National Energy Group, Inc. have appointed CT Corporation System (with an office on the date hereof at 111 Eighth Avenue, New York, New York 10011, U.S.A.) as their agent in their name, place and stead to accept process on their behalf of all writs, process and summonses in any action, suit or proceeding brought in the State of New York arising out of or relating to the Credit Agreement, any other Financing Documents or the transactions contemplated thereby. 1350 Treat Boulevard, Suite 100 Walnut Creek, CA 94596 Tel. 800 874 5258 Fax 925 287 9801 A CCH LEGAL INFORMATION SERVICES COMPANY CT CORPORATION SYSTEM The undersigned hereby accepts each such appointment as agent and agrees with you that (a) the undersigned will maintain an office in New York City until such time as a successor agent shall be appointed by irrevocable powers of attorney in form and substance acceptable to you and your counsel, and such successor agent shall have delivered a letter to you accepting its appointment, (b) the undersigned will perform its duties as agent in accordance with the Credit Agreement and this letter, and (c) the undersigned will forward forthwith copies of any writs, process or summonses which the undersigned receives in connection with its appointment as agent to PG&E Corp., PG&E National Energy Group, LLC and PG&E National Energy Group, Inc. at the following addresses (or at such other address of which PG&E Corp., PG&E National Energy Group, LLC and PG&E National Energy Group, Inc. shall hereafter notify us): PG&E Corporation One Market Spear Street Tower, Suite 2400 San Francisco, CA 94105 Attention: Leslie H. Everett, Vice President and Corporate Secretary Fax: (415) 267-7260 Phone: (415) 267-7010 PG&E National Energy Group, LLC One Market Spear Street Tower, Suite 2400 San Francisco, CA 94105 Attention: Leslie H. Everett, Secretary Fax: (415) 267-7260 Phone: (415) 267-7010 PG&E National Energy Group, Inc. One Market Spear Street Tower, Suite 2400 San Francisco, CA 94105 Attention: Leslie H. Everett, Secretary Fax: (415) 267-7260 Phone: (415) 267-7010 This acceptance and agreement shall be binding upon the undersigned and all successors of the undersigned. Very truly yours, CT CORPORATION SYSTEM By: /s/ Naseem A. Conde ------------------------------- Name: Naseem A. Conde Title: Special Asst. Secy. 1350 Treat Boulevard, Suite 100 Walnut Creek, CA 94596 Tel. 800 874 5258 Fax 925 287 9801 EX-10.6 8 dex106.txt LETTER REGARDING COMP. AGREEMENT - T. KING EXHIBIT 10.6 November 4, 1998 Mr. Thomas B. King Dear Tom: On behalf of PG&E Corporation, I am pleased to extend an invitation to you to join our organization as President and COO - PG&E Gas Transmission and Sr. Vice President PG&E Corporation, reporting to me. We are unanimous in our view that you are the right candidate for this position. As we discussed, this position would be physically located in our Houston office. Below are the details of the compensation and benefit aspects of this offer. It you have any questions on compensation, please contact Brent Stanley at (415) 267-7136. Your initial and 1999 target annual cash compensation is calculated to be approximately $540,500. You will also receive a one-time signing bonus of $200,000. In addition, you will participate in several short and long term incentive plans and other plans, also described below. 1. An annual base salary of $350,000 ($29,167 monthly) subject to possible increases through our annual salary review plan. 2. One-time bonus of $200,000 payable within 30 days of your hire, subject to normal payroll withholdings, Should you decide to leave PG&E Corporation within one year of your start date, a prorated amount of this bonus must be refunded to the company. 3. A target annual bonus of $175,000, which equals 50% of your base salary, in an annual incentive plan under which your actual bonus dollars can reach from 0 to $350,000 based on your performance relative to established goals. 4. An award of 10,000 performance units under our Performance Units Plan (PUP), effective in December 1998. The value of these units is tied to the price of PG&E Corporation common stock. The estimated target value of this award is $333,000 based on a value of $33.00 per share. In addition, you will be awarded 11,000 performance units under the plan in January 1999 with an estimated target value of $363,000 based on a value of $33.00 per share. 5. Providing you meet general business goals for 1999 and 2000, the Corporation will credit to your deferred compensation account, an amount equal to $2,000,000 payable in two equal annual installments on January 1, 2000 and January 1, 2001. Should you terminate prior to the payment of an installment, that installment as well as any remaining installment will be forfeited. The credited funds will be allocated to the PG&E Phantom Stock Fund. Payment of credited funds will occur in accordance with your selected payout option. 6. A stock option grant of 50,000 shares of PG&E Corporation common stock. In addition, you will be granted an additional 100,000 stock options effective the first business day of 1999. The 50,000 options will be in effect and priced as of the day you are elected by the Board of Directors to your new position. The remaining 100,000 options will be effective and priced on the first business day of 1999. 7. An annual perquisite allowance of $15,500. 8. Participation in our health and welfare benefit plans. 9. 4 weeks of paid vacation per year. 10. Executive relocation assistance package. As we have discussed, a number of these compensation elements, as well as election as an officer of PG&E Corporation, are subject to Board of Directors approval. Tom, I believe this position is a unique career opportunity. PG&E Corporation has the vision, the team, the resources, and the plan to be the premier energy company in America. We have the opportunity for great success and we all would like you on our team. I am interested in having you on board as soon as possible. We can mutually agree on a start date, which I hope would be no later than December first. Brent Stanley will be most helpful to you on any details of this offer, however, I am ready and willing to discuss any aspect of it with you. Sincerely ROBERT D. GLYNN, JR. Chairman, Chief Executive Officer and President Accepted: THOMAS B. KING - ------------------------- November 4, 1998 - ------------------------- Date EX-10.7 9 dex107.txt LETTER REGARDING COMP. AGREEMENT - L. MADDOX EXHIBIT 10.7 April 25, 1997 Mr. Lyn Maddox Dear Lyn: On behalf of PG&E Corporation, I am pleased to modify our previous offer for you to join our organization as President and Chief Executive Officer of PG&E Energy Trading and as Senior Vice President of PG&E Corporation reporting to me. It is my understanding that these details are consistent with those described to you by G. Brent Stanley and will form the basis for your acceptance of this offer. Your initial target annual total compensation plus a one-time signing bonus of $50,000 is calculated to be approximately $935,000. Listed below are compensation and benefit details: 1. An annual base salary of $300,000 ($25,000 monthly) subject to possible increases through our merit review plan. 2. One time bonus of $50,000 payable within 30 days of your hire, subject to normal payroll withholdings. 3. A target annual bonus of $135,000, which equals 45% of your base salary, in an annual incentive plan under which your actual bonus dollars can reach from 0 to $270,000 based on your performance relative to established goals. For 1997, this bonus will be not less than $135,000. 4. Annual award of 5,000 performance units under our Performance Units Plan (PUP). The value of these units is tied to the price of PG&E Corporation common stock. The estimated value of this award is $100,000 based on a value of $20 per share. 5. A stock option grant of 120,000 shares of PG&E Corporation common stock. The estimated value of this award is $333,600 based on a present value $2.78 per share. 6. An annual perquisite allowance of $15,500. 7. Participation in our health and welfare benefit plans. 8. Four weeks of paid vacation per year. As we have discussed, a number of these compensation elements, as well as election as an officer of PG&E Corporation, are subject to Board of Directors approval. We are enthused that you are planning to join our team and working with us for the success of PG&E Corporation. I would appreciate receiving your written acceptance of this offer as soon as possible. Please call me at the office or at home (510) 933-9369 at any time. Sincerely, ROBERT D. GLYNN, JR. Accepted: L E MADDOX - -------------------- 4/26/97 - -------------------- Date EX-10.9 10 dex109.txt DESCRIPTION OF RELOCATION ARRANGEMENT - L. MADDOX EXHIBIT 10.9 Description of Relocation Plan Between PG&E Corporation and Lyn E. Maddox Position: Senior Vice President of PG&E Corporation and President and COO - PG&E Energy Trading effective August 16, 2000. 1. A moving allowance equal to one month's pay. 2. Reimbursement for travel expenses incurred in finding a principal residence, without a limitation on the number of trips required. Mr. Maddox will be reimbursed for the reasonable cost of temporary housing, which, subject to the prior approval of the CEO of PG&E Corporation, can be extended beyond the period provided under the plan. 3. Reimbursement of all closing costs incurred in the sale of Mr. Maddox's existing residence and the purchase of a new residence. The relocation plan also will indemnify him for any loss that he may suffer on the sale of his existing residence. 4. The plan will provide for the reimbursement of any tuition loss which Mr. Maddox incurs as a result of his children changing schools, including enrollment and application fees, testing, and school travel costs incurred in placing his children in comparable schools in the Bethesda area. 5. Mr. Maddox will be provided with a temporary mortgage buy-down of $3,500 per month, payable for four years, commencing with the first mortgage payment for his new residence. Should he voluntarily resign from employment with PG&E Corporation or one of its subsidiaries or affiliates prior to December 31, 2004, he will be required to repay all amounts provided to him under the temporary mortgage buy-down. Mr. Maddox's target bonus is 50 percent of his base pay of $400,000 with a potential bonus of 100 percent. In addition to continuation of his current compensation and benefit package, and in recognition of the additional expenses associated with his relocation at PG&E Corporation's request to Bethesda, he also will receive a one-time payment of $250,000, net of taxes, and a one-time taxable payment of $75,000. Should he voluntarily resign from his position and no longer be employed by PG&E Corporation or one of its subsidiaries or affiliates prior to December 31, 2004, he will be required to repay the gross amount of these payments. Inasmuch as these payments are considered to be additional compensation, payment is conditioned on approval by PG&E Corporation's Nominating and Compensation Committee. EX-10.10 11 dex1010.txt PG&E SEO RETENTION PROGRAM EXHIBIT 10.10 PG&E Corporation Nominating and Compensation Committee February 21, 2001 SENIOR EXECUTIVE RETENTION -------------------------- Action Recommended - ------------------ It is recommended that the Nominating and Compensation Committee approve Special Senior Executive Retention Grants as a mechanism to retain a small group of key executive officers. The concept is outlined below. Specific individual recommendations will be presented for the Committee's approval at its meeting on December 20, 2000. Background - ---------- We have built a very strong senior executive team. Many of our key executives are very attractive candidates for senior positions in other companies. Our goal is to retain individuals who are sought after to be CEOs or senior officers in other companies that may have more attractive growth prospects. Our ability to retain these key individuals is critical to our success. We must provide a retention mechanism to make them less vulnerable to leaving by providing them with a strong incentive to stay. The eligible group excludes any key executives from the National Energy Group (NEG) who might otherwise be eligible were it not for the Corporation's plan to take that entity public in the near future. The concept is a multi-year, cliff-vesting incentive award of phantom PG&E Corporation restricted stock units. Description - ----------- The phantom restricted stock units will provide an incentive equal three times an eligible officer's base salary plus target short-term incentive award. Grants will be made effective January 1, 2001, and will vest on December 31, 2004 subject to either one of the following conditions: - - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. Eligible executives may elect to defer award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock, or half in PG&E Corporation stock and half in cash in January of the year following vesting. Key Administrative Provisions - ----------------------------- The following provisions will apply to the early termination of an eligible officer: - -------------------------------------------------------------------------------- Circumstance Award Status - -------------------------------------------------------------------------------- Death or disability Fully vested - -------------------------------------------------------------------------------- Change in control Fully vested - -------------------------------------------------------------------------------- Voluntary termination Forfeited - -------------------------------------------------------------------------------- Termination for cause Forfeited - -------------------------------------------------------------------------------- Involuntary termination (severed) Full or prorated vesting at the discretion of the PG&E Corporation CEO or at the discretion of the Committee in the case of the PG&E Corporation CEO - -------------------------------------------------------------------------------- Retirement Forfeited subject to full or prorated vesting at the discretion of the PG&E Corporation CEO or at the discretion of the Committee in the case of the PG&E Corporation CEO - -------------------------------------------------------------------------------- Estimated Costs - --------------- The cost of the grants will depend on the specific amounts granted and the actual stock price over the four-year period. The estimated four-year cost could range up to $15 million assuming a full payment at the current stock price. This cost will change over the four-year period with changes in the stock price. 2 PG&E Corporation Nominating and Compensation Committee February 21, 2001 SENIOR EXECUTIVE RETENTION -------------------------- Action Recommended - ------------------ It is recommended that the Nominating and Compensation Committee expand the eligible officer population covered by the Senior Executive Retention program to include additional officers of Pacific Gas and Electric Company as well as several key officers of PG&E National Energy Group. Specific individual recommendations will be presented for the Committee's approval at its meeting on February 21, 2001. Background - ---------- On December 20, 2000, the Nominating and Compensation Committee approved the Senior Executive Retention program as a mechanism to retain a small group of key executive officers. The aim of the program is to provide certain key officers, who are critical to our success and sought after by other companies, with a retention mechanism to make them less vulnerable to leaving, by providing them with a strong incentive to stay. The number of shares needed to accommodate the addition of these officers to the program will exceed the current number of authorized shares available under the PG&E Corporation Long-Term Incentive Plan by approximately 700,000 shares. Therefore, award payments under the program, if not deferred, will be paid entirely in cash rather than half in cash and half in stock as provided for under the program approved by the Committee at its meeting on December 20, 2000. A general description of the program is attached (Attachment A). ATTACHMENT A ------------ SENIOR EXECUTIVE RETENTION PROGRAM ---------------------------------- The concept is a multi-year, cliff-vesting incentive award of phantom PG&E Corporation restricted stock units. Description - ----------- The incentive award will take the form of phantom restricted stock units to be granted effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004, only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. Eligible executives may elect to defer award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. Key Administrative Provisions - ----------------------------- The following provisions will apply to the early termination of an eligible officer: - -------------------------------------------------------------------------------- Circumstance Award Status - -------------------------------------------------------------------------------- Death or disability Fully vested - -------------------------------------------------------------------------------- Change in control Fully vested - -------------------------------------------------------------------------------- Voluntary termination Forfeited - -------------------------------------------------------------------------------- Termination for cause Forfeited - -------------------------------------------------------------------------------- Involuntary termination (severed) Full or prorated vesting at the discretion of the PG&E Corporation CEO or at the discretion of the Committee in the case of the PG&E Corporation CEO - -------------------------------------------------------------------------------- Retirement Forfeited subject to full or prorated vesting at the discretion of the PG&E Corporation CEO or at the discretion of the Committee in the case of the PG&E Corporation CEO - -------------------------------------------------------------------------------- EX-10.10.1 12 dex10101.txt LETTER REGARDING RETENTION AWARD - R. D. GLYNN EXHIBIT 10.10.1 January 22, 2001 Mr. Robert D. Glynn, Jr., Chairman CEO and President PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Dear Bob: As you know, the Board of Directors recently approved a Senior Executive Retention program for a small group of key senior officers. You are included in that group. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $6,000,000 and it translates into 615,385 units calculated at the closing price of PG&E Corporation common stock on January 22, 2001, of $9.75 per share. Your grant of phantom PG&E Corporation restricted stock units is effective January 22, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock or half in PG&E Corporation stock and half in cash in January of the year following vesting. Sincerely, BRENT G. STANLEY EX-10.10.2 13 dex10102.txt LETTER REGARDING RETENTION AWARD - G. SMITH EXHIBIT 10.10.2 January 22, 2001 Mr. Gordon R. Smith, President and CEO Pacific Gas and Electric Company 77 Beale Street, M.C. B32 San Francisco, CA 94102 Dear Gordon: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $3,500,000 and it translates into 358,975 units calculated at the closing price of PG&E Corporation common stock on January 22, 2001, of $9.75 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me or Brent Stanley. Your grant of phantom PG&E Corporation restricted stock units is effective January 22, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock or half in PG&E Corporation stock and half in cash in January of the year following vesting. Gordon, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.3 14 dex10103.txt LETTER REGARDING RETENTION AWARD - P. DARBEE EXHIBIT 10.10.3 January 22, 2001 Mr. Peter A. Darbee, Sr. VP and CFO PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Dear Peter: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $2,250,000 and it translates into 230,770 units calculated at the closing price of PG&E Corporation common stock on January 22, 2001, of $9.75 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me or Brent Stanley. Your grant of phantom PG&E Corporation restricted stock units is effective January 22, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock or half in PG&E Corporation stock and half in cash in January of the year following vesting. Peter, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.4 15 dex10104.txt LETTER REGARDING RETENTION AWARD - WORTHINGTON EXHIBIT 10.10.4 January 22, 2001 Bruce R. Worthington, Esq. SVP and General Counsel PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Dear Bruce: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 128,205 units calculated at the closing price of PG&E Corporation common stock on January 22, 2001, of $9.75 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me or Brent Stanley. Your grant of phantom PG&E Corporation restricted stock units is effective January 22, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock or half in PG&E Corporation stock and half in cash in January of the year following vesting. Bruce, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.5 16 dex10105.txt LETTER RE: RETENTION AWARD - G. B. STANLEY EXHIBIT 10.10.5 January 22, 2001 Mr. G. Brent Stanley SVP - Human Resources PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Dear Brent: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 128,205 units calculated at the closing price of PG&E Corporation common stock on January 22, 2001, of $9.75 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me. Your grant of phantom PG&E Corporation restricted stock units is effective January 22, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock or half in PG&E Corporation stock and half in cash in January of the year following vesting. Brent, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.6 17 dex10106.txt LETTER RE: RETENTION AWARD - D. D. RICHARD EXHIBIT 10.10.6 January 22, 2001 Mr. Daniel D. Richard Jr. SVP - Public Affairs PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Dear Dan: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 128,205 units calculated at the closing price of PG&E Corporation common stock on January 22, 2001, of $9.75 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me or Brent Stanley. Your grant of phantom PG&E Corporation restricted stock units is effective January 22, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid either entirely in PG&E Corporation stock or half in PG&E Corporation stock and half in cash in January of the year following vesting. Dan, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.7 18 dex10107.txt LETTER RE: RETENTION AWARD - J. K. RANDOLPH EXHIBIT 10.10.7 February 27, 2001 Mr. James K. Randolph, Sr. Vice President Chief of Utility Operations Pacific Gas and Electric Company 77 Beale Street, 32/nd/ Floor San Francisco, CA 94105 Dear Jim: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 95,715 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Gordon Smith. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. Jim, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.8 19 dex10108.txt LETTER RE: RETENTION AWARD - G. M. RUEGER EXHIBIT 10.10.8 February 27, 2001 Mr. Gregory M. Rueger, Sr. Vice President Generation & Chief Nuclear Officer Pacific Gas and Electric Company 77 Beale Street, 32/nd/ Floor San Francisco, CA 94105 Dear Greg: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long- Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 95,715 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Gordon Smith. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. Greg, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.9 20 dex10109.txt LETTER RE: RETENTION AWARD - KENT HARVEY EXHIBIT 10.10.9 February 27, 2001 Mr. Kent Harvey, Sr. Vice President Chief Financial Officer & Treasurer Pacific Gas and Electric Company 77 Beale Street, 32/nd/ Floor San Francisco, CA 94105 Dear Kent: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 95,715 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Gordon Smith. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. Kent, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.10 21 dex101010.txt LETTER RE: RETENTION AWARD - R. J. PETERS EXHIBIT 10.10.10 February 27, 2001 Roger J. Peters, Esq. Senior Vice President and General Counsel Pacific Gas and Electric Company 77 Beale Street, 32/nd/ Floor San Francisco, CA 94105 Dear Roger: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $1,250,000 and it translates into 95,715 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Gordon Smith. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. Roger, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.11 22 dex101011.txt LETTER RE: RETENTION AWARD - T. G. BOREN EXHIBIT 10.10.11 February 27, 2001 Mr. Thomas G. Boren, Executive Vice President President & CEO PG&E National Energy Group One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Dear Tom: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $3,500,000 and it translates into 267,995 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me or Brent Stanley. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be given the opportunity of exchanging your grant of phantom PG&E corporation stock units under this program for an equity-type interest of comparable value in the new entity. Tom, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.12 23 dex101012.txt LETTER RE: RETENTION AWARD- LYN MADDOX EXHIBIT 10.10.12 February 27, 2001 Mr. Lyn E. Maddox, Sr. Vice President President & Chief Operating Officer PG&E National Energy Group - Trading 7500 Old Georgetown Road Bethesda, MD 20814-6161 Dear Lyn: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $2,250,000 and it translates into 172,285 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Tom Boren. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be given the opportunity of exchanging your grant of phantom PG&E corporation stock units under this program for an equity-type interest of comparable value in the new entity. Lyn, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.13 24 dex101013.txt LETTER RE: RETENTION AWARD - P. C. IRIBE EXHIBIT 10.10.13 February 27, 2001 Mr. P. Chrisman Iribe, Sr. Vice President President & Chief Operating Officer PG&E National Energy Group - East Region 7500 Old Georgetown Road, 13/th/ Flr. Bethesda, MD 20814-6161 Dear Chris: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $2,250,000 and it translates into 172,285 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Tom Boren. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be given the opportunity of exchanging your grant of phantom PG&E corporation stock units under this program for an equity-type interest of comparable value in the new entity. Chris, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.10.14 25 dex101014.txt LETTER RE: RETENTION AWARD - T. B. KING EXHIBIT 10.10.14 February 27, 2001 Mr. Thomas B. King, Sr. Vice President President & Chief Operating Officer PG&E National Energy Group - West Region 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 Dear Tom: You are an essential member of our senior executive team and I view your contribution as vital to getting the Corporation through its current challenges, achieving the Corporation's objectives, and providing strong returns to shareholders. The Board of Directors recently approved a Senior Executive Retention program which includes you. Under this program, you will receive a grant of phantom PG&E Corporation restricted stock units granted under the PG&E Corporation Long-Term Incentive Plan. The amount of your grant is $2,250,000 and it translates into 172,285 units calculated at the closing price of PG&E Corporation common stock on February 21, 2001, of $13.06 per share. An extremely small number of individuals are included in this arrangement. For this reason, it is absolutely necessary for you to restrict any conversation on this subject to me, Brent Stanley, or Tom Boren. Your grant of phantom PG&E Corporation restricted stock units is effective February 21, 2001, and will vest on December 31, 2004, subject to either one of the following conditions: - 50 percent will automatically vest on December 31, 2004. The remaining 50 percent will vest on December 31, 2004 only if the Corporation's performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group; or - if, at the end of the third year of the grant, December 31, 2003, the Corporation's performance as measured by relative TSR on a cumulative basis, is at or above the 75th percentile of its comparator group, the entire grant will vest. You may elect to defer your actual award payments under the PG&E Corporation Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting. If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be given the opportunity of exchanging your grant of phantom PG&E corporation stock units under this program for an equity-type interest of comparable value in the new entity. Tom, I look forward to your continued strong contributions to PG&E Corporation's success. Sincerely, ROBERT D. GLYNN, JR. EX-10.11 26 dex1011.txt AGMT BET PG&E CORP. & T. W. HIGH EXHIBIT 10.11 AGREEMENT AND RELEASE This Agreement and Release (hereafter "Agreement") is made and entered into by and between THOMAS W. HIGH and PG&E CORPORATION (hereafter, PG&E Corp.) (collectively referred to as "the parties") and sets forth the terms and conditions of Mr. High's separation from PG&E Corp. 1. Mr. High shall voluntarily resign from his employment with PG&E Corp. and from his position as SVP - Administration and External Relations of PG&E Corp. and as an officer and/or director of any and all subsidiary and affiliate companies of PG&E Corp., effective close of business April 30, 2001. 2. Beginning on May 1, 2001, and until the first of the month following the month in which Mr. High reaches age 55, PG&E Corp. shall pay to Mr. High an annual benefit under the Supplemental Executive Retirement Plan (SERP) of approximately Two Hundred and Ninety Seven Thousand, Two Hundred and Forty Four Dollars ($297,244.00), in equal monthly installments. Thereafter, and for the remainder of his life, PG&E Corp. shall pay Mr. High an annual benefit under the SERP of approximately Two Hundred Thirty Five Thousand, Five Hundred and Forty Six Dollars ($235,546.00), payable in equal monthly installments, which amount shall be in addition to any benefits to which Mr. High is otherwise entitled under the terms of the Retirement Plan for Employees of Pacific Gas and Electric Company. The benefits described in this paragraph are in the form of a single life annuity, and Mr. High shall be entitled to make any elections with respect to survivor benefits, payment options, or such other optional forms of benefits as are provided for in the SERP, consistent with the actuarial factors used by the SERP plan administrator. 3. PG&E Corp. shall provide Mr. High executive career counseling and/or placement services from the firm of Spherion Corporation or, at his selection, another firm providing such services under contract with PG&E Corp. If Mr. High becomes reemployed during the one year following the effective date of this Agreement, PG&E Corp.'s obligation to provide the service specified in this paragraph shall terminate at the time such employment commences. 4. Effective May 1, 2001, all unvested performance unit grants, stock option grants, and special incentive stock ownership premiums provided to Mr. High under PG&E Corporation's Performance Unit Plan, Stock Option Plan, and Executive Stock Ownership Program shall vest under the provisions governing termination by reason of retirement contained in each respective plan or program. The payment, exercise, and withdrawal of Mr. High's vested performance units, stock option grants, and stock ownership premiums shall be as provided under the terms of their respective plans or program. Mr. High shall be considered to be a retired employee for purposes of the Postretirement Life Insurance Plan of Pacific Gas and Electric Company and shall be entitled to make any elections thereunder as provided to retired officers. 5. PG&E Corp. shall provide to Mr. High legal representation and indemnification protection in any legal proceeding in which he is a party or is threatened to be made a party by reason of the fact that he is or was a PG&E Corp. employee or officer, in accordance with the terms of the resolution of the Board of Directors of PG&E Corp. dated December 18, 1996. 6. Except as provided in paragraph 5 of this Agreement, in consideration of the payment and benefits PG&E Corp. is providing under this Agreement, Mr. High on behalf of himself and his representatives, agents, heirs and assigns, waives, releases, discharges and promises never to assert any and all claims, liabilities or obligations of every kind and nature, whether known or unknown, suspected or unsuspected that he ever had, now has or might have as of the effective date of this Agreement against PG&E Corp., its predecessors, subsidiaries, related entities, officers, directors, shareholders, owners, agents, attorneys, employees, successors, or assigns. The released claims include, without limitation, any claims arising from or related to Mr. High's employment with PG&E Corp., his resignation from his position as an officer and/or director of PG&E Corp. or any of its subsidiaries or affiliate companies, the separation of his employment with PG&E Corp., or any of its subsidiaries or affiliate companies, and/or any of the conditions, events, transactions or series of transactions related thereto, and the execution of this Agreement. The released claims also specifically include, without limitation, any claims arising under any federal, state and local statutory or common law, such as Title VII of the Civil Rights Act, the federal Age Discrimination in Employment Act, the California Fair Employment and Housing Act, the Americans With Disabilities Act, the Employee Retirement Income Security Act, the Fair Labor Standards Act, the California Labor Code (all as amended), the law of contract and tort, and any claim for attorneys' fees. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 7. Mr. High acknowledges that there may exist facts or claims in addition to or different from those which are now known or believed by him to exist. Nonetheless, except as provided for in paragraph 5 of this Agreement, Mr. High understands, intends, and agrees that this Agreement extends to all claims of every nature and kind whatsoever, whether known or unknown, suspected or unsuspected, past or present, and he specifically waives all rights under Section 1542 of the California Civil Code which provides that: A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN TO HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 8. Mr. High agrees that he will not initiate, maintain, or accept the benefits from any legal action or proceeding of any kind against PG&E Corp. or any of its predecessors, subsidiaries, related entities, officers, directors, shareholders, owners, agents, attorneys, employees, successors, or assigns as to any matter released in this Agreement, nor shall he assist or participate in any such proceedings, including any proceedings brought by any third parties, except as required by court order or law or to enforce this Agreement. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. -2- 9. Mr. High shall not seek any future re-employment with PG&E Corp. This paragraph does not, however, preclude Mr. High from accepting an offer of future employment from PG&E Corp. 10. Mr. High shall not disclose, publicize, or circulate to anyone in whole or in part, any information concerning the terms and/or conditions of this Agreement without the express written consent of the Chief Legal Officer of PG&E Corp. unless required by court order or law. Notwithstanding the preceding sentence, Mr. High may disclose the terms and conditions of this Agreement to his immediate family members, and any attorneys or tax advisors, if any, to whom there is a bona fide need for disclosure in order for them to render professional services to his, provided that Mr. High first instructs each affected family member, attorney, and tax advisor that he must keep the information confidential and may not make any disclosure of the terms and conditions of this Agreement, unless required by court order or law. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 11. Mr. High agrees not to use, disclose, publicize, or circulate any confidential or proprietary information concerning PG&E Corp., its subsidiaries, or its affiliates, which has come to his attention during his employment with PG&E Corp., unless his doing so is expressly authorized in writing by the Chief Legal Officer of PG&E Corp., or is required by court order or law. Before making any legally-required disclosure, Mr. High shall give PG&E Corp. notice at least ten (10) business days in advance. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 12. Mr. High agrees not to engage in any unfair competition against PG&E Corp. For purposes of this Agreement, unfair competition shall be accorded the definition developed under the laws of the State of California, including section 17200, et seq., of the California Business and Professions Code. Mr. High agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 13. (a) For a period of one year after the effective date of this Agreement as set forth in paragraph 17 below, Mr. High shall not, directly or indirectly, solicit or contact for the purpose of diverting or taking away or attempt to solicit or contact for the purpose of diverting or taking away any prospective customer of PG&E Corp. or its affiliates or subsidiaries about whom he acquired information as a result of any solicitation efforts by PG&E Corp., its subsidiaries, or affiliates, or the prospective customer during his employment with PG&E Corp. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. (b) For a period of one year after the effective date of this Agreement as set forth in paragraph 17 below, Mr. High shall not, directly or indirectly, solicit or contact for the purpose of diverting or taking away or attempt to solicit or contact for the purpose of diverting or taking away any existing customer of PG&E Corp. or its affiliates or subsidiaries. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. (c) For a period of one year after the effective date of this Agreement as set forth in paragraph 17 below, Mr. High shall not, directly or indirectly, solicit or contact for the purpose of -3- diverting or taking away or attempt to solicit or contact for the purpose of diverting or taking away any existing vendor of PG&E Corp. or its affiliates or subsidiaries. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. (d) For a period of one year after the effective date of this Agreement as set forth in paragraph 17 below, Mr. High shall not, directly or indirectly, solicit or contact for the purpose of diverting or taking away or attempt to solicit or contact for the purpose of diverting or taking away any prospective vendor of PG&E Corp. or its affiliates or subsidiaries, about whom he acquired information as a result of any solicitation efforts by PG&E Corp. or its affiliates or subsidiaries or the prospective vendor during his employment with PG&E Corp. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. (e) For a period of one year after the effective date of this Agreement as set forth in paragraph 17 below, Mr. High shall not, directly or indirectly, solicit, contact or induce, or attempt to solicit, contact or induce, any existing employees, agents or consultants of PG&E Corp., or of any of its subsidiaries or affiliates, to terminate or otherwise alter their employment, agency or consultant relationship with PG&E Corp. or any of its subsidiaries or affiliates. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. (f) For a period of one year after the effective date of this Agreement as set forth in paragraph 17 below, Mr. High shall not, directly or indirectly, solicit, contact or induce, any existing employees, agents or consultants of PG&E Corp., or of any of its subsidiaries or affiliates, to work in any capacity for or on behalf of any person, company or other business enterprise that is in competition with PG&E Corp. or any of its subsidiaries or affiliates. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 14. Mr. High shall, upon reasonable notice from PG&E Corp., furnish information and proper assistance to PG&E Corp. (including truthful testimony and document production) as may reasonably be required by PG&E Corp. in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of PG&E Corp. imposed by any taxing, administrative or regulatory authority having jurisdiction. Mr. High further agrees that his violation of this paragraph shall constitute a material breach of this Agreement. 15. (a) In the event that Mr. High breaches any material provision of this Agreement, PG&E Corp. shall have no further obligation to pay or provide to Mr. High any unpaid amounts or benefits specified in this Agreement. PG&E Corp. shall also be entitled to immediate return of any and all amounts or benefits previously paid or provided to Mr. High under this Agreement and to recalculate any future pension benefit entitlement without the additional credited service and/or age he received or would have received under this Agreement. Despite any breach by Mr. High his other duties and obligations under this Agreement, including his waivers and -4- releases, shall remain in full force and effect. In the event of a breach or threatened breach by Mr. High of any of the provisions in paragraphs 6-8 and 10-14 of this Agreement, PG&E Corp. shall, in addition to any other remedies provided in this Agreement, be entitled to equitable and/or injunctive relief and, because the damages for such a breach or threatened breach will be difficult to determine and will not provide a full and adequate remedy, PG&E Corp. shall also be entitled to specific performance by Mr. High of his obligations under paragraphs 6-8 and 10-14 of this Agreement. Pursuant to paragraph 20 herein, Mr. High shall also be liable for any litigation costs and expenses PG&E Corp. incurs in successfully seeking enforcement of its rights under this Agreement, including reasonable attorney's fees. (b) Mr. High shall be entitled to recover actual damages in the event of any material breach of this Agreement by PG&E Corp., including any unexcused late or non-payment of any amounts owed under this Agreement, or any unexcused failure to provide any other benefits specified in this Agreement. In the event of a breach or threatened breach by PG&E Corp. of any of its material obligations to Mr. High under this Agreement, Mr. High shall be entitled to seek, in addition to any other remedies provided in this Agreement, specific performance of PG&E Corp.'s obligations and any other applicable equitable or injunctive relief. Pursuant to paragraph 20 herein, PG&E Corp. shall also be liable for any litigation costs and expenses Mr. High incurs in successfully seeking enforcement of his rights under this Agreement, including reasonable attorney's fees. Despite any breach by PG&E Corp., its other duties and obligations under this Agreement shall remain in full force and effect. 16. Mr. High acknowledges and agrees that this Agreement is not, and shall not be considered, an admission of liability or of a violation of any applicable contract, law, rule, regulation, or order of any kind. 17. Pursuant to the Older Workers Benefit Protection Act, Mr. High acknowledges that he was provided up to 21 days to consider and accept the terms of this Agreement and that he was advised to consult with an attorney about the Agreement before signing it. Mr. High also understands that, after he signs the Agreement, he will have an additional seven (7) days in which to revoke his acceptance in writing, that to revoke, he must submit a signed statement to that effect to PG&E Corp.'s Senior Human Resources Officer before the close of business on the seventh day, and that, if he does not submit such a revocation, the Agreement will take effect on the eighth day after he signs it. 18. This Agreement sets forth the entire agreement between the parties pertaining to the subject matter of this Agreement and fully supersedes any prior or contemporaneous negotiations, representations, agreements, or understandings between the parties with respect to any such matters, whether written or oral (including any that would have provided Mr. High any different severance arrangements). The parties acknowledge that they have not relied on any promise, representation or warranty, express or implied, not contained in this Agreement. Parol evidence will be inadmissible to show agreement by and among the parties to any term or condition contrary to or in addition to the terms and conditions contained in this Agreement. 19. If any provision of this Agreement is determined to be invalid, void, or -5- unenforceable, the remaining provisions shall remain in full force and effect except that, should paragraphs 6-8 and 10-14 be held invalid, void or unenforceable, either jointly or separately, PG&E Corp. shall be entitled to rescind the Agreement and/or recover from Mr. High any payments made and benefits provided to his under this Agreement. Mr. High understands and agrees that before initiating any action to set aside all or any part of this Agreement, a mandatory condition precedent is his prior tender back to PG&E Corp. of the amounts of any payments previously made or benefits provided to his under this Agreement, including without limitation, any increased pension benefits he gained as a result of any additional credited service and/or age he received under this Agreement. 20. With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Agreement, Mr. High's employment with PG&E Corp. (or with the employing subsidiary), the separation thereof and from his positions as an officer and/or director of PG&E Corp. or any subsidiary or affiliate, or any claims for benefits shall be resolved exclusively by final and binding arbitration using a three member arbitration panel in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making their determination, the arbitrators shall be limited to accepting the position of Mr. High or the position of PG&E Corp., as the case may be. The only claims not covered by this paragraph 20 are any non-waivable claims for benefits under workers' compensation or unemployment insurance laws, which will be resolved under those laws. Any arbitration pursuant to this paragraph 20 shall take place in San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The prevailing party in any dispute or controversy covered by this paragraph 20, or with respect to any request for specific performance, injunctive or other equitable relief, shall be entitled to recover, in addition to any other available remedies specified in this Agreement, all litigation expenses and costs, including any arbitrator, administrative or filing fees and reasonable attorneys' fees. Both Mr. High and PG&E Corp. specifically waive any right to a jury trial on any dispute or controversy covered by this paragraph 20. Judgment may be entered on the arbitrators' award in any court of competent jurisdiction. Subject to the arbitration provisions herein, the sole jurisdiction and venue for any action related to the subject matter of this Agreement shall be the California state and federal courts having within their jurisdiction the location of PG&E Corp.'s principal place of business in California at the time of such action. Both parties consent to the jurisdiction of such courts for any such action. 21. This Agreement shall be governed by and construed under the laws of the United States and, to the extent not preempted by such laws, by the laws of the State of California, without regard to the conflicts of laws provisions thereof. 22. The failure of either party to exercise or enforce, at any time, or for any period of time, any of the provisions of this Agreement shall not be construed as a waiver of such provision, or any portion thereof, and shall in no way affect that party's right to exercise or enforce such provisions. No waiver or default of any provision of this Agreement shall be deemed to be a waiver of any succeeding breach of the same or any other provisions of this Agreement. -6- 23. Mr. High acknowledges and agrees that he has read and understands the contents of this Agreement, that he has been afforded the opportunity to carefully review this Agreement with an attorney of his choice, that he has not relied on any oral or written representation not contained in this Agreement, that he has signed it knowingly and voluntarily, and that after this Agreement becomes effective he will be bound by all of its provisions. PLEASE READ CAREFULLY. THIS AGREEMENT INCLUDES A RELEASE OF ALL KNOWN AND UNKNOWN CLAIMS. THOMAS W. HIGH BRENT G. STANLEY - ---------------------------------- --------------------------------- THOMAS W. HIGH PG&E CORPORATION December 8, 2000 December 8, 2000 - ---------------------------------- --------------------------------- DATE DATE -7- EX-10.14 27 dex1014.txt DESCRIPTION OF STIP FOR OFFICERS OF PG&E CORP. - -------------------------------------------------------------------------------- EXHIBIT 10.14 CONFIDENTIAL ___________________________________________________________ 2001 OFFICER SHORT-TERM INCENTIVE PLAN FINANCIAL PERFORMANCE MEASURE ___________________________________________________________ Nominating and Compensation Committee of the Board of Directors December 20, 2000 [LOGO] PG&E Corporation ---------------- - -------------------------------------------------------------------------------- 2001 Officer STIP Financial Performance Measure ================================================================================ Background Short-Term Incentive Plan Structure - ----------------------------------- . At its meeting on September 20, 2000, the Nominating and Compensation Committee reviewed and approved the 2001 STIP structure for officers of the Corporation and each subsidiary. The structure (see Appendix A) established the weighting of corporate EPS, subsidiary EPS, and other performance factors for officers. The structure requires an implementing methodology to link the EPS performance levels to threshold, minimum, and maximum incentive payout levels, which is contained in this document. 2001 Officer STIP Financial Performance Measure Appendix B ================================================================================ 2001 Short-Term Incentive Plan Structure
- ----------------------------------------------------------------------------------------------------------------------------------- Officer Group Award Component Weight Performance Measures - ----------------------------------------------------------------------------------------------------------------------------------- PG&E Corporation Corporate Financial Performance 100% Corporate EPS from operations - ----------------------------------------------------------------------------------------------------------------------------------- President & CEO - PG&E Corporate Financial Performance 50% Corporate EPS from operations National Energy Group Subsidiary Performance 50% Respective subsidiary contribution to corporate President & CEO - Pacific Gas and EPS from operations Electric Company - ----------------------------------------------------------------------------------------------------------------------------------- Pacific Gas and Electric Co. Corporate Financial Performance 25% Corporate EPS from operations PG&E National Energy Group Subsidiary Financial Performance 50 - 75% Respective subsidiary contribution to corporate Pacific Venture Capital, LLC EPS from operations PG&E Telecom, LLC Subsidiary Operational Performance 0 - 25% Financial, operating, and service measures determined by Subsidiary CEO - -----------------------------------------------------------------------------------------------------------------------------------
EX-10.20 28 dex1020.txt PG&E CORP. EXECUTIVE STOCK OWNERSHIP PROGRAM EXHIBIT 10.20 PG&E CORPORATION EXECUTIVE STOCK OWNERSHIP PROGRAM Administrative Guidelines ------------------------- (As amended September 19, 2000) 1. Description. The Executive Stock Ownership Program ("Program") was approved ----------- by the Nominating and Compensation Committee of the Board of Directors on October 15, 1997. The Program is an important element of the Committee's compensation policy of aligning executive interests with those of the Corporation's shareholders. As an integral part of the Program, the Committee also authorized the use of Special Incentive Stock Ownership Premiums ("SISOPs") which are designed to provide incentives to Eligible Executives to assist in achieving minimum stock ownership targets established by the Committee. These Guidelines were originally adopted by the Committee on November 19, 1997, amended by the Committee on July 22, 1998, October 21, 1998, February 16, 2000, and September 19, 2000. These amended Guidelines, along with the written materials provided to the Committee on October 15, 1997, describe the Program which became effective on January 1, 1998. The Program is administered by the Corporation's Senior Human Resources Officer. 2. Eligible Executives. The Chief Executive Officer shall designate the ------------------- officers of the Corporation and its affiliates who shall be Eligible Executives covered by the Program. The officers covered by the Guidelines and the applicable total stock ownership target ("Target") are: --------------------------------------------------------------------------- Officer Band Position Total Stock Ownership Target --------------------------------------------------------------------------- 1 CEO 3 x base salary --------------------------------------------------------------------------- 2 Heads of Business Lines, 2 x base salary CFO, & General Counsel --------------------------------------------------------------------------- 3 SVPs of Corp. & Utility 1.5 x base salary --------------------------------------------------------------------------- 3. Annual Milestones. Under the Guidelines, Targets 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, 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 equivalents owned by the Eligible Executive as compared with the Annual Milestone or Target for that executive. For purposes of this calculation, the value per share of stock or stock equivalent ("Measurement Value") is the average closing price of PG&E Corporation common stock as traded on the New York Stock Exchange for the last thirty (30) trading days of the year. a) The value of stock beneficially owned by the Eligible Executive is determined by multiplying the number of shares owned beneficially on the Measurement Date times the Measurement Value. b) The value of PG&E Corporation phantom stock units credited to the Eligible Executive's account in the PG&E Corporation Supplemental Retirement Savings Plan ("SRSP") is determined by multiplying the number of phantom stock units credited to the Eligible Executive's SRSP account on the Measurement Date times the Measurement Value. c) The value of stock held in the PG&E Corporation stock fund of any defined contribution plan maintained by PG&E Corporation or any of its subsidiaries is determined by multiplying the number of shares in such plan on the Measurement Date times the Measurement Value. d) For Eligible Executive's whose Target Date is on or before 12/31/2004, the value of the frozen share-equivalent units of the vested "in the money" stock options as of 12/31/2000. The value of the frozen share- equivalent units of the vested "in the money" stock options is the difference between the number of options on 12/31/2000 multiplied by the Measurement Value on 12/31/2000 minus the number of options on 12/31/2000 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, the current stock ownership level is reduced by the stock ownership level used to calculate previous SISOP awards to determine the new ownership then 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 8. This calculation converts the dollar value of the stock ownership level used as the basis for qualifying for SISOPs into a number of shares of stock. It is calculated by dividing the stock ownership level by the Measurement Value. 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 SRSP. Upon award, SISOPs are credited to the --------------------------- Eligible Executive's SRSP account and converted into units of phantom stock each equal in value to a share of PG&E Corporation common stock ("SISOP units") as determined in accordance with the SRSP. The SISOP units constitute "incentive awards" authorized to be awarded by the Committee to Eligible Executives under the PG&E Corporation Long-Term Incentive Program ("LTIP"). Upon credit of SISOP units to an Eligible Executive's SRSP account, an equal number of shares of PG&E Corporation common stock shall be reserved for issuance from the pool of shares authorized for issuance under the LTIP. Once a SISOP unit is credited to the Eligible Executive's SRSP account, it shall be subject to all of the terms and conditions specifically applicable to SISOP units under the SRSP. Once vested in accordance with paragraph 7 below, SISOP units are distributed in the form of an equal number of shares of PG&E Corporation common stock as provided in the SRSP. 7. Vesting. SISOPs vest only upon the expiration of three years after the date ------- of award (provided the Eligible Executive continues to be employed on such date), or, if earlier, upon an Eligible Executive's death, disability, Retirement, upon a Change in Control, as defined in the LTIP, or upon a termination of employment coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation. An Eligible Executive's unvested SISOPs will be forfeited upon termination of employment unless otherwise provided in the PG&E Corporation Officer Severance Policy or by another separation agreement 8. Forfeiture of SISOP Units. So long as SISOP units remain unvested, such ------------------------- units are subject to forfeiture if, on each Measurement Date, the Eligible Executive's stock ownership is less than the Minimum Ownership Level established when the SISOPs were granted (see paragraph 5). To determine forfeiture, the following steps are followed on each Measurement Date: a) The total stock and stock equivalents owned by an Eligible Executive is determined as set forth under paragraph 4. This total ("Current Holdings") is compared with the Minimum Ownership Level determined when the SISOPs were granted. If the Current Holdings are equal to or greater than the Minimum Ownership Level, then no unvested SISOP units are forfeited. If the Current Holdings are less than the Minimum Ownership Level, then the unvested SISOP units are forfeited in the same proportion as the Current Holdings are less than Minimum Ownership Level (for 3 example, if the Current Holdings are 20 percent less than the Minimum Ownership Level, then 20 percent of the SISOP units are forfeited). 9. Failure to Achieve or Maintain Target. Failure to achieve stock ownership ------------------------------------- levels at Target on the Target Date, or to maintain stock ownership levels at Target on any Measurement Date thereafter, will result in the deferral into the PG&E Corporation Phantom Stock Fund of the SRSP of annual awards from the Performance Unit Plan ("PUP") and the Short-Term Incentive Plan ("STIP"). As of any Measurement Date, to the extent that stock ownership levels are below Target, PUP awards shall be converted into PG&E Corporation Phantom Stock Units and held in the PG&E Corporation Phantom Stock Fund of the SRSP. If, with the addition of the phantom stock units attributable to the PUP award, the stock ownership level is still below Target for any Measurement Date, any STIP award above target STIP also shall be converted into phantom stock units, to the extent necessary to achieve the Target stock ownership level. Such conversion of PUP and STIP awards shall continue for successive Measurement Dates, if necessary, until Target is met. Phantom stock units attributable to PUP and STIP awards described in this paragraph 9 will be paid from the SRSP in a lump sum in January of the year following the year in which the Eligible Executive's employment terminates, or upon such earlier date as may have been elected by the Eligible Executive within thirty days after the date of mandatory deferral of PUP and/or STIP awards which date shall not be earlier than three (3) years after the date of mandatory deferral. 4 EX-11 29 dex11.txt COMPUTATION OF EARNINGS PER COMMON SHARE EXHIBIT 11 PG&E CORPORATION COMPUTATION OF EARNINGS PER COMMON SHARE
- ----------------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, ---------------- ------------------ (in millions, except per share amounts) 2000 1999 2000 1999 - ----------------------------------------------------------------------------------- BASIC EARNINGS PER SHARE (EPS)/1/ Earnings available for common stock $(4,117) $ (611) $(3,364) $ (73) ======= ====== ======= ====== Average common shares outstanding/2/ 363 366 362 368 ======= ====== ======= ====== Basic EPS $ (1.34) $(1.67) $ (9.29) $(0.20) ======= ====== ======= ====== DILUTED EARNINGS PER SHARE (EPS)/1/ Earnings available for common stock $(4,117) $ (611) $(3,364) $ (73) ======= ====== ======= ====== Average common shares outstanding 363 366 362 368 Add: outstanding options, reduced by the number of shares that could be repurchased with the proceeds from such exercise (at average market price) 3 - 2 1 ------- ------ ------- ------ Average common shares outstanding as adjusted 366 366 364 369 ======= ====== ======= ====== Diluted EPS $(11.25) (1.67) $ (9.24) $(0.20) ======= ====== ======= ====== - -----------------------------------------------------------------------------------
/1/ This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K and Statement of Financial Accounting Standards No. 128. /2/ Average common shares outstanding exclude shares held by a subsidiary of PG&E Corporation (23,815,500 shares at December 31, 1999 and 2000, respectively) and shares held by the Company to secure deferred compensation obligations (281,985 shares at December 31, 1999 and 2000, respectively). EX-12.1 30 dex121.txt 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) 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------------- Earnings: Net income (loss) $(3,483) $ 788 $ 729 $ 768 $ 755 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 Income tax expense (2,154) 648 629 609 555 Net fixed charges 648 637 673 628 683 ------- ------- ------- ------- ------- Total Earnings $(4,989) $ 2,073 $ 2,031 $ 2,005 $ 1,996 ======= ======= ======= ======= ======= Fixed Charges: Interest on long- term debt, net $ 508 $ 523 $ 585 $ 485 $ 574 Interest on short- term borrowings 108 81 50 101 75 Interest on capital leases 2 3 2 2 3 AFUDC debt 6 7 12 17 8 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 24 24 24 24 24 ------- ------- ------- ------- ------- Total Fixed Charges $ 648 $ 638 $ 673 $ 629 $ 684 ======= ======= ======= ======= ======= Ratios of Earnings to Fixed Charges (7.70)(1) 3.25 3.02 3.19 2.92 - -----------------------------------------------------------------------------------------------
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. (1) The ratio of earnings to fixed charges indicates a deficiency of less than one-to-one coverage aggregating $5,637 million. EX-12.2 31 dex122.txt COMPUTATION OF RATIOS OF EARNINGS - COMBINED 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) 2000 1999 1998 1997 1996 - ------------------------------------------------------------------------------------------ Earnings: Net income (loss) $ (3,483) $ 788 $ 729 $ 768 $ 755 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 Income tax expense (2,154) 648 629 609 555 Net fixed charges 648 637 673 628 683 --------- -------- -------- --------- --------- Total Earnings $ (4,989) $ 2,073 $ 2,031 $ 2,005 $ 1,996 ========= ======== ======== ========= ========= Fixed Charges: Interest on long- term debt, net $ 508 $ 523 $ 585 $ 485 $ 574 Interest on short- term borrowings 108 81 50 101 75 Interest on capital leases 2 3 2 2 3 AFUDC debt 6 7 12 17 8 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 24 24 24 24 24 --------- -------- -------- --------- --------- Total Fixed Charges $ 648 $ 638 $ 673 $ 629 $ 684 --------- -------- -------- --------- --------- Preferred Stock Dividends: Tax deductible dividends $ 9 $ 9 $ 9 $ 10 $ 10 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements $ 27 $ 27 $ 31 $ 39 $ 39 --------- -------- -------- --------- --------- Total Preferred Stock Dividends $ 36 $ 36 $ 40 $ 49 $ 49 --------- -------- -------- --------- --------- Total Combined Fixed Charges and Preferred Stock Dividends $ 684 $ 674 $ 713 $ 678 $ 733 ========= ======== ======== ========= ========= Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends (7.29)(1) 3.08 2.85 2.96 2.72 - ---------------------------------------------------------------------------------------------
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. (1) The ratio of earnings to combined fixed charges and preferred stock dividends indicates a deficiency of less than one-to-one coverage aggregating $5,673 million. EX-13 32 dex13.txt ANNUAL REPORT TO SHAREHOLDERS OF PG&E CORP. EXHIBIT 13 Portions of 2000 Annual Report to Shareholders SELECTED FINANCIAL DATA
(in millions, except per share amounts) 2000 1999 1998 1997 1996 PG&E Corporation/(1)/ For the Year Operating revenues $26,232 $20,820 $19,577 $15,255 $ 9,610 Operating income (loss) (4,807) 878 2,098 1,762 1,896 Income (Loss) from continuing operations (3,324) 13 771 745 722 Earnings (Loss) per common share from continuing operations, basic and diluted (9.18) 0.04 2.02 1.82 1.75 Dividends declared per common share 1.20 1.20 1.20 1.20 1.77 At Year-End Book value per common share $ 8.76 $ 19.13 $ 21.08 $ 21.30 $ 20.73 Common stock price per share 20.00 20.50 31.50 30.31 21.00 Total assets 35,291 29,470 33,234 31,115 26,237 Long-term debt (excluding current portions) 4,736 6,682 7,422 7,659 7,770 Rate reduction bonds (excluding current portions) 1,740 2,031 2,321 2,611 -- Redeemable preferred stock and securities of subsidiaries (excluding current portion) 635 635 635 750 694 Pacific Gas and Electric Company For the Year Operating revenues $ 9,637 $ 9,228 $ 8,924 $ 9,495 $ 9,610 Operating income (loss) (5,201) 1,993 1,876 1,820 1,896 Income (Loss) available for common stock (3,508) 763 702 735 722 At Year-End Total assets $21,988 $21,470 $22,950 $25,147 $26,237 Long-term debt (excluding current portion) 3,342 4,877 5,444 6,218 7,770 Rate reduction bonds (excluding current portion) 1,740 2,031 2,321 2,611 -- Redeemable preferred stock and securities (excluding current portion) 586 586 586 694 694
(1) PG&E Corporation became the holding company for Pacific Gas and Electric Company on January 1, 1997. The Selected Financial Data of PG&E Corporation and Pacific Gas and Electric Company (the Utility) for 1996 are identical because they reflect the accounts of the Utility as the predecessor of PG&E Corporation. Matters relating to certain data above, including the provision for loss on generation-related regulatory assets and undercollected purchased power costs, discontinued operations, and the cumulative effect of a change in accounting principle, are discussed in Management's Discussion and Analysis and in the Notes to the Consolidated Financial Statements. MANAGEMENT'S DISCUSSION AND ANALYSIS PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company (the Utility), delivers electric service to approximately 4.6 million customers and natural gas service to approximately 3.8 million customers. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdiction of the Bankruptcy Court. The factors causing the Utility to take this action are discussed in this Management's Discussion and Analysis (MD&A) and in Notes 2 and 3 of the Notes to the Consolidated Financial Statements. PG&E Corporation's National Energy Group, Inc. (the NEG) is an integrated energy company with a strategic focus on power generation, new power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. The NEG businesses include its power plant development and generation unit, PG&E Generating Company, LLC and its affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas Transmission Corporation (PG&E GT); and its wholesale energy and marketing trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy Trading--Gas Corporation, and PG&E Energy Trading--Power, L.P. (collectively, PG&E Energy Trading or PG&E ET). During 2000, the NEG sold its energy services unit, PG&E Energy Services Corporation (PG&E ES). Also, during the fourth quarter of 2000, the NEG sold its Texas natural gas and natural gas liquids business carried on through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries (PG&E GTT). For more information about the NEG's businesses, see "PG&E National Energy Group, Inc." below. PG&E Corporation has identified five reportable operating segments. The Utility is one reportable operating segment and the other four are part of the NEG (PG&E Gen, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), PG&E GTT, and PG&E ET). During 2000, the NEG has been integrating these lines of business into two lines of business: (1) an integrated power generation and energy trading and marketing business, and (2) a natural gas transmission business. Financial information about each reportable operating segment is provided in this MD&A and in Note 16 of the Notes to the Consolidated Financial Statements. This is a combined annual report of PG&E Corporation and the Utility. It includes separate consolidated financial statements for each entity. The consolidated financial statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and PG&E Corporation's wholly owned and controlled subsidiaries. The consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries. This MD&A should be read in conjunction with the consolidated financial statements included herein. This combined annual report, including our Letter to Shareholders and this MD&A, contains forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements. Although PG&E Corporation and the Utility are not able to predict all of the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements or historical results include: . the reorganization plan that is ultimately adopted by the Bankruptcy Court; . the regulatory, judicial, or legislative actions (including ballot initiatives) that may be taken to meet future power needs in California, mitigate the higher wholesale power prices, provide refunds for prior power costs, or address the Utility's financial condition; . the extent to which the Utility's undercollected wholesale power purchase costs may be collected from customers; . any changes in the amount of transition costs the Utility is allowed to collect from its customers, and the timing of the completion of the Utility's transition cost recovery; . future market prices for electricity and future fuel prices, which in part, are influenced by future weather conditions, the availability of hydroelectric power, and the development of competitive markets; . the method and timing of valuation of the Utility's hydroelectric generation assets; . future operating performance at the Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the future ratemaking applicable to Diablo Canyon; . legislative or regulatory changes, including the pace and extent of the ongoing restructuring of the electric and natural gas industries across the United States; . future sales levels and economic conditions; . the extent to which our current or planned generation development projects are completed and the pace and cost of such completion; . generating capacity expansion and retirements by others; . the outcome of the Utility's various regulatory proceedings; . fluctuations in commodity gas, natural gas liquids, and electric prices and the ability to successfully manage such price fluctuations; . the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant; and . the outcome of pending litigation. As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from results or outcomes we currently seek or expect. Each of these factors is discussed in greater detail in this MD&A. In this MD&A, we first discuss the California energy crisis and its impact on our liquidity. We then discuss statements of cash flows and financial resources, and our results of operations for 2000, 1999, and 1998. Finally, we discuss our competitive and regulatory environment, our risk management activities, and various uncertainties that could affect future earnings. Our MD&A applies to both PG&E Corporation and the Utility. LIQUIDITY AND FINANCIAL RESOURCES The California Energy Crisis The state of California is in the midst of an energy crisis. The cost of wholesale power has risen to levels almost ten times greater than those in 1999. Rolling blackouts have occurred as a result of a broken deregulated electricity market. Because of this crisis, PG&E Corporation and the Utility have experienced a significant deterioration in their liquidity and consolidated financial position. The Utility's credit rating has deteriorated to below investment grade level. As of March 29, 2001, the Utility is in default or has not paid amounts due under various bank agreements, commercial paper, and payments to the California Power Exchange (PX), the California Independent System Operator (ISO), qualifying facilities (QFs), and energy service providers totaling over $4 billion. In addition, PG&E Corporation and the Utility recognized a fourth quarter charge to earnings of $6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility could no longer conclude that its generation-related regulatory assets and undercollected purchased power costs were probable of recovery from ratepayers. This charge resulted in accumulated deficits at December 31, 2000, of $2.0 billion and $2.1 billion for the Utility and PG&E Corporation, respectively. As more fully discussed herein, the Utility has been working with regulators and state and federal legislators and California leaders in an effort to seek an overall solution to the California energy crisis. However, the ongoing uncertainty as to the timing and extent of any solution, in addition to increasing debt and regulatory changes, caused the Utility to seek protection from its creditors through a Chapter 11 Bankruptcy Filing. The filing for bankruptcy protection and the related uncertainty around any reorganization plan, that is ultimately adopted, will have a significant impact on the Utility's future liquidity and results of operations. In addition to the $4 billion of defaults and amounts not paid mentioned above, the Utility anticipates an aggregate of approximately $1.5 billion of additional obligations that will become due and payable in April 2001. As of March 29, 2001, the Utility had $2.6 billion of cash available to fund operations. See Notes 2 and 3 of the Notes to the Consolidated Financial Statements for a detailed discussion of the California energy crisis and the events leading up to the charge incurred by PG&E Corporation and the Utility. A discussion of the current and future liquidity and financial resources, and mitigation efforts undertaken by the Utility and PG&E Corporation follows. Pacific Gas and Electric Company The California energy crisis described in Note 2 of the Notes to the Consolidated Financial Statements has had a significant negative impact on the liquidity and financial resources of the Utility. Beginning in June 2000, the wholesale price of electric power in California steadily increased to an average cost of 18.16 cents per kilowatt-hour (kWh) for the seven month period of June 2000 through December 2000, as compared to an average cost of 4.23 cents per kWh for the same period in 1999. Under California Assemby Bill 1890 (AB 1890), the Utility's electric rates were frozen at levels that allowed approximately 5.4 cents per kWh to be charged to the Utility's customers as reimbursement for power costs incurred by the Utility on behalf of its retail customers. The excess of wholesale electricity costs above the generation-related cost component available in frozen rates resulted in an undercollection at December 31, 2000, of approximately $6.6 billion, and rose to approximately $8.9 billion by February 28, 2001. The difference between the actual costs incurred to purchase power and the amount recovered from customers was funded through a series of borrowings. In October 2000, the Utility fully utilized its existing $1 billion revolving credit facility to support the Utility's commercial paper program and other liquidity requirements. On October 18, 2000, the Utility obtained an additional $1 billion, 364-day revolving credit facility. On November 1, 2000, the Utility issued $1 billion of short-term floating rate notes and $680 million of five- year notes. On November 22, 2000, the Utility issued an additional $240 million of short-term floating rate notes. On December 1, 2000, the bank group reduced the size of the $1 billion, 364-day revolving credit facility to $850 million. At December 31, 2000, the Utility had borrowed $614 million against its five- year revolving credit agreement, had issued $1,225 million of commercial paper, and had issued $1,240 million of floating rate notes. In late 2000, the Utility began to implement cash conservation measures that included layoffs of 1,000 temporary workers, suspension of dividend payments, and deferral of merit increases and incentive compensation for employees. Also, federal and state legislators and regulators recognized that the wholesale power market was seriously flawed and they began seeking solutions to the California energy crisis. In response to the growing crisis, on January 4, 2001, the California Public Utilities Commission (CPUC) approved an interim one-cent per kWh rate increase, which would raise approximately $70 million in cash per month for three months. Even if all this cash had been available to the Utility immediately, $210 million represented approximately one week's worth of net power purchases at the then current prices. Thus, the rate increase did not raise enough cash for the Utility to pay its ongoing wholesale electric energy procurement bills or make further borrowing possible. On January 10, 2001, the Board of Directors of the Utility suspended the payment of its fourth quarter 2000 common stock dividend in an aggregate amount of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E Holdings, Inc., a wholly-owned subsidiary of the Utility. In addition, the Utility's Board of Directors decided not to declare the regular preferred stock dividends for the three-month period ending January 31, 2001, normally payable on February 15, 2001. Dividends on all Utility preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock. On January 16 and 17, 2001, the outstanding bonds of the Utility were downgraded to below investment grade status. Standard and Poor's (S&P) stated that the downgrade reflected the heightened probability of the Utility's imminent insolvency and the resulting negative financial implications for PG&E Corporation and affiliated companies because, among other reasons, (1) some of the Utility's principal trade creditors were demanding that sizeable cash payments be made as a pre-condition to the purchase of natural gas and electric power necessary for on-going business operations; (2) neither legislative nor negotiated solutions to the California utilities' financial situation appeared to be forthcoming in a timely manner, which continued to impede access to financial markets for the working capital needed to avoid insolvency; and (3) Southern California Edison's (SCE) decision to default on its obligation to pay principal and interest due on January 16, 2001, diminished the prospects for the Utility's access to capital markets. This downgrade to below investment grade status was an event of default under one of the Utility's revolving credit facilities and precluded the Utility from access to the capital markets. As a result, the banks stopped funding under the revolving credit facility. On January 17, 2001, the Utility began to default on maturing commercial paper obligations. In addition, the Utility was no longer able to meet its obligations to generators, QFs, the ISO, and PX, and began making partial payments of amounts owed. The Utility's credit ratings as of March 29, 2001, are as follows: Corporate credit rating: D/D Commercial paper: D Senior secured debt: CCC Senior unsecured debt: CC Preferred stock: D Shelf senior secured/unsecured subordinated debt: CCC/CC Shelf debt preferred stock: D After the downgrade, the PX notified the Utility that the ratings downgrade required the Utility to post collateral for all transactions in the PX day-ahead market. Since the Utility was unable to post such collateral, the PX suspended the Utility's trading privileges effective January 19, 2001, in the day-ahead market. The PX also sought to liquidate the Utility's block-forward contracts for the purchase of power. On January 25, 2001, a California Superior Court judge granted the Utility's application for a temporary restraining order, which thereby restrained and enjoined the PX and its agents from liquidating the Utility's contracts in the block-forward market, pending hearing on a preliminary injunction on February 5, 2001. Immediately before the hearing on the preliminary injunction, California Governor Gray Davis, acting under California's Emergency Services Act, commandeered the contracts for the benefit of the state. Under the Act, the state must pay the Utility the reasonable value of the contracts, although the PX may seek to recover the monies that the Utility owes to the PX from any proceeds realized from those contracts. Discussions and negotiations on this issue are currently ongoing between the state and the Utility. On January 19, 2001, the Utility was no longer able to continue purchasing power for its customers because of a lack of creditworthiness and the state of California authorized the California Department of Water Resources (DWR) to purchase electricity for the Utility's customers. Assembly Bill 1X (AB1X) was passed on February 1, 2001, authorizing the DWR to enter into contracts for the purchase and sale of electric power and to issue revenue bonds to finance electricity purchases. The DWR has entered into long-term contracts with several generators for the supply of electricity. However it continues to purchase significant amounts of power on the spot market at prevailing market prices. The DWR is not purchasing electricity for the Utility's entire net open position (the amount of power that cannot be met by the Utility's own or contracted-for generation). To the extent that the DWR is not purchasing electricity for the entire net open position, the remainder is being procured by the ISO. To that extent, the ISO may attempt to charge the Utility for those purchases. As a result of (1) the failure by the state to assume the full procurement responsibility for the Utility's net open position, as was provided under AB1X, (2) the negative impact of recent actions by the CPUC that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) a lack of progress in negotiations with the state to provide a solution for the energy crisis, and (4) the adoption by the CPUC of an illegal and retroactive accounting change that would appear to eliminate the Utility's true undercollected purchased power costs, the Utility filed a voluntary petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code on April 6, 2001. As of March 29, 2001, the Utility was in default and had not paid the following:
Amount Description (in millions) ----------- ------------ Items not paid PX/ISO--real time market deliveries $1,448 Qualifying facilities 643 Direct access credits due to energy service providers 503 Commercial paper 861
Bank loans 939* Other 26 Total Items Not Paid $4,420 Items coming due through April 30, 2001 PX/ISO--real time market deliveries $ 550 Qualifying facilities 340 Gas suppliers 470 Other 140 Total coming due $1,500 Total cash on hand at March 29, 2001 $2,600
*Loans that lenders have agreed to forbear through April 13, 2001. Additionally, the Utility may be required by the CPUC to pay the DWR for purchases that it has made on behalf of the Utility's customers. As discussed further in Note 2 of the Notes to the Consolidated Financial Statements, there is a dispute over how much the Utility must pay the DWR. Also, the DWR has indicated that it intends to purchase power only at "reasonable prices." The ISO has continued to purchase power at prices in excess of the DWR's as yet undisclosed ceiling and has been billing the Utility for the differential. The Utility does not yet know what the total expected billing is for these purchases. Subject to certain qualifications, the banks under the Utility's $1 billion revolving credit agreement agreed to forbear from exercising any remedies with respect to the Utility's default under that agreement until April 13, 2001. Subject to the approval by the Bankruptcy Court, the Utility's intent is to pay its ongoing costs of doing business while seeking resolution of the wholesale energy crisis. It is the Utility's intention to continue to pay employees, vendors, suppliers, and other creditors to maintain essential distribution and transmission services. However, the Utility is not in a position to pay maturing or accelerated obligations, nor is the Utility in a position to pay the ISO, PX, and the QFs the amounts due for the Utility's power purchases above the amount included in rates for power purchase costs. The Utility's current actions are intended to allow the Utility to continue to operate while efforts to reach a regulatory or legislative solution continue. The Utility's plans will be subject to approval of the Bankrupcy Court. The Utility has also deferred quarterly interest payments on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series A, (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly deferred. Distributions can be deferred up to a period of five years per the indenture. Investors will accumulate interest on the unpaid distributions at the rate of 7.90%. The weakened financial condition of the Utility also has impacted its ability to supply natural gas to its natural gas customers. In December 2000 and January 2001, several gas suppliers demanded prepayment, cash on delivery, or other forms of payment assurance before they would deliver gas, instead of the normal payment terms, under which the Utility would pay for the gas after delivery. As the Utility was unable to meet such demands at that time, several gas suppliers refused to supply gas, accelerating the depletion of the Utility's gas storage reserves and potentially exacerbating the electric power crisis if the Utility were required to divert gas from industrial users, including natural gas fired power plant operators. The U.S. Secretary of Energy issued a temporary order on January 19, 2001, requiring the gas suppliers to continue to make deliveries to avoid a worsening natural gas shortage emergency. However, this order expired on February 7, 2001, and certain companies, representing about 10% of the Utility's natural gas suppliers, terminated deliveries after the order expired. The Utility tried to mitigate the worsening supply situation by withdrawing more gas from storage and, when able, purchasing additional gas on the spot market. Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge its gas account receivables and its gas inventories for up to 90 days (extended to 180 days in a CPUC draft decision issued on February 15, 2001) to secure gas for its core customers. At March 29, 2001, the amount of gas accounts receivables pledged was approximately $900 million. As of March 29, 2001, approximately 30% of the Utility's suppliers of natural gas had signed security agreements with the Utility and discussions were continuing with the Utility's other suppliers. Additionally, the Utility is currently implementing a program to obtain longer-term summer and winter supplies and daily spot supplies. PG&E Corporation The liquidity and financial condition crisis faced by the Utility also negatively impacted PG&E Corporation. Through December 31, 2000, PG&E Corporation funded its working capital needs primarily by drawing down on available lines of credit and other short-term credit facilities. At December 31, 2000, PG&E Corporation had borrowed $185 million against its five-year revolving credit agreement and had issued $746 million of commercial paper. Due to the credit ratings downgrades of PG&E Corporation, the banks refused any additional borrowing requests and terminated their remaining commitments under existing credit facilities. Commencing January 17, 2001, PG&E Corporation began to default on its maturing commercial paper obligations. Commencing on March 2, 2001, PG&E Corporation refinanced its debt obligations with $1 billion in aggregate proceeds of two term loans under a common credit agreement with General Electric Capital Corporation and Lehman Commercial Paper Inc. In accordance with the credit agreement, the proceeds, together with other PG&E Corporation cash, were used to pay $501 million in commercial paper (including $457 million of commercial paper on which PG&E Corporation had defaulted), $434 million in borrowings under PG&E Corporation's long-term revolving credit facility, and $116 million to PG&E Corporation shareholders of record as of December 15, 2000, in satisfaction of a defaulted fourth quarter 2000 dividend. Further, approximately $85 million was used to pre-pay the first year's interest under the credit agreement and to pay transaction expenses associated with the debt restructuring. See Note 3 of the Notes to the Consolidated Financial Statements for a detailed description of the loan. On March 15, 2001, PG&E Corporation's corporate credit rating was withdrawn by S&P due to the March 2, 2001, refinancing of its obligations and the fact that PG&E Corporation had no more public debt to be rated. PG&E Corporation itself had cash of $297 million at March 29, 2001, and believes that the funds will be adequate to maintain its continuing operations throughout 2001. In addition, PG&E Corporation believes that the holding company and its non-CPUC regulated subsidiaries are protected from the bankruptcy of the Utility. PG&E National Energy Group In December 2000, and in January and February 2001, PG&E Corporation and the NEG undertook a corporate restructuring of NEG, known as a "ringfencing" transaction. The ringfencing complied with credit rating agency criteria, enabling the NEG, PG&E GTN, and PG&E ET to receive or retain their own credit ratings based on their own creditworthiness. The ringfencing involved the creation or use of special purpose entities (SPEs) as intermediate owners between PG&E Corporation and its non-CPUC regulated subsidiaries. These SPEs are: PG&E National Energy Group, LLC, which owns 100% of the stock of the NEG; PG&E GTN Holdings LLC which owns 100% of the stock of PG&E GTN; and PG&E Energy Trading Holdings LLC, which owns 100% of the stock of PG&E Corporation's energy trading subsidiaries, PG&E Energy Trading-Gas Corporation, PG&E Energy Trading Holdings Corporation, and PG&E Energy Trading-Power, L.P. In addition, the NEG's organizational documents were modified to include the same structural elements as the SPEs to meet credit rating agency criteria. Ringfencing is intended to reduce the likelihood that the assets of the ringfenced companies would be substantively consolidated in a bankruptcy proceeding involving such companies' ultimate parent, and to thereby preserve the value of the "protected" entities as a whole. The SPEs require unanimous approval of their respective boards of directors, including an independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not declare or pay dividends unless the respective board of directors has unanimously approved such action and the company meets specified financial requirements. STATEMENTS OF CASH FLOWS FOR 2000, 1999, AND 1998 PG&E Corporation normally funds investing activities from cash provided by operations after capital requirements and, to the extent necessary, external financing. Our policy is to finance our investments with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to the Utility, complies with regulatory guidelines. PG&E Corporation Consolidated Cash Flows from Operating Activities Net cash (used) provided by PG&E Corporation's operating activities totaled $(776) million, $2,155 million, and $3,388 million in 2000, 1999, and 1998, respectively. The decrease of $2,931 million between 1999 and 2000 is attributable to the California energy crisis previously discussed. Cash Flows from Investing Activities During 2000, 1999, and 1998, PG&E Corporation used $1.8 billion, $1.6 billion, and $1.6 billion, respectively, for upgrades and expansion of its facilities in operation or under construction. These capital expenditures were partially offset by the 1999 and 1998 divestitures of generation facilities at the Utility and by the completed sales of the PG&E ES and PG&E GTT business units in 2000. In 2000, PG&E Corporation sold its Energy Services retail business for $85 million and its value-added-services business and various other assets for $18 million. The NEG received $306 million, which included a working capital adjustment for the sale of PG&E GTT. The sale also included the assumption of liabilities associated with PG&E GTT and debt having a book value of $564 million. In 1999 and 1998, the Utility received proceeds of $1,014 million and $501 million, respectively, from the sale of generation facilities. In 1998, PG&E Corporation sold its Australian energy holdings for proceeds of approximately $126 million, and the NEG sold its Bear Swamp facility for $479 million. Cash Flows from Financing Activities As of March 29, 2001, PG&E Corporation, itself, had $297 million in cash on hand and had successfully refinanced its obligations that were in default. (See previous discussion of PG&E Corporation's refinancing.) Net cash provided by financing activities in 2000 totaled $2.4 billion, principally through borrowings under credit facilities and issuances of short-term and long-term debt needed to fund energy purchases. Net cash used by financing activities in 1999 and 1998 totaled $2.0 billion and $1.1 billion, respectively, and was used principally to retire debt, repurchase outstanding common stock, and pay dividends. During 2000, 1999, and 1998, PG&E Corporation issued $65 million, $54 million, and $63 million of common stock, respectively, primarily through the Dividend Reinvestment Plan and the stock option plan component of the Long-Term Incentive Program. During 2000, 1999, and 1998, PG&E Corporation declared dividends on its common stock of $434 million, $460 million, and $466 million, respectively. During 2000, 1999, and 1998, PG&E Corporation repurchased $2 million, $693 million, and $1,158 million of its common stock, respectively, primarily through separate, accelerated share repurchase programs. As of December 31, 1997, the Board of Directors had authorized the repurchase of up to $1.7 billion of PG&E Corporation's common stock on the open market or in negotiated transactions. As part of this authorization, in January 1998, PG&E Corporation repurchased in a specific transaction 37 million shares of common stock. As of December 31, 1998, approximately $570 million remained available under this repurchase authorization. In February 1999, PG&E Corporation used this remaining authorization to purchase 16.6 million shares at a total cost of $531 million. A subsidiary of PG&E Corporation made this repurchase, along with subsequent stock repurchases. The stock held by the subsidiary is treated as treasury stock and reflected as Stock Held by Subsidiary on the Consolidated Balance Sheet of PG&E Corporation. In October 1999, the Board of Directors of PG&E Corporation authorized an additional $500 million for the purpose of repurchasing shares of PG&E Corporation's common stock on the open market. This authorization supplemented the approximately $40 million remaining from the amount previously authorized by the Board of Directors on December 17, 1997. The authorization for share repurchase extends through September 30, 2001. As of December 31, 1999, through its wholly owned subsidiary, PG&E Corporation repurchased an additional 7.2 million shares, at a cost of $159 million under this authorization. At December 31, 2000, the remainder under the share repurchase authorization is approximately $380 million. PG&E Corporation is precluded by its March 2, 2001, loan agreement with General Electric Capital Corporation and Lehman Commercial Paper Inc. from repurchasing its common stock until the loan is repaid. Utility The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the three year period ended December 31, 2000. Cash Flows from Operating Activities Net cash (used) provided by the Utility's operating activities totaled $(699) million, $2,196 million, and $3,736 million in 2000, 1999, and 1998, respectively. The decrease of $2,895 million between 1999 and 2000 is attributable to the California energy crisis and the significant deterioration of the Utility's financial condition reflected by the deferred electric procurement costs of $6,465 million which have not yet been recovered from ratepayers and which were determined not to be probable of recovery through regulated rates and recognized as a charge to earnings in the fourth quarter 2000. Cash Flows from Investing Activities The primary uses of cash for investing activities are additions to property, plant, and equipment. The Utility's capital expenditures were $1,245 million, $1,181 million, and $1,382 million, for the years ended December 31, 2000, 1999, and 1998, respectively. During 1999, the Utility sold three fossil-fueled generation facilities and its geothermal generation facilities. These sales closed in April and May 1999, respectively, and generated proceeds of $1,014 million. In 1998, the Utility had proceeds of $501 million from the sale of three fossil-fueled generation plants. Cash Flows from Financing Activities In April 2000, a subsidiary of the Utility repurchased from PG&E Corporation 11.9 million shares of its common stock at a cost of $275 million. In December 1999, 7.6 million shares of the Utility's common stock, with an aggregate purchase price of $200 million, was purchased by a subsidiary of the Utility. These repurchases are reflected as stock held by subsidiary in the Consolidated Balance Sheet of the Utility. Earlier in 1999, the Utility repurchased from PG&E Corporation, and cancelled 20 million shares of its common stock from PG&E Corporation for an aggregate purchase price of $726 million to maintain its authorized capital structure. In 2000, 1999, and 1998, the Utility paid dividends on its common and preferred stock of $475 million, $440 million, and $444 million, respectively. The Utility's long-term debt that either matured, was redeemed, or was repurchased during 2000 totaled $597 million. Of this amount, (1) $110 million related to the maturity of its 6.63%, and 6.75% mortgage bonds due June 1, and December 1, 2000, (2) $81 million related to the Utility's repurchase of various pollution control loan agreements, (3) $113 million related to the maturity of the Utility's various medium term notes, (4) $3 million related to the other scheduled maturities of long-term debt, and (5) $290 million related to maturity of rate reduction bonds. The Utility's long-term debt that either matured, was redeemed, or was repurchased during 1999 totaled $672 million. Of this amount, (1) $290 million related to the Utility's rate reduction bonds maturing, (2) $135 million related to the Utility's repurchase of mortgage and various other bonds, (3) $147 million related to maturity of various utility mortgage bonds, and (4) $100 million related to the maturities and redemption of various of the Utility's medium-term notes and other debt. During 2000 and 1999, the Utility did not redeem or repurchase any of its preferred stock. On November 1, 2000, the Utility issued $680 million of five-year, fixed- rate notes and $1,000 million of 364-day floating rate notes. On November 22, 2000, the Utility issued $240 million in floating rate notes. PG&E National Energy Group The California energy crisis has impacted the funding available for new projects at the NEG. The NEG undertook a ringfencing strategy to facilitate access to capital markets and insulate the NEG's assets from the risk of bankruptcy at the Utility. The refinancing of PG&E Corporation's debts on March 2, 2001, further insulates NEG from the risk of bankruptcy at the Utility. General Historically, the NEG has obtained cash from operations, borrowings under credit facilities, non-recourse project financing and other issuances of debt, issuances of commercial paper, and borrowings and capital contributions from PG&E Corporation. These funds have been used to finance operations, service debt obligations, fund the acquisition, development, and/or construction of generating facilities, and to start-up other businesses, finance capital expenditures, and meet other cash and liquidity needs. The projects that the NEG develops typically require substantial capital investment. Some of the projects in which the NEG has an interest have been financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is often secured by interests in the physical assets, major project contracts and agreements, cash accounts, and, in some cases, the ownership interest in that project subsidiary. These financing structures are designed to ensure that the NEG is not contractually obligated to repay the project subsidiary's debt; that is, they are "non-recourse" to the NEG and to its subsidiaries not involved in the project. However, the NEG has agreed to undertake financial support for some of its project subsidiaries in the form of limited obligations and contingent liabilities such as guarantees of specified obligations. To the extent the NEG becomes liable under these guarantees or other agreements in respect of a particular project, it may have to use distributions it receives from other projects to satisfy these obligations. Cash Flows from Operating Activities Cash flow (used by) generated from operations totaled $(77) million, $(41) million, and $(348) million for the years ended December 31, 2000, 1999, and 1998, respectively. The decrease in cash flows for 2000 compared to 1999 of $36 million is attributable to increases in working capital required to support the expanded energy trading operations and a decrease in depreciation expense as a result of the impairment of PG&E GTT assets in 1999. The increase in cash flows generated from operations in 1999 as compared to 1998 of $307 million is due principally to the increase in earnings, excluding the non-cash charge to reflect impairment of the investment in PG&E GTT; an increase in working capital balances of approximately $53 million; realization of gains in energy contracts accounted for on a mark-to-market basis; and increases in the non-cash charges, such as depreciation and the deferred tax provision, partially offset by the increase in the amortization of out-of-market contractual obligations and an increase in capitalized development costs. Cash Flows from Investing Activities The NEG recognized $65 million, $63 million, and $113 million in earnings on investments, which are accounted for using the equity method for 2000, 1999 and 1998, respectively. The NEG received cash distributions from these investments totaling approximately $104 million, $66 million and $69 million during 2000, 1999 and 1998, respectively. Four natural gas-fueled combined-cycle power plants are currently under construction, which when completed will be owned or leased by the NEG. These power plants, referred to as "merchant power plants," will sell power as a commodity in the competitive marketplace. The electricity generated by these plants will be sold on a wholesale basis to local utilities and power marketers, including PG&E ET, which, in turn, will sell it to industrial, commercial, and other electricity customers. Millennium Power, a 360-megawatt (MW) power plant located in Massachusetts, is scheduled to begin commercial service in 2001. Lake Road Generating Plant (Lake Road), an approximately 780-MW power plant located in Connecticut, is scheduled to begin commercial service in 2001. La Paloma Generating Plant, an approximately 1,050-MW power plant, is located in California, and is scheduled to begin commercial service in 2002. Lake Road and La Paloma are being financed through a synthetic lease with a third-party owner. PG&E Gen will operate the plant under operating leases. See Note 14 of the Notes to the Consolidated Financial Statements. The estimated cost to construct these plants is approximately $1.4 billion. In October 2000, the NEG completed construction on an 11.5 MW wind project that is the largest wind generating facility in the Eastern United States for a total cost of $16 million. In September 2000, the NEG purchased the Attala Generating Plant for $311 million. The seller is obligated to deliver a fully operating facility by July 1, 2001. Attala is a 500 MW natural gas-fired combined-cycle project, located in Mississippi. The NEG used $1.3 billion in cash for its investing activities in 1998. During 1998, through its indirect subsidiary USGenNE, the NEG completed the acquisition of a portfolio of electric generating assets and power supply contracts from New England Electric System (NEES). The funding requirements for this acquisition were $1,746 million and included the acquisition of (1) electric generating assets classified as property, plant, and equipment; (2) receivable for support payments of approximately $800 million; and (3) approximately $1,300 million of contractual obligations. The NEES assets include hydroelectric, coal, oil, and natural gas -fueled generation facilities with a combined generating capacity of 4,000 MW. In addition USGenNE assumed 23 multi-year power-purchase agreements representing an additional 800 MW of production capacity. USGenNE entered into agreements with NEES as part of the acquisition, which (1) provide that NEES shall make support payments over the next ten years to USGenNE for the purchase power agreements, and (2) require that USGenNE provide electricity to NEES under contracts that expire over the next six to eleven years. In 1998, the NEG spent approximately $220 million on development and construction activities. Also in 1998, the NEG entered into a sale/leaseback transaction whereby it sold and leased back its Bear Swamp facility, comprised of the Bear Swamp pumped storage station and the Fife Brook station, to a third party. This transaction generated cash proceeds of $479 million. Finally in 1998, the NEG completed the sale of its Australian energy holdings for proceeds of approximately $126 million, and executed some portfolio management transactions, which generated cash proceeds of approximately $22 million. Cash Flows from Financing Activities The NEG maintains $1,350 million in five revolving credit facilities, which support commercial paper and Eurodollar borrowing arrangements. At December 31, 2000 and 1999, the NEG had total outstanding balances related to such borrowings of $1,181 million and $1,173 million, respectively. In addition, certain letters of credit held by the NEG reduce the available outstanding facility commitments. At December 31, 2000, approximately $36 million of letters of credit were outstanding under these facilities. Since the NEG has the ability and intent to refinance certain borrowings, $661 million and $649 million of such borrowings are classified as long-term debt as of December 31, 2000 and 1999, respectively. The remaining outstanding balances are classified as short-term borrowings in the Consolidated Balance Sheets of PG&E Corporation. Capital Requirements The table below provides information about PG&E Corporation's capital requirements at December 31, 2000:
Expected maturity date 2001 2002 2003 2004 2005 Thereafter - ---------------------- ---- ---- ---- ---- ---- ---------- (dollars in millions) Utility: Capital spending $1,505 Long-term debt Variable rate obligations $ 120 $ 697 $ 350 $ 40 $ 40 $ 20 Fixed rate obligations $ 274 $ 379 $ 354 $ 392 $1,012 $ 2,038 Average interest rate 8.0% 7.8% 6.3% 6.4% 6.9% 7.3% Rate reductions bonds $ 290 $ 290 $ 290 $ 290 $ 290 $ 580 Average interest rate 6.2% 6.3% 6.4% 6.4% 6.4% 6.4% National Energy Group: Capital spending $2,445 Long-term debt Variable rate obligations $ 16 $ 94 $ 584 $ 9 $ 9 $ 80 Fixed rate obligations $ 1 $ 34 $ 7 $ 1 $ 251 $ 325 Average interest rate 9.4% 6.9% 7.0% 9.4% 7.1% 8.9%
RESULTS OF OPERATIONS In this section, we discuss the operations of the NEG and present the components of our results of operations for 2000, 1999, and 1998. The table below shows for 2000, 1999, and 1998, certain items from our Statement of Consolidated Operations detailed by Utility and the NEG operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for these groups.) The information for PG&E Corporation (the "Total" column) includes the appropriate intercompany elimination. Following this table we discuss our results of operations. National Energy Group The NEG has been formed to pursue opportunities created by the gradual restructuring of the energy industry across the nation. The NEG integrates our national power generation, gas transmission, and energy trading businesses. The NEG contemplates increasing PG&E Corporation's national market presence through a balanced program of development, acquisition, and contractual control of energy assets and businesses, while at the same time undertaking ongoing portfolio management of its assets and businesses. The NEG's ability to anticipate and capture profitable business opportunities created by industry restructuring will have a significant impact on PG&E Corporation's future operating results. Power Generation We participate in the development, operation, ownership, and management of non-utility electric generating facilities that compete in the United States power generation market. In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generation assets and power supply contracts from NEES. The purchased assets include hydroelectric, coal, oil, and natural gas- fueled generation facilities with a combined generating capacity of about 4,000 MW. As part of the New England electric industry restructuring, the local utility companies were required to offer Standard Offer Service (SOS) to their retail customers. Retail customers may select alternative suppliers at any time. The SOS is intended to provide customers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, followed by a price disincentive that is intended to stimulate the retail market. Retail customers may continue to receive SOS through December 31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island. However, if customers choose an alternate supplier, they are precluded from going back to the SOS. In connection with the purchase of the generation assets, USGenNE entered into wholesale agreements with certain of the retail companies of NEES to supply at specified prices the electric capacity and energy requirements necessary for their retail companies to meet their SOS obligations. These companies are responsible for passing on the revenues generated from the SOS. USGenNE currently is indirectly serving a large portion of the SOS electric capacity and energy requirements for these companies. For the years ended December 31, 2000 and 1999, the SOS price paid to generators was $0.043 and $0.035 per kWh for generation, respectively. Like other utilities, New England utilities previously entered into agreements with unregulated companies (e.g., qualifying facilities under Public Utilities Regulatory Policies Act (PURPA)) to provide energy and capacity at prices that are anticipated to be in excess of market prices. The NEG assumed NEES' contractual rights and duties under several of these power purchase agreements. At December 31, 2000, these agreements provided for an aggregate 470 MW of capacity. NEES will make support payments to us toward the cost of these agreements. The remaining support payments by NEES total $0.8 billion in the aggregate (undiscounted) and are due in monthly installments through January 2008. In certain circumstances, with our consent, NEES may make a full or partial lump sum accelerated payment. Currently, approximately 60% to 70% of the capacity is dedicated to serving SOS customers. To the extent that customers eligible to receive SOS choose alternate suppliers, or as these obligations are sold to other parties, this percentage will continue to decrease. As customers choose alternate suppliers, or the SOS obligations are sold, a greater proportion of the output of the acquired operating capacity will be subject to market prices. Gas Transmission Operations The NEG, through PG&E GTN, owns and operates gas transmission pipelines and associated facilities, subject to regulation by the Federal Energy Regulatory Commission (FERC). The pipeline and associated facilities extend over 612 miles from the Canada-U.S. border to the Oregon-California border. PG&E GTN provides firm and interruptible transportation services to third-party shippers on an open-access basis. Its customers are principally retail gas distribution utilities, electric generators that use natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, natural gas producers, and industrial consumers. On January 27, 2000, PG&E Corporation signed a definitive agreement with El Paso Field Services Company (El Paso) providing for the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of PG&E GTT. Given the terms of the sales agreement, in 1999, PG&E Corporation recognized a charge against pre-tax earnings of $1,275 million, to reflect PG&E GTT's assets at their fair value. On December 22, 2000, after receipt of governmental approvals, PG&E Corporation completed the stock sale. The sales agreement had a provision, which included a sales price adjustment for changes in working capital from December 31, 1999 to closing. The total consideration received was $456 million, which includes the working capital adjustment, less $150 million used to retire the PG&E GTT short-term debt, and the assumption by El Paso of PG&E GTT long-term debt having a book value of $565 million. In December 2000, PG&E Corporation recorded income of approximately $20 million reflecting the sales price true-up. Energy Trading The NEG's trading businesses purchase bulk volumes of power and natural gas from the NEG's affiliates and the wholesale market. The NEG then transports and resells these commodities, either directly to third parties or to other PG&E Corporation affiliates. The NEG also provides risk management services to other NEG businesses and to wholesale customers. (See "Price Risk Management Activities" below; and Note 4 of the Notes to the Consolidated Financial Statements.) Energy Services In December 1999, PG&E Corporation's Board of Directors approved a plan to dispose of PG&E ES, its wholly owned subsidiary, through a sale. The disposal has been accounted for as a discontinued operation, and PG&E Corporation's investment in PG&E ES was written down to its then estimated net realizable value. In addition, PG&E Corporation provided a reserve for anticipated losses through the anticipated date of sale. The total provision for discontinued operations was $58 million, net of income taxes of $36 million. Of this amount, $33 million (net of taxes) was allocated toward operating losses for the period leading up to the intended disposal date. In 2000, $31 million (net of taxes) of actual operating losses were charged against this reserve. During the second quarter of 2000, the NEG finalized the disposal of the energy commodity portion of PG&E ES for $20 million, plus net working capital of approximately $65 million, for a total of $85 million. In addition, the sale of the Value-Added Services business and various other assets was completed on July 21, 2000, for a total consideration of $18 million. For the year ended December 31, 2000, an additional estimated loss of $40 million (or $0.11 per share), net of income tax of $36 million, was recorded. The additional loss was greater than the amount originally provided for several reasons: (1) the sale was originally contemplated to be a sale of the entity as a whole; (2) it was ultimately sold in various pieces; (3) several assets were not sold and were subsequently abandoned; and (4) wind-down costs associated with abandoned assets were greater than originally contemplated. In addition, the worsening energy situation in California also contributed to the additional loss incurred.
PG&E National Energy Group --------------------------- PG&E GT ------- (in millions) Utility PG&EGen NW Texas PG&E ET Eliminations & Total Other/(1)/ 2000: Operating revenues $ 9,637 $ 1,211 $ 239 $ 873 $ 16,054 $ (1,782) $ 26,232 Operating expenses 14,838 1,073 105 869 15,974 (1,820) 31,039 Operating loss (4,807) Interest income 266 Interest expense (788) Other income (expense), net (23) Income taxes (2,028) Loss from continuing operations (3,324) Net loss (3,364) Net cash used by operating activities (776) Net cash used by investing (970) activities Net cash provided by financing 2,364 activities
EBITDA/(2)/ $(1,244) $ 227 $176 $ 108 $ 91 $ (55) $ (697) 1999: Operating revenues $ 9,228 $1,122 $224 $ 1,148 $10,521 $(1,423) $20,820 Operating expenses 7,235 1,007 104 2,446 10,582 (1,432) 19,942 Operating income 878 Interest income 118 Interest expense (772) Other income (expense), net 37 Income taxes 248 Income from continuing operations 13 Net loss (73) Net cash provided by operating activities 2,155 Net cash used by investing activities (117) Net cash used by financing activities (2,043) EBITDA/(2)/ $ 3,523 $ 203 $181 $(1,178) $ (53) $ 19 $ 2,695 1998: Operating revenues $ 8,924 $ 649 $237 $ 1,941 $ 8,509 $ (683) $19,577 Operating expenses 7,048 489 101 1,996 8,528 (683) 17,479 Operating income 2,098 Interest income 101 Interest expense (781) Other income (expense), net (36) Income taxes 611 Income from continuing operations 771 Net income 719 Net cash provided by operating 3,388 activities Net cash used by investing activities (2,226) Net cash used by financing activities (1,113) EBITDA/(2)/ $ 3,294 $ 200 $177 $ 15 $ (15) $ (7) $ 3,664
(1) Net income on intercompany positions recognized by segments using mark-to- market accounting is eliminated. Intercompany transactions are also eliminated. (2) EBITDA is defined as income before provision for income taxes, interest expense, interest income, deferred electric procurement costs, depreciation and amortization, provision for loss on generation-related assets and undercollected purchased power costs. EBITDA is not intended to represent cash flows from operations and should not be considered as an alternative to net income as an indicator of the PG&E Corporation's operating performance or to cash flows as a measure of liquidity. Refer to the Statement of Cash Flows for the U.S. GAAP basis cash flows. PG&E Corporation believes that EBITDA is a standard measure commonly reported and widely used by analysts, investors, and other interested parties. However, EBITDA as presented herein may not be comparable to similarly titled measures reported by other companies. Overall Results PG&E Corporation's financial position and results of operations are impacted by the ongoing California energy crisis. Please see the Liquidity and Financial Resources section and Note 2 of the Notes to the Consolidated Financial Statements for more information on the California energy crisis. Net loss for the year ended December 31, 2000 increased to $3,364 million from a net loss of $73 million for the same period in 1999. Of the $3,291 million increase, the Utility's net loss allocated to common stock for the year ended December 31, 2000 accounted for $4,271 million of the increase, partially offset by an increase in the NEG net income of $980 million. The decrease in performance of 2000 compared to 1999 results of operations is attributable to the following factors: . The Utility's earnings were impacted as a result of the write-off of its remaining generation related regulatory assets and undercollected purchased power costs ($4.1 billion, after taxes). Because of the substantial uncertainty created by the California energy crisis, the Utility can no longer conclude that energy costs, which had been deferred on its balance sheets, are probable of recovery. Under Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulations," if a rate mechanism provided by legislation or other regulatory authority were subsequently established that made recovery from regulated rates probable as to all or a portion of the undercollection that was previously charged against earnings, a regulatory asset would be reinstated with a corresponding increase in earnings. . As a result of the high cost of power, with no offsetting revenues, the Utility and PG&E Corporation had a net loss for California tax purposes. California law does not permit carrybacks of such losses and only permits carryforwards of 55% of such losses. As a result, PG&E Corporation was unable to recognize $79 million of state tax benefits because of California law. Income tax expense was also higher due to depreciation adjustments and a reduction in investment tax credits. . In 2000, the Utility recorded a provision ($83 million, after tax) for potential losses associated with litigation discussed in Note 15 of the Notes to the Consolidated Financial Statements. . At the end of 1999, PG&E Corporation announced its plans to dispose of PG&E GTT, and these assets were written down to estimated fair value resulting in a charge of $890 million ($2.24 per share). PG&E GTT has operated at a breakeven basis in 2000, while it reported a net loss from operations of $7 million ($0.02 per share) in 1999. These operations were sold on December 22, 2000. . Also at the end of 1999, PG&E Corporation announced its plans to dispose of PG&E ES and these assets were written down to net realizable value. PG&E ES operated at a loss during 2000. However, those losses were charged against reserves established in 1999 and did not impact the current results from operations, while PG&E ES reported losses of $98 million ($0.27 per share) for 1999. Additionally, during the later half of 2000, PG&E Corporation recorded after-tax charges of $40 million ($0.11 per share) to reflect the closing of transactions to dispose of the retail energy services business and related commodity portfolio. . PG&E ET's net income in 2000, net of restructuring charges of $13 million after-tax ($0.04 per share) related to the move of natural gas trading operations from Houston, Texas, to Bethesda, Maryland, increased $57 million compared to 1999 results due to across the board improvements in natural gas and power trading, asset management, and structured transactions. While trading in electric commodities has generally been profitable, the results of the gas trading operations have improved significantly as a result of structured transactions. Additionally, the gas trading operations benefited from the highest gas prices in a number of years. The power trading operations have been able to benefit from volatile prices throughout the United States. . PG&E Gen and PG&E GTN earnings decreased slightly from 1999 levels, primarily attributable to a decline in operating results in the generating business and a decrease in operating income at PG&E GTN primarily as a result of settlements received in the amount of $19 million for negotiations regarding transportation contracts and other related issues, resulting in the restructuring and/or termination of these transportation contracts in 1999 with no similar transactions in 2000. The effective tax rate for PG&E Corporation has decreased to 37.9% in 2000 compared to 95.0% in the prior year as a result of a higher effective tax rate in 1999, largely due to the disposition of PG&E GTT which resulted in a capital loss for tax purposes, which could not be fully recognized. The decrease in performance of 1999 over 1998 results of operations is attributable to the following factors: . PG&E Corporation had a net loss in 1999 of $73 million, or $0.20 per share. In 1998 PG&E Corporation had net income of $719 million, or $1.88 per share. The decrease was principally due to the write-down to fair value of the natural gas business in Texas and the accrual for the discontinuance of operations of the Energy Services segment. The PG&E GTT write-down was approximately $890 million after taxes or $2.42 per share and is comprised of the following pre-tax amounts: $819 million write-down of net property, plant, and equipment, $446 million write-down of goodwill, and an accrual of $10 million for selling costs. The PG&E ES discontinued operations generated a charge of $58 million after tax. . Partially offsetting these charges were increases in Utility income of $153 million or $0.42 per share, primarily as a result of the 1999 General Rate Case. . Also increasing income was an adjustment of a litigation reserve at GTT, associated with a court-approved settlement proposal in the amount of $35 million after tax. . The 1998 income from continuing operation also included a loss on the sale of the Australian energy holdings of $23 million, or $0.06 per share, without a similar charge in 1999. . In addition, PG&E Gen changed its method of accounting for major maintenance and overhauls at its generating facilities. Beginning January 1, 1999, the cost of major maintenance and overhauls, principally at the PG&E Gen business segment, has been accounted for as incurred. The change resulted in PG&E Corporation recording income of $12 million after-tax ($0.03 per share), reflecting the cumulative effect of the change in accounting principle for the year ended December 31, 1999. PG&E Corporation has recorded income tax expense of $248 million for 1999. The effective tax rate primarily results from two factors: (1) electric industry restructuring has resulted in the reversal of temporary differences whose tax benefits were originally flowed through to customers causing an increase in income tax expense independent of pre-tax income, and (2) the disposition of PG&E GTT resulted in a capital loss for tax purposes, which could not be fully recognized. Dividends PG&E Corporation's historical quarterly common stock dividend was $0.30 per common share, which corresponded to an annualized dividend of $1.20 per common share. On January 10, 2001, the Board of Directors of PG&E Corporation suspended the payment of its fourth quarter 2000 common stock dividend of $0.30 per share declared by the Board of Directors on October 18, 2000 and payable on January 15, 2001 to shareholders of record as of December 15, 2000. The California energy crisis had created a liquidity crisis for PG&E Corporation, which led to the suspension of payments of dividends to conserve cash resources. These defaulted dividends were later paid on March 2, 2001 in conjunction with the refinancing of PG&E Corporation obligations, discussed above under the Liquidity and Financial Resources section. Additionally, the parent company refinancing agreements mentioned above prohibit dividends from being declared or paid until the term loans have been repaid. The agreement is for a term of two years with an option on behalf of PG&E Corporation to extend the term for an additional year. On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $110 million, declared in October 2000, to PG&E Corporation and its wholly owned subsidiary PG&E Holdings, Inc. Until its financial condition is restored, the Utility is precluded from paying dividends to PG&E Corporation and PG&E Holdings, Inc. Utility Overall Results The Utility's net loss allocated to common stock was $3,508 million in 2000 as compared to 1999 net income of $763 million. The decrease was primarily the result of the write-off of its remaining generation-related regulatory assets and undercollected purchased power costs, a provision for potential litigation losses, and higher income tax expense as mentioned previously. The Utility's net income available for common stock increased to $763 million in 1999 as compared to 1998 net income of $702 million, primarily because of the impacts of the 1999 General Rate Case (GRC). Operating Income Operating loss for the Utility was $5,201 million in 2000 as compared to operating income of $1,993 million in 1999. This decrease in the Utility's operating income was primarily due to the write-off of its remaining generation related regulatory assets and undercollected purchased power costs. In addition, it is attributable to a provision for potential litigation losses and a lower return on its assets, due to the sale of a portion of the Utility's generating assets and the ongoing recovery of transition costs. Operating income for the Utility was $1,993 million in 1999 as compared to $1,876 million in 1998. This increase was primarily because of the impacts of the 1999 GRC. However, the increases from the GRC were partially offset by a reduction in the Utility's authorized cost of capital and a lower return on its assets due to the sale of a significant portion of its generating assets and recovery of transition costs. Operating Revenues The following table shows the components of the Utility's electric revenue by customer class, natural gas revenues, and total revenues for the years ended December 31:
2000 1999 1998 Residential $3,351 $3,294 $3,198 Commercial 2,804 2,940 2,883 Total residential and commercial 6,155 6,234 6,081 Legislative discount (453) (435) (396) Revenues from residential and commercial 5,702 5,799 5,685 Industrial 509 864 933 Agriculture 386 392 351 Miscellaneous 257 177 222 Total electric operating revenues $6,854 $7,232 $7,191 Total gas operating revenues $2,783 $1,996 $1,733 Total operating revenues $9,637 $9,228 $8,924
Utility operating revenues increased $409 million or 4.4% to $9,637 million in 2000 compared to $9,228 million in 1999. The increase in operating revenues for 2000, as compared to 1999, related primarily to higher gas prices, which are passed on to customers and collected in gas revenues, partially offset by a decrease in electric revenues. The average price of gas per thousand cubic feet was $4.92 in 2000 and $2.47 in 1999. Gas sales volumes for bundled sales and transportation decreased by 9% from 1999 sales volumes due to warmer winter weather, while gas sales volumes for transportation-only service increased by 25% due to increased demands by electric generators to meet air-conditioning loads due to warmer summer weather and new transportation contracts. Electric sales volumes increased for all customer classes, resulting in an overall increase of 3% over 1999 sales volumes. Electric revenues from industrial and commercial customers decreased because of higher wholesale power market prices and resulting credits issued to direct access customers. These customers, principally large industrial companies, procure electricity from independent generators under long-term contracts and receive a credit on their utility bills at prevailing market prices. In accordance with CPUC regulations, the Utility provides an energy credit to those customers (known as direct access customers) who have chosen to buy their electric generation energy from an energy service provider (ESP) other than the Utility. The Utility bills direct access customers based upon fully bundled rates (generation, distribution, transmission, public purpose programs, and a competition transition charge). However, the direct access customer receives an energy credit equal to the PX price for wholesale electricity (calculated as the average market prices multiplied by customer energy usage for the period), with the customer being obligated to their ESP at their direct access contract rate. As wholesale power prices began to increase in June 2000, the level of PX credits increased correspondingly to the point where the credits exceeded the Utility's distribution and transmission charges to direct access customers. During 2000, the PX credits reduced electric revenue by $472 million, although the Utility ceased paying most of these credits in December 2000. As of March 29, 2001, the estimated total of accumulated credits for direct access customers that have not been paid by the Utility is approximately $503 million. Such amounts are reflected on the Utility's balance sheet. The actual amount that will be refunded to ESPs will be dependent upon when the rate freeze ends and whether there are any adjustments made to wholesale energy prices by FERC. Utility operating revenues increased $304 million or 3.4% in 1999 as compared to 1998. This increase is primarily due to: (1) a $147 million increase in gas revenues from residential and commercial gas customers due to higher usage, (2) a $93 million increase in gas revenues as a result of the GRC, (3) a $43 million increase in revenues from small and medium electric customers due to increased customers, and (4) a $16 million increase in revenues from an increase in gas transportation volumes. Operating Expenses Utility operating expenses increased $7,603 million in 2000 compared to 1999. The tables below summarize the changes in the Utility's operating expenses:
For the Year ended December 31, ----------- Increase Increase (in millions) 2000 1999 (Decrease) (Decrease) Cost of electric energy, net $ 6,741 $2,411 $ 4,330 179.6% Deferred electric procurement costs (6,465) -- (6,465) -- Cost of gas 1,425 738 687 93.1% Operating and maintenance, net 2,687 2,522 165 6.5% Depreciation, amortization, and decommissioning 3,511 1,564 1,947 124.5% Provision for loss on generation related regulatory assets and purchased power costs 6,939 -- 6,939 -- Total $14,838 $7,235 $ 7,603 105.1% For the Year ended December 31, ----------- Increase Increase (in millions) 1999 1998 (Decrease) (Decrease) Cost of electric energy, net $ 2,411 $2,321 $ 90 3.9% Cost of gas 738 621 117 18.8% Operating and maintenance, net 2,522 2,668 (146) (5.5%) Depreciation, amortization, and decommissioning 1,564 1,438 126 8.8% Total $ 7,235 $7,048 $ 187 2.7%
The overall increase in operating expenses is primarily attributable to the write-off of the Utility's transition cost regulatory assets and undercollected purchased power costs. In addition, operating expenses increased due to increases in the cost of gas during the latter half of 2000. The average price the Utility paid per thousand cubic feet of gas was $4.92 in 2000 and $2.47 in 1999. Wholesale electric energy costs increased significantly during the latter half of 2000. The average monthly costs per kWh of purchased power during the latter half of 2000 were: June (16.33 cents), July (11.00 cents), August (18.70 cents), September (13.82 cents), October (13.62 cents), November (20.43 cents), and December (33.24 cents). The amount of purchased power costs in excess of the revenue for the generation component of frozen rates was reflected as deferred electric procurement costs prior to the year-end write-off described above. Revenues for the generation component of frozen rates were approximately 5.4 cents per kWh during 2000. Depreciation, amortization, and decommissioning increased $1,947 million in 2000. The increase resulted primarily from an increase in recovery of transition costs resulting from higher revenues from sales to the PX of Utility-owned generation, including Diablo Canyon, and generation from QFs and other providers. As mandated by the CPUC, these revenues, in excess of the related costs, must be used to recover transition costs. See Note 2 of the Notes to the Consolidated Financial Statements. The Utility's operating expenses increased $187 million in 1999 as compared to 1998. This increase reflected the increased cost of gas due to higher usage and the increased amortization of electric transition costs, partially offset by a decrease in operating and maintenance expense resulting from fewer owned- generation facilities in 1999 as a result of divestitures. Dividends Dividends paid to PG&E Corporation increased from $440 million in 1999 to $475 million in 2000, maintaining the CPUC-mandated capital structure. Dividends paid to PG&E Corporation in 1998 were $444 million. Dividends paid to preferred shareholders remained at the same level of $25 million in 2000 and 1999. Dividends paid to preferred shareholders decreased from $29 million in 1998 to $25 million in 1999, primarily as a result of redemptions. As previously discussed, the Utility has suspended payment of its common and preferred dividends. Dividends on preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock. PG&E National Energy Group Operating Income Operating income at the NEG increased $1,509 million in 2000 as compared to 1999, primarily related to the charge to write PG&E GTT down to its net realizable value in 1999 with no similar charge occurring in 2000. Additionally, all business units reflected improved operating results over the prior year, despite a $22 million charge related to the relocation of the energy trading operations from Houston, Texas, to Bethesda, Maryland. Operating income of the NEG decreased $62 million in 1999 as compared to 1998, excluding the charge to write PG&E GTT down to its net realizable value. The decline resulted from mild weather in the Northeast, lower interruptible transport revenue in the Pacific Northwest, less portfolio management activity, and trading losses in the U.S. gas portfolio. This decline was partially offset by cost containment efforts across the organization and an increase in the differential between natural gas liquids prices and the cost of natural gas. Operating Revenues The NEG operating revenues increased $5,003 million in 2000 compared to 1999. The NEG has focused its trading efforts on asset management and higher- margin trades, resulting in increased trading volume of electric commodities principally in the Southeast and Midwest. In addition, increases in the price of power and gas have resulted in increased revenues. The NEG's 1999 operating revenues increased $939 million as compared to 1998, principally due to: (1) the PG&E Gen business segment receiving a full year of revenue from the New England assets acquired in September 1998, and (2) increases in trading revenues at PG&E ET reflecting the further maturation of its business. The 1999 operating revenues also reflected revenue increases at PG&E GTT resulting from an improved differential between the natural gas liquids prices and the incoming natural gas. These revenue increases were partially offset by (1) a decline in interruptible revenues in the Northwest due to the lower natural gas prices in the Southwest as compared to Canadian prices, and (2) lower transportation revenue on the Texas transmission system. Operating Expenses Operating expenses at the NEG increased $3,494 million in 2000 compared to the prior year. The increase results from the increased trading volumes discussed above, and increases in the cost of power and gas, partially offset by reduced depreciation and amortization expense at PG&E GTT reflective of the disposal of the PG&E GTT assets. The NEG's operating expenses increased $2,276 million in 1999 as compared to 1998, due to the charge associated with the disposition of PG&E GTT, a full year of operating expenses associated with the generation facilities in New England, and growth of PG&E ET operations. Dividends The NEG currently intends to retain any future earnings to fund the development and growth of its business. Further, the NEG is precluded from paying dividends, unless it meets certain financial tests. Therefore, it is not anticipating paying any cash dividends on its common stock in the foreseeable future. REGULATORY MATTERS A significant portion of PG&E Corporation's operations is regulated by federal and state regulatory commissions. These commissions oversee service levels and, in certain cases, PG&E Corporation's revenues and pricing for its regulated services. Following are the percentages of 2000 revenues that fell under the jurisdiction of these various regulatory agencies: Utility Consolidated Cost of service-based 96.3% 39.2% Market 3.7% 60.8% The Utility is the only subsidiary with significant regulatory proceedings at this time. The Utility's significant regulatory proceedings are discussed below. Regulatory proceedings associated with electric industry restructuring are discussed above in "The California Energy Crisis." See Note 2 of the Notes to the Consolidated Financial Statements. The Utility's General Rate Case The CPUC authorizes an amount known as "base revenues" to be collected from ratepayers to recover the Utility's basic business and operational costs for its gas and electric distribution operations. Base revenues, which include non-fuel- related operating and maintenance costs, depreciation, taxes, and a return on invested capital, currently are authorized by the CPUC in GRC proceedings. The CPUC's final decision in the Utility's 1999 GRC application increased annual electric distribution revenues by $163 million and annual gas distribution revenues by $93 million over 1998 authorized base revenues. In March 2000, two interveners filed applications for rehearing of the 1999 GRC decision, alleging that the CPUC committed legal errors by approving funding in certain areas that were not adequately supported by record evidence. In April 2000, the Utility filed its response to these applications for rehearing, defending the GRC decision against the allegations of error. A CPUC decision on the applications for rehearing is pending. In the 1999 GRC decision the CPUC ordered that the Utility file a 2002 GRC. As a result of the current energy crisis, the procedural schedule has been delayed pending the CPUC's resolution of the Utility's request that it be permitted to file an alternative schedule or an alternative to the 2002 GRC. An earlier decision initially delaying the schedule affirms that rates would still become effective on January 1, 2002, although the CPUC decision may not be rendered until after that date. Order Instituting Investigation (OII) into Holding Company Activities On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned utilities, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities' transfer of money to their holding companies since deregulation of the electric industry commenced, including during times when their utility subsidiaries were experiencing financial difficulties; (2) the failure of the holding companies to financially assist the utilities when needed; (3) the transfer by the holding companies' of assets to unregulated subsidiaries; and (4) the holding companies' action to "ring fence" their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies (including penalties), prospective rules, or conditions, as appropriate. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. As described above, on April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the Utility believe that to the extent the CPUC seeks to investigate past conduct for compliance purposes, the investigation is automatically stayed by the bankruptcy filing. Neither the Utility nor PG&E Corporation can predict what the outcome of the investigation will be or whether the outcome will have a material adverse effect on their results of operation or financial condition. The Utility's 2001 Attrition Rate Adjustment (ARA) In July 2000, the Utility filed an ARA application with the CPUC to increase its 2001 electric distribution revenues by $189 million, effective January 1, 2001. The increase reflects inflation and the growth in capital investments necessary to serve customers. The Utility did not request an increase in gas distribution revenues. In December 2000, the CPUC issued an interim order finding that a decision on the application cannot be rendered by January 1, 2001, and determining that if attrition relief is eventually granted, that relief will be effective as of January 1, 2001. Hearings are scheduled to begin in June 2001, and a CPUC decision is expected by January 2002. The Utility's Cost of Capital Proceedings Each year, the Utility files an application with the CPUC to determine the authorized rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. Since February 17, 2000, the Utility's adopted return on common equity (ROE) has been 11.22% on electric and gas distribution operations, resulting in an authorized 9.12% overall rate of return (ROR). The Utility's earlier adopted ROE was 10.6%. The adopted ROR for 2000 resulted in an increase of approximately $49 million over 1999 electric and gas distribution revenues. In May 2000, the Utility filed an application with the CPUC to establish its authorized ROR for electric and gas distribution operations for 2001. The application requests an ROE of 12.4%, and an overall ROR of 9.75%. If granted, the requested ROR would increase electric distribution revenues by approximately $72 million and gas distribution revenues by approximately $23 million. The application also requests authority to implement an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would replace the annual cost of capital proceedings. The proposed adjustment mechanism would modify the Utility's cost of capital based on changes in an interest rate index. The Utility also proposes to maintain its currently authorized capital structure of 46.2% long-term debt, 5.8% preferred stock, and 48% common equity. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22% ROE for test year 2001. This authorized ROE results in a corresponding 9.12% return on rate base and no change in the Utility's electric or gas revenue requirement for 2001. A final CPUC decision is expected in the second quarter of 2001. The Utility's FERC Transmission Rate Cases Since April 1998, electric transmission revenues have been authorized by the FERC, including various rates to recover transmission costs from the Utility's former bundled retail transmission customers. The FERC has not yet acted upon a settlement filed by the Utility that, if approved, would allow the Utility to recover $345 million in electric transmission rates for the 14-month period of April 1, 1998 through May 31, 1999. During this period, somewhat higher rates have been collected, subject to refund. A FERC order approving this settlement is expected by the end of 2001. The Utility has accrued $24 million for potential refunds related to the period ended May 31, 1999. In April 2000, the FERC approved a settlement that permits the Utility to recover $264 million in electric transmission rates retroactively for the 10-month period from May 31, 1999 to March 31, 2000. In September 2000, the FERC approved another settlement that permits the Utility to recover $340 million annually in electric transmission rates and made this retroactive to April 1, 2000. Further, in November 2000, the FERC accepted, subject to refund, the Utility's proposal to collect $397 million annually in electric transmission rates beginning on May 6, 2001. The Utility's Catastrophic Event Memorandum Account Proceeding In April 2000, the CPUC approved a settlement agreement in a proceeding addressing the Catastrophic Events Memorandum Account. The settlement provided for a $59 million increase in electric distribution revenue requirement and an $11 million increase in gas distribution revenue requirement which was collected through rates during 2000. The increase compensates the Utility for costs incurred for several emergencies, including the 1991 Oakland Hills Fire and the 1998 storms. The Utility's Electric Base Revenue Increase Proceeding Section 368(e) of the California Public Utilities Code was adopted as part of the California electric industry restructuring legislation. It provided for an increase in the Utility's electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. In accordance with Section 368(e), the CPUC authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC authorized an additional base revenue increase of $77 million. Section 368(e) expenditures are subject to review by the CPUC. In July 1999, the Office of Ratepayer Advocates; a division of the CPUC, (ORA) recommended a disallowance of $88.4 million in Section 368(e) expenditures for 1997 and 1998. In August 1999, The Utility Reform Network (TURN) recommended an additional $14 million disallowance for a total recommended disallowance for 1997 and 1998 expenditures of $102.4 million. The Utility opposed the recommended disallowances and hearings were held in October 1999. It is uncertain when a proposed decision will be issued by the CPUC. Any proposed decision would be subject to comment by the parties and change by the CPUC before a final decision is issued. The Utility does not expect a material impact on its financial position or results of operations resulting from these matters. The Utility's Performance-Based Ratemaking (PBR) Application In June 2000, the CPUC granted the Utility's request to withdraw its PBR application filed in November 1998. The Utility had requested the withdrawal in accordance with the 1999 GRC decision issued in February 2000, which required a 2002 GRC before a PBR mechanism could be implemented. In closing the PBR proceeding, the CPUC ordered the Utility to file a new PBR application by September 2000. This application would propose financial rewards and penalties associated with utility performance in meeting prescribed standards for measures such as electric reliability and customer service. In September 2000, the Utility filed an application with the CPUC to establish (1) performance standards and associated financial rewards and penalties for electric and gas distribution service, (2) a revenue-sharing mechanism for new categories of non-tariffed products and services (NTP&S) offered by the Utility, and (3) ratemaking for proceeds from sales or transfers of certain non-generation related land. The performance standards would cover a period of five years commencing January 1, 2001. The total maximum annual reward or penalty is $54 million per year, consisting of $52 million for electric distribution and $2 million for gas distribution. The revenue-sharing mechanism proposes to share net positive after-tax revenues from new categories of NTP&S equally between ratepayers and shareholders. Finally, the Utility requested that the CPUC establish basic rules about the allocation of gains and losses from the Utility's non-generation-related land sales. In November 2000, the CPUC suspended the proceeding until further notice. MUNICIPALIZATION AND OTHER COMPETITION With the uncertainties over future electric utility rates due to the California energy crisis, municipalization is under consideration by many local governments in California. Municipalization is the attempt by cities and local utility districts to take over markets from private, investor-owned utility companies. Local governments in California are increasingly looking at entering the utility business as a source of new revenue. Those that already have municipal utilities are examining expansion to provide new services or to sell existing services outside of their current boundaries. Municipalization efforts in San Francisco, Berkeley, and San Diego (among several other California cities) are being pursued by grass roots organizations and proposals to municipalize may go before voters. We cannot currently predict what the outcome will be from these actions. As wholesale electric prices increase, alternatives to the current model become more attractive. These alternative technologies, such as distributed generation which enables siting of smaller electric generation facilities in close proximity to the electric demand, have the potential to strand Utility investment and make recovery more challenging. The CPUC has opened a rulemaking proceeding to examine various issues concerning distributed generation, including interconnection issues, who can own and operate distributed generation, environmental impacts, the role of utility distribution companies, and the rate design and cost allocation issues associated with the deployment of distributed generation facilities. This rulemaking is also intended to address other areas of potential electric competition, such as billing services. There has been little activity in this rulemaking since its issuance in 1999. ENVIRONMENTAL MATTERS We are subject to laws and regulations established to both maintain and improve the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove those substances or remedy effects on the environment. See Note 15 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters. Utility The Utility records an environmental remediation liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. At December 31, 2000, the Utility expects to spend $320 million, undiscounted, for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility could spend as much as $462 million on these costs. The Utility estimates the upper limit of the range 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 clean-up costs at additional sites or expected outcomes change. The Utility had an environmental remediation liability of $320 million and $271 million at December 31, 2000 and 1999, respectively. The $320 million accrued at December 31, 2000 includes (1) $114 million related to the pre- closing remediation liability, associated with divested generation facilities (see further discussion in the "Generation Divestiture" section of Note 2 of the Notes to the Consolidated Financial Statements), and (2) $180 million related to remediation costs for those generation facilities that the Utility still owns, manufactured gas plant sites, and gas gathering compressor stations. Of the $320 million environmental remediation liability, the Utility has recovered $168 million through rates, and expects to recover another $87 million in future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate. In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings. In March 2000, the Central Coast Board requested the Utility to provide specific information regarding the "backflush" procedure used at Moss Landing. The Utility provided the requested information to the Board in April 2000. The Utility's investigation indicated that while it owned Moss Landing, significant amounts of water were discharged from the cooling water intake. While the Utility's investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes that the temperature of the discharged water was higher than that of the ambient receiving water. In December 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which the Utility would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. Settlement negotiations are continuing. The Utility's Diablo Canyon employs a "once through" cooling water system which is regulated under a NPDES Permit issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shell fish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order (CDO) alleging that, although the temperature limit has never been exceeded, the Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology reflects "best technology available" under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in California Superior Court. The Utility believes the ultimate outcome of these matters will not have a material impact on the Utility's financial position or results of operations. PG&E National Energy Group In October and November 1999, the U.S. Environmental Protection Agency (EPA) and several states filed suits or announced their intention to file suits against a number of coal-fired power plants in Midwestern and Eastern states. These suits relate to alleged violations of the Clean Air Act. More specifically, they allege violations of the deterioration prevention and non- attainment provisions of the Clean Air Act's new source review requirements arising out of certain physical changes that may have been made at these facilities without first obtaining the required permits. In May 2000 the NEG received a request for information seeking detailed operating and maintenance histories for the Salem Harbor and Brayton Point power plants. If EPA were to find that there were physical changes in the past that were undertaken without first receiving the required permits under the Clean Air Act, then penalties may be imposed and further emission reductions might be necessary at these plants. In addition to the EPA, states may impose more stringent air emissions requirements. The Commonwealth of Massachusetts is considering the adoption of more stringent air emission reductions from electric generating facilities. If adopted, these requirements will impact Salem Harbor and Brayton Point. The NEG has proposed an emission reduction plan that may include modernization of the Salem Harbor power plant and use of advanced technologies for emissions removal. It is also studying various advanced technologies for emissions removal for the Brayton Point power plant. The NEG's subsidiary, USGenNE, has proposed a number of state and regional initiatives that will require it to achieve significant reductions of emissions by 2010. The NEG expects that USGenNE will meet these requirements through a combination of installation of controls, use of emission allowances it currently owns, and purchase of additional allowances. The NEG currently estimates that USGenNE's total capital cost for complying with these requirements will be approximately $300 million. PG&E Gen's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending. It is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $55 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits. During September 2000, USGenNE signed a series of agreements that require, among other things, that USGenNE alter its existing waste water treatment facilities at two facilities by replacing certain unlined treatment basins, submit and implement a plan for the closure of such basins, and perform certain environmental testing at the facilities. USGenNE has incurred $4 million in 2000 and expects to complete the required steps on or before December 2001. The total expected cost of these improvements is $21 million. Inflation Financial statements, which are prepared in accordance with accounting principles generally accepted in the United States of America, report operating results in terms of historical costs and do not evaluate the impact of inflation. Inflation affects our construction costs, operating expenses, and interest charges. In addition, the Utility's electric revenues do not reflect the impact of inflation due to the current electric rate freeze. However, inflation at current levels is not expected to have a material adverse impact on PG&E Corporation's or the Utility's financial position or results of operations. Quantitative and Qualitative Disclosures About Market Risk Price Risk Management Activities We have established a risk management policy that allows derivatives to be used for both trading and non-trading 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 PG&E Corporation's or the Utility's primary market risk exposures, which include commodity price risk, interest rate risk, and foreign currency risk. We also participate in markets using derivatives to gather market intelligence, create liquidity, and maintain a market presence. Such derivatives include forward contracts, futures, swaps, options, and other contracts. Net open positions often exist or are established due to PG&E Corporation's and the Utility's assessment of their responses to changing market conditions. To the extent that PG&E Corporation has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial results. PG&E Corporation and the Utility may only engage in the trading of derivatives in accordance with policies established by the PG&E Corporation Risk Management Committee. Trading is permitted only after the Risk Management Committee authorizes such activity subject to appropriate financial exposure limits. Under PG&E Corporation, both the NEG and the Utility have their own Risk Management Committees that address matters relating to those companies' respective businesses. These Risk Management Committees are comprised of senior officers. Market Risk Commodity Price Risk Commodity price risk is the risk that changes in market prices will adversely affect earnings and cash flows. PG&E Corporation is primarily exposed to the commodity price risk associated with energy commodities such as electricity and natural gas. Therefore, PG&E Corporation's price risk management activities primarily involve buying and selling fixed-price commodity commitments into the future. In compliance with regulatory requirements, the Utility manages price risk independently from the activities in PG&E Corporation's unregulated business. Price risk activities consist of the use of non-trading (hedging) financial instruments to reduce the impact of commodity price fluctuations for electricity and natural gas. While the use of these instruments has been authorized by the CPUC, the CPUC has yet to establish rules around how it will judge the reasonableness of these instruments. Gains and losses associated with the use of the majority of these financial instruments primarily affect regulatory accounts, depending on the business unit and the specific program involved. In response to high wholesale electricity costs experienced during the summer of 2000, the CPUC in August 2000 eliminated the requirement to procure electricity in the spot market and authorized the Utility to enter into "bilateral agreements" with third parties. These contracts are used to purchase electricity from non-PX sources at fixed prices for terms that may extend to the end of 2005. The purpose of bilateral contracts is to lock in supply and rates on the future purchase of electricity and to reduce price volatility. The CPUC has authorized the Utility to trade natural gas-based financial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets, subject to certain conditions. Furthermore, the Utility was authorized to trade natural gas-based financial instruments to hedge the gas commodity price swings in serving core gas customers. PG&E Corporation's business units measure commodity price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. We quantify market risk using a variance/co-variance value-at-risk model that provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period. PG&E Corporation uses historical data for calculating the price volatility of our positions and how likely the prices of those positions will move together. The model includes all derivatives and commodity investments in our trading portfolios and only derivative commodity investments for our non-trading portfolio (but not the related underlying hedged position). PG&E Corporation and the Utility express value-at-risk as a dollar amount of the potential loss in the fair value of our portfolios based on a 95% confidence level using a one-day liquidation period. Therefore, there is a 5% probability that the Company's portfolios will incur a loss in one day greater than its value-at-risk. The value-at-risk is aggregated for PG&E Corporation as a whole by correlating the daily returns of the portfolios for electricity and natural gas for the previous 22 trading days. The following tables illustrate the value-at-risk for PG&E Corporation's daily commodity price risk exposure for the year ended December 31:
2000 1999 ---- ---- Trading Non-Trading Trading Non-Trading (Dollars in millions) NEG: Value at End of Period $11.5 $ 8.8 $4.4 $ -- Average 6.8 9.5 4.3 0.6 Low 5.5 7.6 1.3 -- High 12.3 11.1 6.2 1.7 Utility: Value at End of Period -- 187.4 -- 3.2 Average -- 24.2 -- 4.0 Low -- 0.1 -- 2.9 High -- 207.8 -- 5.7
Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, inadequate indication of the exposure of a portfolio to extreme price movements, and the inability to address the risk resulting from intra-day trading activities. Interest Rate Risk PG&E Corporation and the Utility are exposed to the following types of interest rate exposure: Floating rate exposure measures the sensitivity of corporate earnings and cash flows to changes in short-term interest rates. This exposure arises when short-term debt is rolled over at maturity, when interest rates on floating rate notes are periodically reset according to a formula or index, and when floating rate assets are financed with fixed rate liabilities. PG&E Corporation manages its exposure to short-term interest rates by using an appropriate mix of short- term debt, long-term floating rate debt, and long-term fixed rate debt. Financing exposure measures the effect of an increase in interest rates that may occur related to any planned or expected fixed rate debt financing. This includes the exposure associated with replacing debt at maturity. PG&E Corporation will hedge financing exposure in situations where the potential impairment of earnings, cash flows, and investment returns or execution efficiency, or external factors (such as bank imposed credit agreements) necessitate hedging. Refunding exposure measures the effect of an increase in interest rates on the ability to economically refund a callable debt instrument. Corporate bonds typically are issued with a call feature that allows the issuer to retire and replace the bonds at a lower rate if interest rates have fallen. The value of this call feature to the issuer declines with increases in interest rates. PG&E Corporation will hedge refunding exposure when it is economic to repurchase all or part of the underlying debt instrument and replace it with a debt instrument that has lower cost during its remaining life. The guideline for a refunding to be economic is that the net present value savings should exceed 5% of the par value of the debt to be refunded and the refunding efficiency should exceed 85%. PG&E Corporation and the Utility use interest rate swaps to manage their interest rate exposure. Interest rate risk sensitivity analysis is used to measure PG&E Corporation's interest rate price risk by computing estimated changes in the fair value in the event of assumed changes in market interest rates. As of December 31, 2000, if interest rates had averaged 1% higher, it was estimated that earnings would have decreased by approximately $24 million. Foreign Currency Risk PG&E Corporation is exposed to the following types of foreign currency risk: Economic exposure measures the change in value that results from changes in future operating or investing cash flows caused by the timing and level of anticipated foreign currency flows. Economic exposure includes the anticipated purchase of foreign entities, anticipated cash flows, projected revenues and expenses denominated in a foreign currency. Transaction exposure measures changes in value of current outstanding financial obligations already incurred, but not due to be settled until some future date. This includes the agreement to purchase a foreign entity in a currency other than the U.S. dollar, an obligation to infuse equity capital into a foreign entity, foreign currency denominated debt obligations, as well as actual non-U.S. dollar cash flows such as dividends declared but not yet paid. Translation exposure measures potential accounting derived changes in owners' equity that result from translating a foreign affiliate's financial statements from its functional currency to U.S. dollars for PG&E Corporation's consolidated financial statements. PG&E Corporation's primary foreign currency exchange rate exposure was with the Canadian dollar. The following instruments are used to hedge foreign currency exposures: forwards, swaps, and options. Based on a sensitivity analysis at December 31, 2000, a 10% devaluation of the Canadian dollar would be immaterial to PG&E Corporation's consolidated financial statements. New Accounting Standards PG&E Corporation and the Utility will adopt SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," effective January 1, 2001. The Statement will require us to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives, or any portions thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income until the hedged items are recognized in earnings. PG&E Corporation estimates that the transition adjustment to implement this new standard will be an immaterial reduction of net earnings and a negative adjustment of $377 million to other comprehensive income. The Utility estimates that the transition adjustment to implement this new standard will be an immaterial reduction of net earnings and a positive adjustment of $44 million to other comprehensive income. These adjustments will be recognized as of January 1, 2001 as a cumulative effect of a change in accounting principle. The ongoing effects will depend on the future market conditions and hedging activities at PG&E Corporation and the Utility. PG&E Corporation and the Utility have certain derivative commodity contracts for the physical delivery of purchase quantities transacted in the normal course of business. At this time, these derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus will not be reflected on the balance sheet at fair value. The Derivative Implementation Group of the Financial Accounting Standards Board is currently evaluating the definition of normal purchases and sales. As such, certain derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. PG&E Corporation and the Utility will evaluate the impact of the implementation guidance on a prospective basis when the final decision regarding this issue is resolved. Legal Matters In the normal course of business, both the Utility and PG&E Corporation are named as parties in a number of claims and lawsuits. See Note 15 of the Notes to the Consolidated Financial Statements for further discussion of significant pending legal matters. PG&E Corporation STATEMENTS OF CONSOLIDATED OPERATIONS (in millions, except per share amounts)
Year ended December 31, ----------------------- 2000 1999 1998 Operating Revenues Utility $ 9,637 $ 9,228 $ 8,924 Energy commodities and services 16,595 11,592 10,653 Total operating revenues 26,232 20,820 19,577 Operating Expenses Cost of energy for utility 8,166 3,149 2,942 Deferred electric procurement cost (6,465) -- -- Cost of energy commodities and services 15,220 10,587 9,852 Operating and maintenance 3,520 3,151 3,083 Depreciation, amortization, and decommissioning 3,659 1,780 1,602 Loss on assets held for sale -- 1,275 -- Provision for loss on generation-related regulatory assets and undercollected purchased power costs 6,939 -- -- Total operating expenses 31,039 19,942 17,479 Operating Income (Loss) (4,807) 878 2,098 Interest income 266 118 101 Interest expense (788) (772) (781) Other income (expense), net (23) 37 (36) Income (Loss) Before Income Taxes (5,352) 261 1,382 Income taxes provision (benefit) (2,028) 248 611 Income (Loss) from continuing operations $(3,324) $ 13 $ 771 Discontinued operations (Note 5) Loss from operations of PG&E Energy Services (net of applicable income taxes of $0 million, $35 million, and $41 million, respectively) -- (40) (52) Loss on disposal of PG&E Energy Services (net of applicable income taxes of $36 million, $36 million, and $0 million, respectively) (40) (58) -- Net income (loss) before cumulative effect of a change in accounting principle (Note 1) (3,364) (85) 719 Cumulative effect of a change in an accounting principle (net of applicable income taxes of $8 million) -- 12 -- Net Income (Loss) $(3,364) $ (73) $ 719 Weighted average common shares outstanding 362 368 382 Earnings (Loss) Per Common Share, Basic and Diluted Income (Loss) from continuing operations $ (9.18) $ 0.04 $ 2.02 Discontinued operations (0.11) (0.27) (0.14) Cumulative effect of a change in an accounting principle -- 0.03 -- Net Earnings (Loss) $ (9.29) $ (0.20) $ 1.88 Dividends Declared Per Common Share $ 1.20 $ 1.20 $ 1.20
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. PG&E Corporation CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at December 31, ------------------------- 2000 1999 ASSETS Current Assets Cash and cash equivalents $ 899 $ 281 Short-term investments 1,634 187 Accounts receivable Customers (net of allowance for doubtful accounts of $71 million and $65 million, respectively) 2,131 1,486 Energy marketing 2,211 532 Regulatory balancing accounts 222 -- Price risk management 2,039 400 Inventories 392 433 Income taxes receivable 1,241 -- Prepaid expenses and other 406 255 Total current assets 11,175 3,574 Property, Plant, and Equipment Utility 23,872 23,001 Non-utility Electric generation 2,008 1,905 Gas transmission 1,542 2,541 Construction work in progress 900 436 Other 147 184 Total property, plant, and equipment (at original cost) 28,469 28,067 Accumulated depreciation and decommissioning (11,878) (11,291) Net property, plant, and equipment 16,591 16,776 Other Noncurrent Assets Regulatory assets 1,773 4,957 Nuclear decommissioning funds 1,328 1,264 Price risk management 2,026 329 Other 2,398 2,570 Total noncurrent assets 7,525 9,120 TOTAL ASSETS $ 35,291 $ 29,470
PG&E Corporation CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at December 31, ------------ 2000 1999 LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 4,530 $ 1,499 Long-term debt, classified as current 2,391 558 Current portion of rate reduction bonds 290 290 Accounts payable Trade creditors 3,760 708 Energy marketing 2,096 480 Regulatory balancing accounts 196 384 Other 459 559 Accrued taxes -- 211 Price risk management 1,999 323 Other 1,563 1,058 Total current liabilities 17,284 6,070 Noncurrent Liabilities Long-term debt 4,736 6,682 Rate reduction bonds 1,740 2,031 Deferred income taxes 1,656 3,147 Deferred tax credits 192 231 Price risk management 1,867 207 Other 3,864 3,436 Total noncurrent liabilities 14,055 15,734 Preferred Stock of Subsidiaries 480 480 Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 300 300 Common Stockholders' Equity Common stock, no par value, authorized 800,000,000 shares, issued 387,193,727 and 384,406,113 shares, respectively 5,971 5,906 Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690) Reinvested earnings (Accumulated Deficit) (2,105) 1,674 Accumulated other comprehensive income (loss) (4) (4) Total common stockholders' equity 3,172 6,886 Commitments and Contingencies (Notes 1, 2, 3, 7, 14, and 15) -- -- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $35,291 $29,470
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. PG&E Corporation STATEMENTS OF CONSOLIDATED CASH FLOWS (in millions)
For the year ended December 31, ------------------------------- 2000 1999 1998 Cash Flows From Operating Activities Net income (loss) $(3,364) $ (73) $ 719 Adjustments to reconcile net (loss) income to net cash provided (used) by operating activities: Depreciation, amortization, and decommissioning 3,659 1,780 1,602 Deferred electric procurement costs (6,465) -- -- Deferred income taxes and tax credits--net (767) (754) (107) Other deferred charges and noncurrent liabilities 256 102 18 Provision for loss on generation-related regulatory assets and undercollected purchased power costs 6,939 -- -- Loss on assets held for sale -- 1,275 -- Loss regulatory assets from discontinued operations 40 98 52 Cumulative effect of change in accounting principle -- (12) -- Net effect of changes in operating assets and liabilities: Short-term investments (1,447) (132) 1,105 Accounts receivable--trade (2,324) 370 (342) Inventories 41 23 (33) Income tax receivable (1,241) -- -- Price risk management assets and liabilities, net 30 (28) (16) Accounts payable 4,568 (293) 247 Regulatory balancing accounts (410) 305 537 Accrued taxes (211) 108 (123) Other working capital 324 209 199 Other--net (404) (823) (470) Net cash (used) provided by operating activities (776) 2,155 3,388 Cash Flows From Investing Activities Capital expenditures (1,758) (1,584) (1,619) Acquisitions -- -- (1,779) Proceeds from sale of assets 415 1,014 1,106 Other--net 373 453 66 Net cash used by investing activities (970) (117) (2,226) Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities 2,846 (145) 2,115 Long-term debt issued 1,023 -- -- Long-term debt matured, redeemed, or repurchased (1,155) (798) (1,552) Preferred stock redeemed or repurchased -- -- (108) Common stock issued 65 54 63 Common stock repurchased (2) (693) (1,158) Dividends paid (436) (465) (470) Other--net 23 4 (3) Net cash provided (used) by financing activities 2,364 (2,043) (1,113) Net Change in Cash and Cash Equivalents 618 (5) 49 Cash and Cash Equivalents at January 1 281 286 237 Cash and Cash Equivalents at December 31 $ 899 $ 281 $ 286 Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 719 $ 727 $ 774 Income taxes (net of refunds) 20 723 770 Supplemental disclosures of non-cash investing and financing Retirement of long-term debt in the sale of PG&E Gas Transmission--Texas 564 -- --
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. PG&E Corporation STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY (in millions, except share amounts)
Common Reinvested Total Compre- Stock Earnings Accumulated Common hensive Common Held by (Accumulated Other Comprehensive Stock Income Stock Subsidiary Deficit) Income (Loss) Equity (Loss) Balance December 31, 1997 $ 6,366 $ -- $ 2,543 $ (12) $ 8,897 $ -- Net income -- -- 719 -- 719 719 Foreign currency translation adjustment -- -- -- 6 6 6 Comprehensive income -- -- -- -- -- $ 725 Common stock issued (2,028,303 shares) 63 -- -- -- 63 Common stock repurchased (37,090,630 shares) (565) -- (593) -- (1,158) Cash dividends declared on common stock -- -- (466) -- (466) Other (2) -- 7 -- 5 Balance December 31, 1998 5,862 -- 2,210 (6) 8,066 Net loss -- -- (73) -- (73) $ (73) Foreign currency translation adjustment -- -- -- 2 2 2 Comprehensive loss -- -- -- -- $ (71) Common stock issued (1,879,474 shares) 54 -- -- -- 54 Common stock repurchased (23,892,425 shares) (2) (690) (1) -- (693) Cash dividends declared on common stock (460) -- (460) Other (8) -- (2) -- (10) Balance December 31, 1999 5,906 (690) 1,674 (4) 6,886 Net loss -- -- (3,364) -- (3,364) $ (3,364) Common stock issued (2,847,269 shares) 65 -- -- -- 65 Common stock repurchased (59,655 shares) (1) -- (1) -- (2) Cash dividends declared on common stock -- -- (434) -- (434) Other 1 -- 20 -- 21 Balance December 31, 2000 $ 5,971 $ (690) $ (2,105) $ (4) $ 3,172
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. Pacific Gas and Electric Company STATEMENTS OF CONSOLIDATED OPERATIONS (in millions)
Year ended December 31, ----------------------- 2000 1999 1998 Operating Revenues Electric $ 6,854 $7,232 $7,191 Gas 2,783 1,996 1,733 Total operating revenues 9,637 9,228 8,924 Operating Expenses Cost of electric energy 6,741 2,411 2,321 Deferred electric procurement cost (6,465) -- -- Cost of gas 1,425 738 621 Operating and maintenance 2,687 2,522 2,668 Depreciation, amortization, and decommissioning 3,511 1,564 1,438 Provision for loss on generation-related regulatory assets and undercollected purchased power costs 6,939 -- -- Total operating expenses 14,838 7,235 7,048 Operating Income (Loss) (5,201) 1,993 1,876 Interest income 186 45 96 Interest expense (619) (593) (621) Other income (expense), net (3) (9) 7 Income (Loss) Before Income Taxes (5,637) 1,436 1,358 Income taxes provision (benefit) (2,154) 648 629 Net Income (Loss) (3,483) 788 729 Preferred dividend requirement 25 25 27 Income (Loss) Available for (Allocated to) Common Stock $(3,508) $ 763 $ 702
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. Pacific Gas and Electric Company CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at December 31, ------------ 2000 1999 ASSETS Current Assets Cash and cash equivalents $ 111 $ 80 Short-term investments 1,283 21 Accounts receivable Customers (net of allowance for doubtful accounts of $52 million and $46 million, respectively) 1,711 1,201 Related parties 6 9 Regulatory balancing account 222 -- Inventories Gas stored underground and fuel oil 146 139 Materials and supplies 134 155 Income taxes receivable 1,120 -- Prepaid expenses and other 45 34 Deferred income taxes -- 119 Total current assets 4,778 1,758 Property, Plant, and Equipment Electric 16,335 15,762 Gas 7,537 7,239 Construction work in progress 249 214 Total property, plant, and equipment (at original cost) 24,121 23,215 Accumulated depreciation and decommissioning (11,120) (10,497) Net property, plant, and equipment 13,001 12,718 Other Noncurrent Assets Regulatory assets 1,716 4,895 Nuclear decommissioning funds 1,328 1,264 Other 1,165 835 Total noncurrent assets 4,209 6,994 TOTAL ASSETS $ 21,988 $ 21,470
Pacific Gas and Electric Company CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at December 31, ------------ 2000 1999 LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 3,079 $ 449 Long-term debt, classified as current 2,374 465 Current portion of rate reduction bonds 290 290 Accounts payable Trade creditors 3,688 577 Related parties 138 216 Regulatory balancing accounts 196 384 Other 363 333 Accrued taxes -- 118 Deferred income taxes 172 -- Other 670 529 Total current liabilities 10,970 3,361 Noncurrent Liabilities Long-term debt 3,342 4,877 Rate reduction bonds 1,740 2,031 Deferred income taxes 929 2,510 Deferred tax credits 192 231 Other 2,968 2,252 Total noncurrent liabilities 9,171 11,901 Preferred Stock With Mandatory Redemption Provisions 6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137 Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 7.90%, 12,000,000 shares due 2025 300 300 Stockholders' Equity Preferred stock without mandatory redemption provisions Nonredeemable--5% to 6%, outstanding 5,784,825 shares 145 145 Redeemable--4.36% to 7.04%, outstanding 5,973,456 shares 149 149 Common stock, $5 par value, authorized 800,000,000 shares, issued 321,314,760 shares 1,606 1,606 Common stock held by subsidiary, at cost, 19,481,213 shares and 7,627,765 shares, respectively (475) (200) Additional paid-in capital 1,964 1,964 Reinvested earnings (Accumulated Deficit) (1,979) 2,107 Total stockholders' equity 1,410 5,771 Commitments and Contingencies (Notes 1, 2, 7, 14, and 15) -- -- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $21,988 $21,470
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. Pacific Gas and Electric Company STATEMENTS OF CONSOLIDATED CASH FLOWS (in millions)
For the year ended December 31, ------------ 2000 1999 1998 Cash Flows From Operating Activities Net income (loss) $(3,483) $ 788 $ 729 Adjustments to reconcile net income to net cash (used) provided by operating activities: Depreciation, amortization, and decommissioning 3,511 1,564 1,438 Deferred electric procurement costs (6,465) -- -- Deferred income taxes and tax credits--net (930) (485) (257) Other deferred charges and noncurrent liabilities 480 101 31 Provision for loss on generation-related regulatory assets and undercollected purchased power costs 6,939 -- -- Net effect of changes in operating assets and liabilities: Short-term investments (1,262) (4) 1,126 Accounts receivable (507) 187 266 Income taxes receivable (1,120) -- -- Accounts payable 3,063 15 203 Regulatory balancing accounts (410) 305 537 Accrued taxes (118) 116 (227) Other working capital 125 (39) (71) Other--net (522) (352) (39) Net cash (used) provided by operating activities (699) 2,196 3,736 Cash Flows From Investing Activities Capital expenditures (1,245) (1,181) (1,382) Proceeds from sale of assets 6 1,014 501 Other--net 32 234 40 Net cash used by investing activities (1,207) 67 (841) Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities 2,630 (219) 668 Long-term debt issued 680 -- -- Long-term debt matured, redeemed, or repurchased (597) (672) (1,413) Preferred stock redeemed or repurchased -- -- (108) Common stock repurchased (275) (926) (1,600) Dividends paid (475) (440) (444) Other--net (26) 1 (5) Net cash provided (used) by financing activities 1,937 (2,256) (2,902) Net Change in Cash and Cash Equivalents 31 7 (7) Cash and Cash Equivalents at January 1 80 73 80 Cash and Cash Equivalents at December 31 $ 111 $ 80 $ 73 Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 587 $ 531 $ 600 Income taxes (net of refunds) -- 1,001 1,115
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. Pacific Gas and Electric Company STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (in millions, except share amounts)
Preferred Accumulated Stock Addi- Common Reinvested Other Total Without Compre- tional Stock Earnings Compre- Common Mandatory hensive Common Paid-in Held by (Accumulated hensive Stock Redemption Income Stock Capital Subsidiary Deficit) (Loss) Equity Provisions (Loss) Balance December 31, 1997 $2,018 $2,564 $ -- $ 2,671 $-- 7,253 $402 Net income -- -- -- 729 -- 729 -- $ 729 Foreign currency translation adjustments -- -- -- -- (1) (1) -- (1) Comprehensive income -- -- -- -- -- -- -- $ 728 Common stock repurchased (62,150,837 shares) (311) (481) -- (808) -- (1,600) -- Preferred stock redeemed (4,323,948 shares) -- (7) -- (3) -- (10) (98) Cash dividends declared Preferred stock -- -- -- (28) -- (28) -- Common stock -- -- -- (300) -- (300) -- Other -- 11 -- -- -- 11 (10) Balance December 31, 1998 $1,707 $2,087 -- $ 2,261 (1) $ 6,054 $294 Net income -- -- -- 788 -- 788 -- $ 788 Foreign currency translation adjustments -- -- -- -- 1 1 -- 1 Comprehensive income -- -- -- -- -- -- -- $ 789 Common stock repurchased (27,666,460 shares) (101) (123) (200) (502) -- (926) -- Cash dividends declared Preferred stock -- -- -- (25) -- (25) -- Common stock -- -- -- (415) -- (415) -- Balance December 31, 1999 $1,606 $1,964 $(200) $ 2,107 -- $ 5,477 $294 Net loss -- -- -- (3,483) -- (3,483) -- $(3,483) Common stock repurchased (11,853,448 shares) -- -- (275) -- -- (275) -- Cash dividends declared Preferred stock -- -- -- (25) -- (25) -- Common stock -- -- -- (578) -- (578) -- Balance December 31, 2000 $1,606 $1,964 $(475) $(1,979) $-- $ 1,116 $294
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Note 1: General Basis of Presentation PG&E Corporation was incorporated in California in 1995 and became the holding company of Pacific Gas and Electric Company (the Utility) on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. Effective with PG&E Corporation's formation, the Utility's interests in its unregulated subsidiaries were transferred to PG&E Corporation. As discussed further in Notes 2 and 3, on April 6, 2001, the Utility filed a voluntary petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possesion while being subject to the jurisdiction of the Bankruptcy Court. This is a combined annual report of PG&E Corporation and the Utility. Therefore, the Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation, the Utility, and PG&E Corporation's wholly owned and controlled subsidiaries. The Utility's consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. All significant inter-company transactions have been eliminated from the consolidated financial statements. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 used include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). Operations PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's Northern and Central California energy utility subsidiary, the Utility, delivers electric service to approximately 4.6 million customers and natural gas service to approximately 3.8 million customers. PG&E Corporation's PG&E National Energy Group, Inc. (NEG) markets energy services and products throughout North America. The NEG is an integrated energy company with a strategic focus on power generation, new power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. NEG businesses include its power plant development and generation unit, PG&E Generating Company, LLC and its affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas Transmission Corporation (PG&E GT); and its wholesale energy and marketing trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P. (collectively, PG&E Energy Trading or PG&E ET). During 2000, NEG sold its energy services unit, PG&E Energy Services Corporation (PG&E ES). Also, during the fourth quarter of 2000, NEG sold its Texas natural gas and natural gas liquids business carried on through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries (PG&E GTT). Cash Equivalents and Short-Term Investments Cash equivalents (stated at cost, which approximates market) include working funds and consist primarily of Eurodollar time deposits, bankers' acceptances, and commercial paper with original maturities of three months or less when purchased. Restricted Cash Restricted cash includes cash and cash equivalents, as defined above, which are restricted under the terms of certain agreements for payment to third parties, primarily for debt service. Restricted cash included under Cash and Cash Equivalents in PG&E Corporation's and the Utility's Consolidated Balance Sheets as of December 31, 2000 and 1999 is as follows: (in millions) 2000 1999 Utility $ 50 $ 42 National Energy Group 53 81 Inventories Inventories include materials and supplies, gas stored underground, coal, and fuel oil. Materials and supplies, coal, and gas stored underground are valued at average cost, except for the gas storage inventory of PG&E ET, which is recorded at fair value. Fuel oil is valued by the last-in first-out method. Income Taxes PG&E Corporation and the Utility use the liability method of accounting for income taxes. Income tax expense (benefit) includes current and deferred income taxes resulting from operations during the year. Tax credits are amortized over the life of the related property. PG&E Corporation files a consolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80% or more. The Utility and various other subsidiaries are parties to a tax-sharing arrangement with PG&E Corporation. PG&E Corporation files consolidated state income tax returns when applicable. The Utility reports taxes on a stand-alone basis. Earnings (Loss) Per Share Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. The following is a reconciliation of PG&E Corporation's net income (loss) and weighted average common shares outstanding for calculating basic and diluted net income (loss) per share.
Years ended December 31, ----------------------- (in millions) 2000 1999 1998 Income (loss) from continuing operations $(3,324) $ 13 $ 771 Discontinued operations (40) (98) (52) Net income (Loss) before cumulative effect of accounting change (3,364) (85) 719 Cumulative effect of accounting change -- 12 -- Net Income (Loss) $(3,364) $ (73) $ 719 Earnings (Loss) per common share, Basic and Diluted: Weighted average common shares outstanding 362 368 382
Income (Loss) from continuing operations $ (9.18) $ 0.04 $ 2.02 Discontinued operations (0.11) (0.27) (0.14) Cumulative effect of accounting change -- 0.03 -- Net Income (Loss) $ (9.29) $(0.20) $ 1.88
The diluted share base for 2000 excludes incremental shares of 2 million related to employee stock options. These shares are excluded due to the anti- dilutive effect as a result of the loss from continuing operations. For 1999 and 1998, the assumed conversion of stock options issued under the long-term incentive plan increased the weighted average shares outstanding for dilutive purposes to 369 million and 383 million, respectively. PG&E Corporation reflects the preferred dividends of subsidiaries as other expense for computation of both basic and diluted earnings per share. Property, Plant, and Equipment Plant additions and replacements are capitalized. The capitalized costs include labor, materials, construction overhead, and capitalized interest or an allowance for funds used during construction (AFUDC). AFUDC is the estimated cost of debt and equity funds used to finance regulated plant additions. Capitalized interest and AFUDC for PG&E Corporation amounted to $19 million, $18 million, and $28 million for the years ended December 31, 2000, 1999, and 1998, respectively. Capitalized interest and AFUDC for the Utility amounted to $18 million, $16 million, and $26 million for the years ended December 31, 2000, 1999, and 1998, respectively. Nuclear fuel inventories are included in property, plant, and equipment. 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. The original cost of retired plant and removal costs less salvage value is charged to accumulated depreciation upon retirement of plant in service for the Utility and the NEG businesses that apply Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended. For the remainder of the NEG business operations, the cost and accumulated depreciation of property, plant, and equipment retired or otherwise disposed of is removed from related accounts and included in the determination of the gain or loss on disposition. Property, plant, and equipment are depreciated using a straight-line remaining-life method. PG&E Corporation's composite depreciation rates were 4.44%, 3.60%, and 3.89% for the years ended December 31, 2000, 1999, and 1998, respectively. The Utility's composite depreciation rates were 4.54 %, 3.41%, and 3.88% for the years ended December 31, 2000, 1999, and 1998, respectively. Estimated useful lives of property, plant, and equipment are as follows:
Utility Non-Utility Electric generating facilities 20 to 50 years 20 to 50 years Electric distribution facilities 10 to 63 years N/A Electric transmission 27 to 65 years N/A Gas distribution facilities 28 to 49 years N/A Gas transmission 25 to 45 years 22 to 40 years Gas storage 25 to 48 years N/A Other 5 to 38 years 2 to 7 years
The useful life of the Utility's property, plant, and equipment complies with CPUC-authorized ranges. Capitalized Software Costs Costs incurred during the application development stage of internal use software projects are capitalized. At December 31, 2000 and 1999, capitalized software costs totaled $235 million and $216 million, net of $80 million and $59 million accumulated amortization, respectively. Such capitalized amounts are amortized in accordance with regulatory requirements ratably over the expected lives of the projects when they become operational, over periods ranging from 2 to 15 years. Gains and Losses on Reacquired Debt 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 amortization period of the debt reacquired, consistent with ratemaking principles. Gains and losses on reacquired debt associated with unregulated operations are recognized in earnings as extraordinary gains or losses at the time such debt is reacquired. Intangible Assets and Asset Impairment PG&E Corporation amortizes the excess of purchase price over fair value of net assets of businesses acquired (goodwill) using the straight-line method over periods ranging from 5 to 40 years. PG&E Corporation periodically assesses goodwill and intangible assets for potential impairment. PG&E Corporation and the Utility periodically evaluate long-lived assets, including property, plant, and equipment, goodwill, and specifically identifiable intangible assets, when events or changes in circumstances indicate that the carrying value of these assets may be impaired. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of," requires PG&E Corporation and the Utility to write off regulatory assets when they are no longer probable of recovery. On an ongoing basis, PG&E Corporation and the Utility review their regulatory assets and liabilities for the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. Regulation and Statement of Financial Accounting Standards (SFAS) No. 71 The Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory Commission (NRC), among others. The gas transmission business in the Pacific Northwest is regulated by the FERC. PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71. This statement allows for the recording of a regulatory asset or liability for costs that will be collected or refunded through the ratemaking process in the future. Regulatory assets comprise the following:
Balance at December 31, ------------ (in millions) 2000 1999 Rate Reduction Bonds/(1)/ $1,178 $ 727 Unamortized loss, net of gain, on reacquired debt 342 376 Regulatory assets for deferred income tax 160 705 Transition Revenue Account/(1)/ -- 69 Transition Cost Balancing Account/(1)/ -- 220 Diablo Canyon/(1)/ -- 1,891 Other, net 36 907 Total Utility regulatory assets $1,716 $4,895 PG&E GTN 57 62 Total PG&E Corporation regulatory assets $1,773 $4,957
(1) See Note 2 of the Notes to the Consolidated Financial Statements for further discussion. Regulatory assets are amortized over the period that the costs are reflected in regulated revenues. The Utility has amortized its eligible generation-related transition costs, including the Transition Cost Balancing Account (TCBA) and the regulatory assets related to Diablo Canyon, over the transition period in conjunction with the available competition transition charge (CTC) revenues. During 2000, the energy crisis materially and adversely affected PG&E Corporation's and the Utility's cash flow and liquidity and created substantial uncertainty about their prospects for the future. As a result, the Utility can no longer conclude that energy costs, which have been deferred on its balance sheet in accordance with SFAS No. 71, are probable of recovery through future rates. Accordingly, the Utility wrote off the generation-related transition costs and undercollected purchased power costs at December 31, 2000 (see Note 2 of the Notes to the Consolidated Financial Statements). In general, the Utility does not earn a return on regulatory assets where the related costs do no accrue interest. At December 31, 2000, the Utility did not earn a return on the regulatory asset related to recording deferred taxes as required by SFAS No. 109 "Accounting for Income Taxes" of $160 million. During 2000, all other assets that did not earn a return were recovered or written off as referred to above. At December 31, 1999, the Utility did not earn a return on (1) the $410 million regulatory asset related to recording deferred taxes as required by SFAS No. 109, (2) the regulatory asset related to the Western Area Power Administration contract of $86 million, and (3) a regulatory asset related to the generation portion of certain employee benefits of $15 million. Revenues and Regulatory Balancing Accounts For gas utility revenues, sales balancing accounts accumulate differences between authorized and actual base revenues. Further, gas cost balancing accounts accumulate differences between the actual cost of gas and the revenues designated for recovery of such costs. The regulatory balancing accounts accumulate balances until they are refunded to or received from Utility customers through authorized rate adjustments. Utility revenues included amounts for services rendered but unbilled at the end of each year. Revenue Recognition Revenues derived from power generation are recognized upon output, product delivery, or satisfaction of specific targets, all as specified by contractual terms. Regulated gas transmission revenues are recorded as services are provided, based on rate schedules approved by the FERC. Substantially all of PG&E ET's operations are accounted for under a mark-to-market accounting methodology. Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition," was issued by the Securities and Exchange Commission (SEC), on December 3, 1999. SAB No. 101, as amended, summarizes certain of the SEC staff's views in applying accounting principles generally accepted in the United States of America to revenue recognition in financial statements. PG&E Corporation's consolidated financial statements reflect the accounting principles provided in SAB No. 101. Accounting for Price Risk Management Activities PG&E Corporation, primarily through its subsidiaries, engages in price risk management activities for both trading and non-trading purposes. PG&E Corporation conducts trading activities principally through its unregulated lines of business. Trading activities are conducted to generate profit, create liquidity, and maintain a market presence. Net open positions often exist or are established due to the NEG's assessment of and response to changing market conditions. Non-trading activities are conducted to optimize and secure the return on risk capital deployed within the NEG's existing asset and contractual portfolio. In addition, non-trading activity exists within the Utility to hedge against price fluctuations of electricity and natural gas. Derivative and other financial instruments associated with electricity, natural gas, natural gas liquids, and related trading activities are accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, PG&E Corporation's trading contracts, including both physical contracts and financial instruments, are recorded at market value, which approximates fair value. The market prices used to value these transactions reflect management's best estimates considering various factors, including market quotes, time value, and volatility factors of the underlying 43 commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions. Changes in the market value of these contract portfolios, resulting primarily from newly originated transactions and the impact of commodity price or interest rate movements, are recognized in operating income in the period of change. Unrealized gains and losses on these contract portfolios are recorded as assets and liabilities, respectively, from price risk management. In addition to the trading activities, as discussed previously, PG&E Corporation may engage in non-trading activities using futures, forward contracts, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. PG&E Corporation accounts for non-trading transactions under the deferral method. Initially, PG&E Corporation defers unrealized gains and losses on these transactions and classifies them as assets or liabilities. When the underlying item settles, PG&E Corporation recognizes the gain or loss in operating expense. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses. If the hedged item is sold, the value of the associated derivative is recognized in income. PG&E Corporation and the Utility will adopt SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" effective January 1, 2001. The Statement will require PG&E Corporation and the Utility to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income until the hedged items are recognized in earnings. PG&E Corporation estimates that the transition adjustment to implement this new standard will be a non-material reduction of net earnings and a negative adjustment of $377 million to other comprehensive income. The Utility estimates that the transition adjustment to implement this new standard will be a non-material reduction of net earnings and a negative adjustment of $44 million to other comprehensive income. These adjustments will be recognized as of January 1, 2001 as a cumulative effect of a change in accounting principle. The ongoing effects will depend on the future market conditions and hedging activities at PG&E Corporation and the Utility. PG&E Corporation and the Utility have certain derivative commodity contracts for the physical delivery of purchase quantities transacted in the normal course of business. At this time, these derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus will not be reflected on the balance sheet at fair value. The Derivative Implementation Group of the Financial Accounting Standards Board is currently evaluating the definition of normal purchases and sales. As such, certain derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. PG&E Corporation and the Utility will evaluate the impact of the implementation guidance on a prospective basis when the final decision regarding this issue is resolved. Comprehensive Income PG&E Corporation's and the Utility's comprehensive income consists of net income and other items recorded directly to the equity accounts. The objective is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with shareholders. PG&E Corporation's and the Utility's other comprehensive income consists principally of foreign currency translation adjustments and will include changes in the market value of certain financial hedges upon the implementation of SFAS No. 133 on January 1, 2001. See Accounting for Price Risk Management Activities above for discussion of implementation of SFAS No. 133. Cumulative Effect of Change in Accounting Method Effective January 1, 1999, PG&E Corporation changed its method of accounting for major maintenance and overhauls of generating assets at the NEG. Beginning January 1, 1999, the cost of major maintenance and overhauls of generating assets, principally at the PG&E Gen business segment, were accounted for as incurred. Previously, the estimated cost of major maintenance and overhauls was accrued in advance in a systematic and rational manner over the period between major maintenance and overhauls. The change resulted in PG&E Corporation recording income of $12 million net of income tax ($0.03 per share) as of December 31, 1999, reflecting the cumulative effect of the change in accounting principle. The Utility has consistently accounted for major maintenance and overhauls as incurred. 44 Related Party Agreements In accordance with various agreements, the Utility and other subsidiaries provide and receive various services from their parent, PG&E Corporation. The Utility and PG&E Corporation exchange administrative and professional support services in support of operations. These services are priced at either the fully loaded cost or at the higher of fully loaded cost or fair market value depending on the nature of the services provided. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using a variety of factors, including their share of employees, operating expenses, assets, and other cost causal methods. Additionally, the Utility purchases gas commodity and transmission services and sells reservation and other ancillary services to the NEG. These services are priced at either tariff rates or fair market value depending on the nature of the services provided. Intercompany transactions are eliminated in consolidation and no profit results from these transactions. For the years ended December 31, 2000, 1999, and 1998, the Utility's significant related party transactions were as follows:
(in millions) 2000 1999 1998 Utility revenues from: Administrative services provided to PG&E Corporation $ 12 $ 23 $ 17 Transportation and distribution services provided to PG&E ES -- 134 -- Gas reservation services provided to PG&E ET 12 7 1 Other 2 3 4 Utility expenses from: Administrative services received from PG&E Corporation $ 83 $ 66 $ 58 Gas commodity and transmission services received from PG&E ET 136 30 1 Transmission services received from PG&E GT 46 47 49
Stock-based Compensation PG&E Corporation accounts for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by SFAS No. 123, "Accounting for Stock-Based Compensation." Under the intrinsic value method, PG&E Corporation does not recognize any compensation expense as the exercise price of all stock options is equal to the fair market value at the time the options are granted. Reclassifications Certain amounts in 1999 and 1998 financial statements have been reclassified to conform to the 2000 presentation. Note 2: The California Energy Crisis In 1998, California became one of the first states in the country to implement electric industry restructuring and establish a competitive market framework for electric generation. Electric industry restructuring was mandated by the California Legislature in Assembly Bill 1890 (AB 1890). The electric industry restructuring established a transition period, mandated a rate freeze, included a plan for recovery of uneconomic generation-related costs (transition costs), and encouraged the disposition of a portion of utility-owned generation facilities. The competitive market framework called for the creation of the Power Exchange (PX) and the Independent System Operator (ISO). The PX would establish market-clearing prices for electricity, and the ISO would schedule delivery of electricity for all market participants and operate certain markets for electricity. The Utility was required to purchase electricity for its customers through the PX and ISO. Customers were given the choice of continuing to buy electricity from the Utility or buying electricity from independent power generators or retail electricity suppliers. Most of the Utility's customers continued to buy electricity through the Utility. Beginning in June 2000, wholesale prices for electricity sold through the PX and ISO experienced unanticipated and massive increases. The average price of electricity purchased by the Utility for the benefit of its customers was 18.2 cents per kWh for the period of June 1 through December 31, 2000, compared to 4.2 cents per kWh during the same period in 1999. The Utility was only permitted to collect approximately 5.4 cents per kWh in rates from its customers 45 during that period. The increased cost of the purchased electricity has strained the financial resources of the Utility. Because of the rate freeze, the Utility was unable to pass on the increases in power costs to its customers through current rates. In order to finance the higher costs of energy, during the third and fourth quarter of 2000, the Utility increased its lines of credit to $1,850 million (net increase of $850 million), issued $1,240 million of debt under a 364-day facility, and issued $680 million of five-year notes. The Utility continued to finance the higher costs of wholesale electric power while interested parties evaluated various solutions to the energy crisis. In November 2000, the Utility filed its Rate Stabilization Plan (RSP), which sought to end the rate freeze and pass along the increased wholesale electric costs to customers through increased rates. The CPUC evaluated the Utility's proposal and deferred its decision until after hearings could be held, although the CPUC did increase rates one cent per kWh for 90 days effective January 4, 2001. This increase resulted in approximately $70 million of additional revenue per month, which was not nearly enough to cover the higher wholesale costs of electricity, nor did it help with the costs already incurred. By December 31, 2000, the Utility had borrowed more than $3.0 billion under its various credit facilities to pay its energy costs. As a result of the California energy crisis and its impact on the Utility's financial resources, PG&E Corporation's and the Utility's credit rating deteriorated to below investment grade in January 2001. This credit downgrade precluded PG&E Corporation and the Utility from access to capital markets. Commencing in January 2001, PG&E Corporation and the Utility began to default on maturing commercial paper. In addition, the Utility became unable to pay the full amount of invoices received for wholesale power purchases and made only partial payments. The Utility had no credit under which it could purchase wholesale electricity on behalf of its customers on a continuing basis and generators were only selling to the Utility under emergency actions taken by the U.S. Secretary of Energy. In January 2001 the California Legislature and the Governor authorized the California Department of Water Resources (DWR) to purchase wholesale electric energy on behalf of the Utility's retail customers. In February 2001, the California Legislature passed California Assembly Bill 1X (AB 1X), which authorized the DWR to purchase wholesale electricity on behalf of the Utility's customers. On March 27, 2001, the CPUC authorized an average increase in retail rates of 3.0 cents per kWh, which was in addition to the emergency 1.0 cent per kWh surcharge adopted on January 4, 2001 by the CPUC. The revenue generated by this rate increase is to be used only for electric power procurement costs that are incurred after March 27, 2001. Although the rate increase is authorized immediately, the 3.0 cent surcharge will not be collected in rates until the CPUC establishes the rate design which is not expected to be adopted until May 2001. As more fully described below, the energy crisis has materially and adversely affected the Utility's cash flow and liquidity and has created substantial uncertainty about their prospects for the future. As a result, the Utility can no longer conclude that energy costs, which had been deferred on its balance sheet in accordance with SFAS No. 71, are probable of recovery through future rates. Accordingly, the Utility has taken a charge against earnings of $6.9 billion ($4.1 billion after tax) to write off its remaining generation- related regulatory assets and undercollected purchased power costs. This charge has resulted in an accumulated deficit at the Utility of $2.0 billion as of December 31, 2000. PG&E Corporation's accumulated deficit at December 31, 2000 is $2.1 billion. Further, the Utility does not have authority to recover any purchased power costs it incurs during 2001 in excess of revenues from retail rates. Such amounts also will be charged against earnings, as incurred, absent a regulatory or legislative solution that provides for recovery of such costs. Under SFAS No. 71, if a rate mechanism provided by legislation or other regulatory authority is subsequently established that makes recovery from regulated rates probable as to all or a portion of the undercollection that was previously charged against earnings, a regulatory asset will be reinstated with a corresponding increase in earnings. As discussed more fully herein, the Utility is seeking resolution on many fronts. The ongoing uncertainty and lack of successful resolution continues to have a negative impact on the Utility's ability to obtain funding and pay its debt and power procurement liabilities. As discussed further in Note 3, on April 6, 2001, the Utility sought protection from its creditors through a Chapter 11 bankruptcy filing. The filing for bankruptcy and the related uncertainty around any reorganization plan that is ultimately adopted will have a significant impact on the Utility's future liquidity and results of operations. PG&E Corporation, itself, had cash of $297 million at March 29, 2001 and believes that the funds will be adequate to maintain its operations through and beyond 2001. In addition, PG&E Corporation believes that PG&E Corporation, itself, and its other subsidiaries not subject to CPUC regulation are substantially protected from the continuing liquidity and financial difficulties of the Utility. A discussion of the events leading up to the charge, PG&E Corporation's and the Utility's mitigation efforts and the ongoing uncertainty follows. 46 Transition Period and Rate Freeze California's deregulation legislation passed by the California Legislature in 1996 established a transition period, which was to begin in 1998. During this period, electric rates for all customers were frozen at 1996 levels, with rates for residential and small commercial customers being reduced in 1998 by 10% and frozen at that level. During the transition period, investor-owned utilities were given the opportunity to recover their transition costs. Transition costs were generation-related costs that proved to be uneconomic under the new industry structure. To pay for the 10% rate reduction, the Utility refinanced $2.9 billion (the expected revenue reduction from the rate decrease) of its transition costs with the proceeds from the sale of rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of the transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service did not increase the Utility customers' electric rates (See Note 9). If the transition period ends before March 31, 2002, the Utility may be obligated to return a portion of the economic benefits of the transaction to customers. The timing of any such return and the exact amount of such portion, if any, have not yet been determined. The rate freeze was scheduled to end on the earlier of March 31, 2002 or the date the Utility has recovered all of its transition costs. The Utility believes it recovered its eligible transition costs during August 2000 or potentially earlier as a result of recording a credit to the Utility's account for tracking the recovery of transition costs in recognition of the fair market value of the Utility's hydroelectric generation facilities. On August 31, 2000, the Utility recorded a $2.1 billion credit to the Utility's account for tracking the recovery of the TCBA, which was an amount by which a negotiated $2.8 billion hydroelectric generation asset valuation exceeded the aggregate book value of such assets. At August 31, 2000, there was a balance of approximately $2.2 billion of undercollected wholesale electricity costs recorded in the regulatory balancing account called the Transition Revenue Account (TRA). If the final valuation for the hydroelectric assets is greater than $2.8 billion, as the Utility expects, the Utility will have recovered its transition costs earlier. The undercollected TRA balance as of the end of the earlier determined transition period will be less than the August 31 balance of $2.2 billion, and could be zero depending on the ultimate valuation of the hydroelectric generating facilities and when the transition period actually ends. However, the CPUC has not yet accepted the Utility's estimated market valuation of its hydroelectric assets nor has the CPUC determined that the rate freeze has ended. Wholesale Prices of Electricity As previously stated, beginning in June 2000, the Utility experienced unanticipated and massive increases in the wholesale costs of the electricity purchased from the PX and ISO on behalf of its retail customers. For the year ended December 31, 2000 and 1999, the average monthly prices in cents per kWh that the PX and ISO charged the Utility for electricity were as follows: 2000 1999 January 4.38 3.15 February 3.78 2.87 March 3.24 2.87 April 3.28 2.90 May 6.08 2.82 June 16.33 2.95 July 11.00 3.85 August 18.70 4.10 September 13.82 4.09 October 13.62 6.18 November 20.43 4.46 December 33.24 3.97 It is expected that the wholesale costs will continue to be extremely high through 2001 unless significant changes occur in the wholesale electricity market. The generation-related cost component, which provides for recovery of 47 wholesale electricity purchased by the Utility and, if available, for recovery of transition cost, was approximately 5.4 cents per kWh, during 2000. The excess of wholesale electricity costs above the generation-related cost component available in frozen rates was deferred to the TRA. The TRA balance as of December 31, 2000, prior to being written off against earnings, was an undercollection of approximately $6.6 billion. Under current CPUC decisions, if the TRA undercollection is not recovered through frozen rates by the end of the transition period, it cannot be recovered or offset against overcollections of transition cost recovery. Once the transition period has ended and the rate freeze is over, the Utility's customers will be responsible for reasonable wholesale electricity costs. However, actual changes in customer rates will not occur until new retail rates are authorized by the CPUC or, to the extent allowed, by the bankruptcy court. The Utility has reviewed on an ongoing basis the facts and circumstances relating to the TRA and remaining transition cost regulatory assets. Due to the lack of regulatory, legislative, or judicial relief, the Utility has determined that it can no longer conclude that its uncollected wholesale electricity costs and remaining transition costs are probable of recovery in future rates. Accordingly, the Utility wrote off, as a charge against earnings, the TRA and TCBA of approximately $6.9 billion. In addition, absent a regulatory, judicial, or legislative solution that provides for full recovery of such costs, the Utility will be unable to defer the costs of wholesale power purchases in excess of amounts recovered through rates in 2001 and such expenses are expected to reduce the Utility's future earnings accordingly. Transition Cost Recovery Beginning January 1, 1998, the Utility started amortizing eligible transition costs, including most generation-related regulatory assets. These transition costs were offset by or recovered through the frozen rates, market valuation of generation assets in excess of book value, net energy sales from the Utility's electric generation facilities, and the amount by which long-term contract prices to purchase electricity were lower than the PX price. Transition costs and associated recoveries are recorded in the Utility's TCBA. During the transition period, a reduced rate of return on common equity of 6.77% applies to all generation assets, including those generation assets reclassified to regulatory assets. During the transition period, the CPUC reviews the Utility's compliance with accounting methods established in the CPUC's decisions governing transition cost recovery and the amount of transition costs requested for recovery. In January 2001, the CPUC approved all non-nuclear transition costs that were amortized from July 1, 1998, to June 30, 1999. The CPUC currently is reviewing non-nuclear transition costs amortized from July 1, 1999, to June 30, 2000. Mitigation Efforts The Utility is actively exploring ways to reduce its exposure to the higher wholesale electricity costs and to recover its written-off TRA and TCBA balances. As previously indicated, the Utility believes the transition period has ended and filed an application with the CPUC asking it to so rule. The Utility has also filed a lawsuit against the CPUC in Federal District Court, filed an application with the CPUC seeking approval of a five-year rate stabilization plan, filed an application with the FERC to address the current market crisis, worked with interested parties to address power market dysfunction before appropriate regulatory bodies, and hedged a portion of its open procurement position against higher purchased power costs through forward purchases. The Utility's actions and related activities are discussed below. Application with the FERC On October 16, 2000, the Utility joined with Southern California Edison and The Utility Reform Network (TURN), in filing a petition with the FERC requesting that the FERC (1) immediately find the California wholesale electricity market to be not workably competitive and the resulting prices to be unjust and unreasonable; (2) immediately impose a cap on the price for energy and ancillary services; and (3) institute further expedited proceedings regarding the market failure, mitigation of market power, structural solutions, and responsibility for refunds. However, the reduced price cap requested, even if approved, would still be above the approximate 5.4 cents per kWh available through frozen rates for the payment of the Utility's wholesale electricity costs. On December 15, 2000, the FERC issued an order in response to the above filing. The remedies proposed by the FERC include, among other things: (1) eliminating the requirement that the California investor-owned utilities must sell all of their power into, and buy all of their power needs from, the PX; (2) modifying the single price auction so that bids above $150 per megawatt hour (MWh) (15 cents per kWh) cannot set the market clearing prices paid to all bidders, effective January 1, 2001 through April 30, 2001; (3) establishing an independent governing board for the ISO; and 48 (4) establishing penalties for under-scheduling power loads. The FERC did not order any refunds based on its findings, but announced its intent to retain the discretion to order refunds for wholesale electricity costs incurred from October 2000 through December 31, 2002. In March 2001, the FERC ordered refunds of $69 million for January 2001 and indicated it would continue to review December 2000 wholesale prices. The generators have appealed the decision. Any refunds will be offset against amounts owed the generators. Federal Lawsuit On November 8, 2000, the Utility filed a lawsuit in federal district court in San Francisco against the CPUC. The Utility asked the court to declare that the federally-approved wholesale electricity costs the Utility has incurred to serve its customers are recoverable in retail rates both before and after the end of the transition period. The lawsuit states that the wholesale power costs the Utility has incurred are paid pursuant to filed rates, which the FERC has authorized and approved and that under the United States Constitution and numerous federal court decisions, state regulators cannot disallow such costs. The Utility's lawsuit also alleges that to the extent that the Utility is denied recovery of these mandated wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property. On January 29, 2001, the Utility's lawsuit was transferred to the federal district court in Los Angeles where Southern California Edison has its identical case pending. Legislative Action On February 1, 2001, the governor of California signed into law AB 1X. AB 1X extended a preliminary authority of the DWR to purchase power. Public Utilities Code Section 360.5, adopted in AB 1X, authorizes the CPUC to determine the portion of each electric utility's existing electric retail rate that represents the difference between the generation related component of the utility's retail rate in effect on January 5, 2001, and the sum of the costs of the utility's own generation, qualifying facilities (QF) contracts, existing bilateral contracts, and ancillary services (the California Procurement Adjustment or CPA). The CPA is payable to the DWR by each utility upon receipt from its retail end use customers. 49 The DWR has indicated that it intends to buy power only at "reasonable prices" to meet the power needs of the retail electric customer that cannot be met by the utility-owned generation or power under contract to the utilities; i.e. the utilities' net open position. As the DWR has set a yet undisclosed ceiling on what it will pay for power, the ISO has been left to pay the remainder. The ISO has purchased energy at costs above the DWR's ceiling and, in turn, is expected to bill the Utility for those costs. AB 1X does not address whether or how the Utility will be able to pay for or recover purchase power costs it has incurred because ISO purchases were not under the DWR's ceiling for "reasonable prices." PG&E Corporation and the Utility cannot predict what regulatory, legislative, or judicial actions may be taken with respect to this issue. In response to the ISO's concern over the weakened financial condition of the Utility and its ability to pay for power purchases, on February 14, 2001, the FERC issued an order stating that the ISO could not allow the Utility to schedule power from a third party supplier, unless the Utility was creditworthy or was backed by creditworthy parties. The FERC order also stated that the ISO could continue to schedule power for the Utility as long as it comes from its own generation units and is routed over its own transmission lines. The ISO has stated that it will charge the Utility for the power it buys on an emergency basis, despite the FERC ruling. On April 6, 2001, the FERC issued a further order directing the ISO to implement its prior order which the FERC clarified applies to all third -party transactions whether scheduled or not. Rate Stabilization Plan (RSP) On November 22, 2000, the Utility filed an application with the CPUC seeking approval of a five-year RSP beginning on January 1, 2001. The Utility requested an initial average rate increase of 22.4%. The Utility also proposed that it receive actual costs, including a regulated return, for electricity generation provided by it with the idea that profits that would have been generated at market rates be recovered from customers later in the five-year rate stabilization period. With respect to Diablo Canyon Nuclear Power Plant (Diablo Canyon) the Utility has proposed to defer all profits (discussed below in "Diablo Canyon Benefits Sharing"), until 2003, when the allocation of revenues between ratepayers and shareholders will be readjusted. The readjustment is intended to allow, by the end of 2005, the total net revenues earned by Diablo Canyon, over the five-year plan, to be allocated equally between shareholders and ratepayers according to existing CPUC decisions. On January 4, 2001, the CPUC issued an emergency interim decision denying the Utility's request for a rate increase. Instead, the decision permitted the Utility to establish an interim surcharge applied to electric rates on an equal- cents-per-kWh basis of 1.0 cent per kWh, subject to refund and adjustment. The surcharge was to remain in effect for 90 days from the effective date of the decision. The Utility was required to establish a balancing account to track the revenue provided by the surcharge and to apply these revenues to ongoing wholesale electricity costs. The surcharge was made permanent in the CPUC's March 27, 2001 decision, referred to below. On January 26, 2001, an assigned CPUC commissioner's ruling was issued in the Utility's rate stabilization plan proceeding. The ruling stated that in phase one of the case, the scope of the proceeding will include (1) reviewing the independent audits of the utilities accounts to determine whether there is a financial necessity for additional relief for the utilities, (2) reviewing TURN's accounting proposal to transfer the undercollected balances in the utilities' TRAs to their respective TCBAs and reviewing the generation memorandum accounts, and (3) considering whether the rate freeze has ended only on a prospective basis. On January 30, 2001, the independent consultants engaged by the CPUC issued their review report on the Utility's financial position as of December 31, 2000, as well as that of PG&E Corporation and the Utility's affiliates. The review found that the Utility made an accurate representation of its financial situation noting accurate representations of its borrowing capabilities, credit condition, and events of default. The review also found that the Utility accurately represented recorded entries to its TRA and TCBA. The review alleged certain deficiencies with respect to bidding strategies, cash conservation matters, and cash flow forecast assumptions. The Utility filed rebuttal testimony on February 14, 2001. Hearings to consider the issues and reports of the independent consultants began on February 20, 2001. On March 27, 2001, the CPUC ruled on parts of the Utility's RSP and granted an increase in rates by adopting an average 3.0 cents per kWh surcharge. Although the increase is authorized immediately, the 3.0 cents per kWh surcharge will not be collected in rates until the CPUC establishes an appropriate rate design for the surcharge, which is not expected to be adopted until May 2001, at the earliest. The revenue generated by the rate increase is to be used only for electric power procurement costs that are incurred after March 27, 2001. The CPUC declared that the revenues generated 50 by this surcharge are subject to refund (1) if not used to pay for such power purchases, (2) to the extent that generators and sellers of power make refunds for overcollections, or (3) to the extent any administrative body or court denies the refunds of overcollections in a proceeding where recovery has been hampered by a lack of cooperation from the Utility. The 3.0 cents per kWh surcharge is in addition to the emergency interim surcharge approved in January 4, 2001, which the CPUC made permanent in this decision. The CPUC also modified accounting rules in response to a proposal made by TURN as described below. Also, on March 27, 2001, the CPUC issued a decision ordering the Utility and the other California investor-owned utilities to pay the DWR a per-kWh price equal to the applicable generation-related retail rate per kWh established for each utility as in effect on January 5, 2001, for each kWh the DWR sells to the customers of each utility. The CPUC determined that the generation-related component of retail rates should be equal to the total bundled electric rate (including the 1 cent per kWh interim surcharge adopted by the CPUC on January 5, 2001) less the following non-generation-related rates or charges: transmission, distribution, public purpose programs, nuclear decommissioning, and the fixed transition amount. The CPUC determined that the Utility's company- wide average generation-related rate component is 6.471 cents per kWh and that this is the amount that should be paid to the DWR for each kWh delivered by the DWR to the Utility's retail customers after February 1, 2001, until specific rates are calculated. The CPUC ordered the utilities to pay the DWR within 45 days after the DWR supplies power to their retail customers, subject to penalties for each day that payment is late. The amount of power supplied to retail end-use customers after March 27, 2001, for which the DWR is entitled to be paid would be based on the product of the number of kWh that the DWR provided 45 days earlier and the Utility's company-wide average generation-related rate of 6.471 cents per kWh, and the additional 3 cent per kWh surcharge described above. The CPUC also ordered that the utilities immediately pay the sums owed to the DWR for power sold by the DWR from January 18, 2001 through January 31, 2001, under California Senate Bill 7X. Based on an estimated number of kWh sold by the DWR, the Utility paid approximately $30 million to the DWR at the rate of 5.471 cents per kWh as adopted by the CPUC. In addition, on April 3, 2001, the CPUC adopted a method to calculate the CPA, as described in Public Utilities Code Section 360.5 (added by AB 1X effective February 1, 2001). Section 360.5 requires the CPUC to determine (1) the portion of each electric utility's electric retail rate effective on January 5, 2001, the CPA, that is equal to the difference between the generation-related component of the utility's retail rate in effect on January 5, 2001, and the sum of the costs of the utility's own generation, QFs contracts, existing bilateral contracts (i.e., entered into before February 1, 2001), and ancillary services, and (2) the amount of the CPA that is allocable to the power sold by the DWR. The CPUC decided that the CPA should be a set rate calculated by determining each utility's generation-related revenues (for the Utility the CPUC has proposed that this be equal to 6.471 cents per kWh multiplied by total kWh sales by the Utility to the Utility's retail customers), then subtracting each utility's statutorily authorized generation-related costs, and dividing the result by each utility's total kWh sales. Each utility's CPA rate will be used to determine the amount of bonds the DWR may issue. Using the CPUC's methodology, but substituting the CPUC's cost assumptions with actual expected costs and including costs the CPUC has refused to recognize, the Utility's calculations show that the CPA for the 11-month period February through December 2001 would be negative by $2.2 billion, (i.e., there would be no CPA available to the DWR) assuming the DWR purchases 84% of the Utility's net open position. (The net open position is the amount of power that cannot be met by the utilities' own or contracted-for generation.) If AB 1X were amended to also include in the CPA all the incremental revenue from the 3 cent per kWh increase discussed above (approximately $2.3 billion for 11 months), then the amount available to the DWR for the CPA for the comparable 11-month period, assuming the Utility were allowed to recover its costs first, would be approximately $100 million. The Utility believes the method adopted by the CPUC is unlawful and inconsistent with Section 360.5 because, among other reasons, it establishes a set rate that does not reflect actual residual revenues, overstates the CPA by excluding and/or understating authorized costs, and to the extent it is dedicated to the DWR does not allow the Utility to recover its own revenue requirements and costs of service. The Utility intends to file an application for rehearing of this decision. The CPUC noted that although the DWR has assumed responsibility to purchase some of the utilities' power requirements, it has not committed to purchase all of the utilities' net open position. To the extent the DWR does not buy enough power to cover the Utility's net open position, the ISO purchases emergency power on the high-priced spot market to meet system reliability requirements and the net open position. The ISO may attempt to charge the Utility a proportionate share of the ISO's purchases. The Utility believes that under the current circumstances and applicable tariffs it is not responsible for such ISO charges. As the DWR has not advised the CPUC of its revenue requirement for the DWR's power purchases, it is unclear how much of the 3 cent surcharge will be needed by the DWR and how much, if 51 any, may be used by the Utility to recover its procurement costs incurred after March 27, 2001 (including any ISO charges). Since the end of January 2001, the Utility has been paying only 15% of amounts due QFs. On March 27, 2001, the CPUC issued a decision requiring the Utility and the other California investor-owned utilities to pay QFs fully for energy deliveries made on and after the date of the decision, within 15 days of the end of the QFs' billing period. The decision permits QFs to establish a 15- day billing period as compared to the current monthly billing period. The CPUC noted that its change to the payment provision was required to maintain energy reliability in California and thus provided that failure to make a required payment would result in a fine in the amount owed to the QF. The decision also adopts a revised pricing formula relating to the California border price of gas applicable to energy payments to all QFs, including those that do not use natural gas as a fuel. Based on the Utility's preliminary review of the decision, the revised pricing formula would reduce the Utility's 2001 average QF energy and capacity payments from approximately 12.7 cents per kWh to 12.3 cents per kWh. The CPUC also adopted TURN's proposal to transfer on a monthly basis the balance in each Utility's TRA to the Utility's TCBA. The TRA is a regulatory balancing account that is credited with total revenue collected from ratepayers through frozen rates and which tracks undercollected power purchase costs. The TCBA is a regulatory balancing account that tracks the recovery of generation- related transition costs. The accounting changes are retroactive to January 1, 1998. The Utility believes the CPUC is retroactively transforming the power purchase costs in the TRA into transition costs in the TCBA. However, the CPUC characterized the accounting changes as merely reducing the prior revenues recorded in the TCBA, thereby affecting only the amount of transition cost recovery achieved to date. The CPUC also ordered that the utilities restate and record their generation memorandum account balances to the TRA on a monthly basis before any transfer of generation revenues to the TCBA. The CPUC found that based on the accounting changes, the conditions for meeting the end of the rate freeze have not been met. The Utility believes the adoption of TURN's proposed accounting changes results in illegal retroactive ratemaking, constitutes an unconstitutional taking of the Utility's property, and violates the federal filed rate doctrine. The Utility also believes the other CPUC decisions are similarly illegal to the extent they would compel the Utility to make payments to the DWR and QFs without providing adequate revenues for such payments. The Utility plans to challenge the decisions in appropriate legal forums. Bilateral Contracts Under the terms of AB 1890, the Utility was required to purchase all of its power from the PX and ISO to meet the needs of its customers. On August 3, 2000, after the California energy crisis had begun, the CPUC approved the Utility's use of bilateral contracts, subject to the CPUC approving a set of standards or criteria by which the reasonableness of such contracts would be reviewed on an after-the-fact basis. The CPUC has yet to approve such standards or criteria. In October 2000, the Utility entered into multiple bilateral contracts with suppliers for long-term electricity deliveries. As of December 31, 2000, these contracts ranged from approximately 1,228,000 MWhs to 6,344,800 MWhs of supply annually. The contracts extended from 2001 to 2005. Each of the contracts was for delivery beginning January 1, 2001 or later. As a result of the energy crisis, certain of these contracts were terminated, subsequent to December 31, 2000. PX Energy Credits In accordance with CPUC regulations, the Utility provides a PX energy credit to those customers (known as direct access customers) who have chosen to buy their electric energy from an energy service provider (ESP) other than the Utility. As wholesale power prices began to increase beginning in June 2000, the level of PX credits increased correspondingly to the point where the credits exceeded the Utility's distribution and transmission charges to direct access customers. During 2000, the PX credits reduced electric revenue by $472 million, although the Utility ceased paying most of these credits in December 2000. These amounts are reflected on the accompanying consolidated balance sheet at December 31, 2000. As of March 29, 2001, the estimated total of accumulated credits for direct access customers that have not been paid by the Utility is approximately $503 million. The actual amount that will be refunded to ESPs will be dependent upon when the rate freeze ends and whether there are any adjustments made to wholesale energy prices by the FERC. Generation Divestiture In April 1999, the Utility sold three fossil-fueled generation plants for $801 million. At the time of sale, these three fossil-fueled plants had a combined book value of $256 million and a combined capacity of 3,065 MW. In May 1999, the Utility sold its complex of geothermal generation facilities for $213 million. At the time of sale, these facilities had a combined book value of $244 million and a combined capacity of 1,224 MW. The Lake facility was sold at a gain of $8 million while the Sonoma facility was sold at a loss of $39 million. The gains from the sale of the fossil-fueled generation plants and the Lake facility were used to offset other transition costs. Likewise, the loss from the sale of the Sonoma geothermal generation facilities is being recovered as a transition cost. The Utility has retained a liability for required environmental remediation related to any pre-closing soil or groundwater contamination at the plants it has sold. Under the California electric industry restructuring legislation, the valuation of the Utility's remaining generation assets (primarily its hydroelectric facilities) must be completed by December 31, 2001. Any excess of market value over the assets' book value would be used to offset the Utility's transition costs. In August 2000, the Utility and a number of interested parties filed an application with the CPUC requesting that the CPUC approve a settlement agreement reached by these parties. The agreement was filed in the Utility's proceeding to determine the market value of its hydroelectric generation assets. In this settlement agreement, the Utility indicated that it would transfer its hydroelectric generation assets, at a negotiated value of $2.8 billion, to an affiliate. Due to the high wholesale prices and the corresponding increase in the value of its hydroelectric generation assets, in November 2000 as part of an application with the CPUC seeking approval of a five-year RSP, the Utility withdrew its support from the settlement agreement, eliminating it from consideration in the proceeding. In January 2001, California Assembly Bill 6 was passed which prohibits disposal of any of the Utility's generation facilities, including the hydroelectric facilities, prior to January 1, 2006. In December 2000, the Utility submitted updated testimony in the hydroelectric valuation proceeding indicating the market value of the hydroelectric assets ranges from $3.9 billion to $4.2 billion assuming a competitive auction or other arms-length sale. At December 31, 2000, the book value of the Utility's net investment in hydroelectric generation assets was approximately $692 million. Diablo Canyon Benefits Sharing As required by a prior CPUC decision on June 30, 2000, the Utility filed an application with the CPUC requesting approval of its proposal for sharing with ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon. The net benefit sharing methodology proposed in the Utility's application would be effective at the end of the current electric rate freeze for the Utility's customers and would continue for as long as the Utility owned Diablo Canyon. Under the proposal, the Utility would share the net benefits of operating Diablo Canyon based on the audited profits from operations, determined consistent with the prior CPUC decisions. If Diablo Canyon experiences losses, such losses would be deferred and netted against profits in the calculation of the net benefits in subsequent periods (or against profits in prior periods if subsequent profits are insufficient to offset such losses). Any changes to the net sharing methodology must be approved by the CPUC. The CPUC has suspended the proceedings to consider the net benefit sharing proposal. In the Utility's RSP, parties have proposed that the requirement to establish a sharing methodology be rescinded and the Diablo Canyon be placed on cost-of-service ratemaking. It is uncertain what future ratemaking will be applicable to Diablo Canyon. Cost of Electric Energy For the years ended December 31, 2000 and 1999, and the period March 31, 1998 (the PX establishment date) to December 31, 1998, the cost of electric energy for the Utility, reflected on the Utility's Statement of Consolidated Operations, comprises the cost of fuel for electric generation and QF purchases, the cost of PX purchases, and ancillary services charged by the ISO, net of sales to the PX, as follows: Year Ended December 31, ------------------------ (in millions) 2000 1999 1998 Cost of fuel resources at market prices $ 9,512 $3,233 $ 3,370 Proceeds from sales to the PX (2,771) (822) (1,049) Total Utility cost of electric energy $ 6,741 $2,411 $ 2,321 Note 3: Subsequent Events Credit Rating Downgrades As a result of the Utility's deteriorating financial condition from the California energy crisis, the major credit agencies have downgraded the long- term and short-term credit ratings of both PG&E Corporation and the Utility. The following is a summary of current credit ratings by Standard & Poor's (S&P) and Moody's Investors Service (Moody's) as of March 29, 2001, for the Utility:
Standard & Poors Current Ratings Corporate credit rating D/D Commercial paper D Senior secured debt CCC Senior unsecured debt CC Preferred stock D Shelf senior secured/unsecured subordinated debt CCC/CC Shelf preferred stock D Moody's Investors Service Commercial paper Not prime Mortgage B3 Secured pollution control bonds B3 Issuer rating Caa2 Senior unsecured notes Caa2 Unsecured debentures Caa2 Unsecured pollution control bonds Caa2 Bank credit facility Caa2 Preferred Stock caa Shelf senior secured debt (P)B3 Shelf senior unsecured debt (P)Caa2 Shelf preferred stock (P)caa Variable rate demand bonds Speculative Grade
PG&E Corporation On January 16 and 17, 2001, in response to the continued energy crisis, S&P and Moody's, respectively, downgraded PG&E Corporation's credit ratings to below investment grade. The downgrade, in addition to PG&E Corporation's and the Utility's non-payment of commercial paper constituted an event of default under both the $436 million and the $500 million credit facilities. In response, the banks immediately terminated their outstanding commitments under these defaulted credit facilities. Through February 28, 2001, PG&E Corporation had $501 million in outstanding commercial paper, of which $457 million came due and was not paid. On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1 billion in aggregate proceeds of two term loans under a common credit agreement with General Electric Capital Corporation and Lehman Commercial Paper, Inc. In accordance with the credit agreement, the proceeds, together with other PG&E Corporation cash, were used to pay the $501 million in outstanding commercial paper, $434 million in borrowings under PG&E Corporation's long- term revolving credit facility, and $116 million to PG&E Corporation's shareholders of record on December 15, 2000 in satisfaction of the defaulted fourth quarter 2000 common stock dividend. Further, approximately $85 million was used to pre-pay the first year's interest under the credit agreement and to pay transaction expenses associated with the debt restructuring. The loans will mature on March 2, 2003 (which date may be extended at the option of PG&E Corporation for up to one year upon payment of a fee of up to 5% of the then outstanding indebtedness), or earlier, if a spin-off of the shares of the NEG were to occur. As required by the credit agreement, PG&E Corporation has given the lenders a security interest in the NEG. The loans prohibit PG&E Corporation from declaring dividends, making other distributions to shareholders, or incurring additional indebtedness until the loans have been repaid, although PG&E Corporation could incur unsecured indebtedness provided it meets certain requirements. The loan also prohibits NEG from making distributions to PG&E Corporation and restricts certain other intercompany transactions. Further, as required by the credit agreement, NEG LLC has granted to affiliates of the lenders options that entitle these affiliates to purchase up to 3% of the shares of the NEG at an exercise price of $1.00 based on the following schedule: Percentages of Shares subject to NEG Options ---------------------- Loans outstanding for: Less than six months 2.0% Six to eighteen months 2.5% Greater than eighteen months 3.0% The option becomes exercisable on the date of full repayment or, earlier, if an initial public offering of the shares of the NEG (IPO) were to occur. The NEG has the right to call the option in cash at a purchase price equal to the fair market value of the underlying shares, which right is exercisable at any time following the repayment of the loans. If an IPO has not occurred, the holders of the option have the right to require the NEG or PG&E Corporation to repurchase the option at a purchase price equal to the fair market value of the underlying shares, which right is exercisable at any time after the earlier of full repayment of the loans or 45 days before expiration of the option. The option will expire 45 days after the maturity of the loans. PG&E Corporation will account for the options by recording the fair value of the option at issuance as a debt issuance cost to be amortized over the expected life of the loans. The options will be marked to market through an increase or decrease to current earnings. Under the credit agreement, the NEG is permitted to make investments, incur indebtedness, sell assets, and operate its businesses pursuant to its business plan. Mandatory repayment of the loans will be required from the net after-tax proceeds received by the NEG or any subsidiary of the NEG from (1) the issuance of indebtedness, (2) the issuance or sale of any equity (except for cash proceeds from an IPO), (3) asset sales, and (4) casualty insurance, condemnation awards, or other recoveries. However, if such proceeds are retained as cash, used to pay indebtedness, or reinvested in the NEG's businesses, mandatory repayment will not be required. Any net proceeds from an IPO must be used to reduce the outstanding balance of the loans to $500 million or less. In addition, all distributions made by the NEG to PG&E Corporation other than (1) to reimburse PG&E Corporation for corporate overhead expenses, (2) pursuant to any tax sharing arrangements which the NEG and PG&E Corporation are parties, and (3) pursuant to any note that may be payable to PG&E Corporation in connection with an IPO and similar arrangements must be used to pay the loans. The credit agreement also prohibits PG&E Corporation from taking certain actions, including a restriction against declaring or paying any dividends for as long as the loans are outstanding. A breach of covenants, including requirements that (1) the NEG's unsecured long-term debt have a credit rating of at least BBB- by S&P or Baa3 by Moody's, (2) the ratio of fair market value of the NEG to the aggregate amount of principal then outstanding under the loans is not less than 2 to 1, and (3) PG&E Corporation maintain a cash or cash equivalent reserve of at least 15% of the total principal amount of the loans outstanding, entitles the lenders to declare the loans to be due and payable. Utility The Utility had been drawing on its $1 billion facility to pay maturing commercial paper. As of January 16, 2001, the Utility had drawn down $938 million under this facility. On January 16 and 17, 2001, S&P and Moody's, respectively, downgraded the Utility's credit ratings to below investment grade. This downgrade resulted in an event of default under the $850 million credit facility, while the Utility's non-payment of commercial paper exceeding $100 million constituted events of default under both the $1 billion and $850 million credit facilities. Although they have the ability under the terms of the various agreements, no bank has called for accelerated payment of any of the Utility's outstanding debt, nor has any bank permanently waived any requirements violated which resulted in the events of default described above. Lenders have agreed to forbear from accelerating payments until April 13, 2001. On January 10, 2001, the Board of Directors of the Utility suspended the payment of its fourth quarter 2000 common stock dividend in an aggregate amount of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E Holdings, Inc., a subsidiary of the Utility. In addition, the Utility's Board of Directors decided not to declare the regular preferred stock dividends for the three-month period ending January 31, 2001, normally payable on February 15, 2001. Dividends on all Utility preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock. After the downgrade, the PX notified the Utility that the ratings downgrade required the Utility to post collateral for all transactions in the PX day-ahead market. Since the Utility was unable to post such collateral, the PX suspended the Utility's trading privileges effective January 19, 2001 in the day-ahead market. The PX also sought to liquidate the Utility's block forward contracts for the purchase of power. On January 25, 2001, a California Superior Court judge granted the Utility's application for a temporary restraining order, which thereby restrained and enjoined the PX and its agents from liquidating the Utility's contracts in the block forward market, pending hearing on a preliminary injunction on February 5, 2001. Immediately before the hearing on the preliminary injunction, California Governor Gray Davis, acting under California's Emergency Services Act, commandeered the contracts for the benefit of the state. Under the Act, the state must pay the Utility the reasonable value of the contracts, although the PX may seek to recover the monies that the Utility owes to the PX from any proceeds realized from those contracts. Discussions and negotiations on this issue are currently ongoing between the state and the Utility. As of March 29, 2001, the Utility was in default and/or had not paid the following:
Description Amount in millions) (unaudited) Items not paid PX/ISO--real time market deliveries $1,448 Qualifying facilities 643 Direct access credits due to energy service providers 503 Commercial paper 861 Bank loans 939* Other 26 Total Items Not Paid $4,420 Items coming due through April 30, 2001 PX/ISO--real time market deliveries $ 550 Qualifying facilities 340 Gas suppliers 470 Other 140 Total coming due 1,500 Total cash on hand at March 29, 2001 $2,600
* Loans that lenders have agreed to forbear through April 13, 2001. Additionally, the Utility may owe the DWR for purchases that the DWR has made on behalf of the Utility's customers. As discussed further in Note 2 of the Notes to the Consolidated Financial Statements, there is a dispute over how much the Utility owes the DWR. Also, the DWR has indicated that it intends to purchase power at only "reasonable prices." The ISO has continued to purchase power at prices in excess of the DWR's as yet undisclosed ceiling and is expected to bill the Utility for the differential. The Utility does not yet know what the total expected billing is for these purchases. As a result of (1) the failure by the state to assume the full procurement responsibility for the Utility's net open position as was provided under AB1X, (2) the negative impact of recent actions by the CPUC that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) a lack of progress in negotiations with the state to provide a solution for the energy crisis, and (4) the adoption by the CPUC of an illegal and retroactive accounting change that would appear to eliminate the Utility's true uncollected purchased power costs, the Utility filed a voluntary petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code on April 6, 2001. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdiction of the bankruptcy court. Subject to the approval of the bankruptcy court, the Utility's intent is to pay its ongoing costs of doing business while seeking resolution of the wholesale power crisis. It is the Utility's intention to continue to pay employees, vendors, suppliers, and other creditors to maintain essential distribution and transmission services. However, the Utility is not in a position to pay maturing or accelerated obligations, nor is the Utility in a position to pay the ISO, PX, and the QFs, the massive amounts due for the Utility's power purchases above the amount included in rates for power purchase costs. The Utility's current actions are intended to allow the Utility to continue to operate while efforts to reach a regulatory or legislative solution continue. The Utility has also deferred quarterly interest payments on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series A, (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly deferred. Distributions can be deferred up to a period of five years per the indenture. Investors will accumulate interest on the unpaid distributions at the rate of 7.90%. National Energy Group In December 2000 and in January and February 2001, PG&E Corporation and the NEG undertook a corporate restructuring of the NEG, known as a "ringfencing" transaction. The ringfencing complied with credit rating agency criteria, enabling NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and PG&E ET to receive or retain their own credit rating, based upon their creditworthiness. The ringfencing involved the creation of new special purpose entities (SPEs) as intermediate owners between PG&E Corporation and its non CPUC-regulated subsidiaries. These new SPEs are: PG&E National Energy Group, LLC, which owns 100% of the stock of the NEG; GTN Holdings LLC, which owns 100% of the stock of PG&E GTN; and PG&E Energy Trading Holdings LLC which owns 100% of the stock of PG&E Corporation's energy trading subsidiaries, PG&E Energy Trading--Gas Corporation, PG&E Energy Trading Holdings Corporation, and PG&E Energy Trading-Power, L.P. In addition, the NEG's organizational documents were modified to include the same structural elements as the SPEs to meet credit rating agency criteria. Ringfencing is intended to reduce the likelihood that the assets of the ringfenced entities would be substantially consolidated in a bankruptcy proceeding involving such companies' ultimate parent, and to thereby preserve the value of the "protected" entities as a whole. The SPEs require unanimous approval of their respective boards of directors, which includes an independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not declare or pay dividends unless the respective boards of directors has unanimously approved such action and the company meets specified financial requirements. Note 4: Price Risk Management and Financial Instruments Trading and Non-Trading Activities The following table is a summary of the contract or notional amounts and maturities of commodity derivatives related to commodity price risk management as of December 31, 2000 and 1999:
Maximum Electricity, Natural Gas, Purchase Sale Term in and Natural Gas Liquids Contracts (Long) (Short) Years (billions of MMBtu equivalents/(1)/) NEG: Trading Activities--December 31, 2000 Swaps 2.04 1.95 6 Options 0.46 0.37 8 Futures 0.14 0.15 3 Forward Contracts 1.42 1.38 16 Trading Activities--December 31, 1999 Swaps 2.38 2.33 7 Options .94 .86 8 Futures .19 .18 2 Forward Contracts 1.49 1.46 12 Non-Trading Activities--December 31, 2000 Forward Contracts 1.70 0.74 22 Non-Trading Activities--December 31, 1999 Forward Contracts 0.02 0.01 3 Utility: Non-Trading Activities--December 31, 2000 Swaps 0.06 0.07 1 Forward Contracts 0.02 -- 5 Non-Trading Activities--December 31, 1999 Swaps -- 0.01 1
(1) One MMBtu is equal to one million British thermal units. Electricity contracts, measured in megawatts, were converted to MMBtu equivalents using a conversion factor of 10 MMBtus per 1 MWh. Natural gas liquids contracts were converted to MMBtu equivalents using an appropriate conversion factor for each type of natural gas liquids product. The following table is a summary of the contract or notional amounts and maturities of PG&E Corporation's financial instruments used for non-trading activities as of December 31:
2000 1999 ----- ----- (in millions) Notional Contract Notional Contract Amount Expiration Amount Expiration Non-Trading Activities: Interest Rate $1,756 2012 $ 724 2003 Foreign Currency 94 2003 104 2002
Notional amounts shown represent volumes that are used to calculate amounts due under the agreements and do not necessarily represent volumes exchanged. Because the changes in market value of these derivatives used as hedges are generally offset by changes in the value of the underlying physical transactions, the amounts at risk are significantly lower than these notional amounts might suggest. PG&E Corporation's net gain (loss) on trading contracts held during the years ended December 31, are as follows:
(in millions) 2000 1999 1998 Swaps $ 173 $ 15 $ 69 Options 66 (41) (49) Futures (106) (36) (63)
Forward Contracts 72 98 101 Net gain $ 205 $ 36 $ 58
The following table discloses PG&E Corporation's estimated average fair value and ending fair value of price risk management assets and liabilities at December 31, 2000 and 1999.
Average Ending Fair Value Fair Value ---------- ---------- (in millions) Assets Liabilities Assets Liabilities Trading Activities--December 31, 2000 Swaps $ 163 $ 75 $ 286 $ 121 Options 153 106 250 171 Futures 34 78 33 98 Forward Contracts 2,053 1,921 3,496 3,476 Total $2,403 $2,180 $4,065 $3,866 Noncurrent portion $2,026 $1,867 Current portion $2,039 $1,999 Trading Activities--December 31, 1999 Swaps $ 218 $ 197 $ 50 $ 33 Options 75 87 56 41 Futures 89 119 35 58 Forward Contracts 475 356 588 398 Total $ 857 $ 759 $ 729 $ 530 Noncurrent portion $ 329 $ 207 Current portion $ 400 $ 323
Credit Risk The use of financial instruments to manage the risks associated with changes in energy commodity prices creates exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations. The counterparties in PG&E Corporation's and the Utility's portfolio consist primarily of investor-owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies. PG&E Corporation and the Utility minimize credit risk by dealing primarily with creditworthy counterparties in accordance with established credit approval practices and limits. PG&E Corporation assesses the financial strength of its counterparties at least quarterly and requires that counterparties post security in the forms of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits. Neither PG&E Corporation nor the Utility has experienced material losses due to the nonperformance of counterparties in 2000. Counterparties considered to be investment grade or higher comprise 76% of the total credit exposure. At December 31, 2000, PG&E Corporation's and the Utility's gross credit risk amounted to $3.3 billion and $978 million, respectively. Fair Value of Financial Instruments PG&E Corporation's financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and certain accrued liabilities, notes payable, commercial paper, capital leases, and long-term debt. The fair value of these financial instruments, with the exception of long- term receivables, fixed rate debt, and interest rate swaps, approximates their carrying value as of December 31, 2000 and 1999, due to their short-term nature or due to the fact that the interest rate paid on the instrument is variable. The carrying amounts of the long-term receivables approximate fair value at December 31, 2000 and 1999, as the assumptions used to value these instruments at the acquisition date had not changed. The fair values of long-term receivables and long-term debt were estimated using discounted cash flows analysis, based on PG&E Corporation's current incremental borrowing rate. The approximate carrying values were based on currently quoted market prices for similar types of borrowing arrangements. The fair value of interest rate swap agreements, which are not carried on the consolidated balance sheets, is estimated by calculating the present value of the difference between the total fixed payments of the interest rate swap agreements and the total floating payments using the appropriate current market rates. The carrying amount and fair value of PG&E Corporation's long-term receivables, long-term debt, and interest rate swaps as of December 31, 2000 and 1999, is summarized as follows:
2000 1999 ---- ---- PG&E Corporation Carrying Fair Value Carrying Fair Value (in millions) Amount Amount Long-term receivables $ 611 $ 526 $ 680 $ 680 Long-term debt 9,157 9,010 9,561 9,393 Interest rate swaps -- (73) -- (9)
Fair value of the Utility's rate reduction bonds, and Utility obligated mandatorily redeemable preferred securities of trust holding solely Utility subordinated debentures, are all determined based on quoted market prices. Fair value of the Utility's preferred stock with mandatory provisions is based on indicative market prices. Where quoted or indicative market prices are not available, the estimated fair value is determined using other valuation techniques (for example, the present value of future cash flows). Most of the Utility's debt is determined using quoted market prices, but the fair value of a small portion of Utility debt is determined using the present value of future cash flows. See Note 3 of the Notes to the Consolidated Financial Statements for subsequent events regarding PG&E Corporation's and the Utility's credit facilities. At December 31, 2000 and 1999, the Utility's carrying amount and ending fair value of its financial instruments was:
2000 1999 ---- ---- Utility: Carrying Fair Value Carrying Fair Value (in millions) Amount Amount Nuclear decommissioning funds noncurrent asset (see Note 11) $1,328 $1,328 $1,264 $1,264 Total long-term debt(1) (see Note 8) 5,716 5,320 5,342 5,217 Rate reduction bonds(2) (see Note 9) 2,030 2,044 2,321 2,265 Preferred stock with mandatory redemption provisions (see Note 7) 137 98 137 140 Utility obligated mandatorily redeemable preferred securities of trust holding solely Utility subordinated debentures (See note 7) 300 180 300 267
(1) Total long-term debt includes the current portion of long-term debt. (2) Rate reduction bonds include the current portion of rate reduction bonds. Note 5: Acquisitions and Disposals On September 28, 2000, the NEG purchased for $311 million the Attala Generating Company LLC, which owns a gas-fired power plant under construction. Under the purchase agreement, the NEG prepaid the estimated remaining construction costs, which are being managed by the seller. The project, which was approximately 75% complete as of December 31, 2000, is expected to begin commercial service in July 2001. In connection with the acquisition, the NEG also assumed industrial revenue bonds in the amount of $158 million. The seller has agreed to pay off the bonds prior to December 15, 2001; accordingly, the NEG recorded a receivable equal to the amount of the outstanding bonds and accrued interest at December 31, 2000. On January 27, 2000, PG&E Corporation signed a definitive agreement with El Paso Field Services Company (El Paso) providing for the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of PG&E Gas Transmission, Texas Corporation, PG&E Gas Transmission Teco, Inc., and their subsidiaries (PG&E GTT). PG&E GTT assets consist of 8,500 miles of natural gas and natural gas liquids pipeline, nine natural gas processing plants, and natural gas storage facilities, all located in Texas. Given the terms of the sales agreement, in 1999 PG&E Corporation recognized a charge against pre-tax earnings of $1,275 million, to reflect PG&E GTT's assets at their fair value. The composition of the pre-tax charge is as follows: (1) an $819 million write-down of net property, plant, and equipment, (2) the elimination of the unamortized portion of goodwill in the amount of $446 million, and (3) an accrual of $10 million representing selling costs. On December 22, 2000, after receipt of governmental approvals, PG&E Corporation completed the stock sale. The total consideration received was $456 million, less $150 million used to retire the PG&E GTT short-term debt, and the assumption by El Paso of PG&E GTT long-term debt having a book value of $564 million. The final sale price is subject to adjustment during a 120-day working capital true-up period. The NEG recorded a gain of approximately $20 million based on its best estimate of the final sales price. PG&E GTT's total assets and liabilities, including the charge noted above, included in PG&E Corporation's Consolidated Balance Sheet at December 31, 1999, were as follows: (in millions) Assets Current assets $ 229 Noncurrent assets 988 Total assets 1,217 Liabilities Current liabilities 448 Noncurrent liabilities 624 Total liabilities 1,072 Net assets $ 145 The following table reflects PG&E GTT's results of operations included in PG&E Corporation's Statement of Consolidated Operations for the years ended December 31: (in millions) 2000 1999 1998 Revenue $ 873 $ 1,753 $2,064 Operating expenses 869 3,058 2,115 Operating income (loss) 4 (1,305) (51) Interest expense and other, net (36) 7 (50) Sales price true-up 20 -- -- Income (Loss) before income taxes (12) (1,298) (101) Income tax provision (benefit) (32) (390) (31) Net income (loss) $ 20 $ (908) $ (70) In December 1999, PG&E Corporation's Board of Directors approved a plan to dispose of PG&E Energy Services (PG&E ES), a wholly owned subsidiary, through a sale. The disposal has been accounted for as a discontinued operation, and PG&E Corporation's investment in PG&E ES was written down to its then estimated net realizable value. In addition, PG&E Corporation provided a reserve for anticipated losses through the anticipated date of sale. The total provision for discontinued operations was $58 million, net of income taxes of $36 million at December 31, 1999. Of this amount, $33 million (net of taxes) was allocated toward operating losses for the period leading up to the intended disposal date. In 2000, $31 million (net of taxes) of actual operating losses was charged against this reserve. During the second quarter of 2000, the NEG finalized the transactions related to the disposal of the energy commodity portion of PG&E ES for $20 million, plus net working capital of approximately $65 million, for a total of $85 million. In addition, the sale of the Value-Added Services business and various other assets was completed on July 21, 2000, for a total consideration of $18 million. For the year ended December 31, 2000, an additional estimated loss of $40 million (or $0.11 per share), net of income tax of $36 million, was recorded as actual losses in connection with the disposition exceeded that originally estimated. The principal reason for the additional loss was due to the mix of assets, and the structure and timing of the actual sales agreements, as opposed to the one reflected in the initial provision established in 1999. In addition, the worsening energy situation in California also contributed to the additional loss incurred. The PG&E ES business segment generated net losses from operations of $40 million (or $0.11 per share) for the year ended December 31, 1999. In September 1998, PG&E Gen through its indirect subsidiary USGen New England, Inc. (USGenNE), acquired a portfolio of electric generating assets and power supply agreements from a wholly-owned subsidiary of the New England Electric System (NEES). The purchase price, including fuel and other inventories and transaction costs, was approximately $1.8 billion funded through $1.3 billion of debt and a $425 million equity contribution from PG&E Corporation. The net purchase price was allocated as follows: electric generating assets of $2.3 billion classified as property, plant, and equipment, long-term receivables of $0.8 billion, and out-of-market contractual obligations of $1.3 billion and asset contracts related to acquired power sales agreement of $45 million. The acquisition of the NEES assets was considered an asset purchase. Accordingly, the purchase has been allocated to the assets purchased and the liabilities assumed based upon an assessment of fair value at the date of acquisition. The assets acquired included hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 MW. In addition, the NEG, USGenNE, assumed 23 multi-year power purchase agreements representing an additional 800 MW of production capacity. The NEG, through a wholly-owned subsidiary, entered into the agreements as part of the acquisition, which (1) provided that a wholly-owned subsidiary of NEES would make payments through January 2008 for the purchase power agreements, and (2) required that the NEG, through its wholly-owned subsidiary, provide electricity to certain NEES affiliates under contracts that expire at various times through 2008. In July 1998, PG&E Corporation sold its Australian energy holdings for $126 million. PG&E Corporation recognized a loss of approximately $23 million related to the sale, which is included in other income (expense) on the Statement of Consolidated Operations. Note 6: Common Stock PG&E Corporation PG&E Corporation has authorized 800 million shares of no-par common stock, of which 387 million and 384 million shares were issued as of December 31, 2000 and 1999, respectively. During the years ended December 31, 2000 and 1999, PG&E Corporation repurchased $2 million and $693 million of its common stock, respectively. The 2000 repurchases were for the Dividend Reinvestment Program. The 1999 repurchases were executed through open market purchases and an accelerated share repurchase program. Under the 1999 accelerated share repurchase program agreement, PG&E Corporation repurchased in a specific transaction 16.6 million shares of its common stock at a cost of $502 million. In connection with this transaction, PG&E Corporation entered into a forward contract with an investment institution. PG&E Corporation settled the forward contract and its additional obligation of $29 million in September 1999. A wholly owned subsidiary of PG&E Corporation made this repurchase, along with subsequent stock repurchases. The stock held by the subsidiary is treated as treasury stock and reflected as stock held by subsidiary on the Consolidated Balance Sheet of PG&E Corporation. In October 1999, the Board of Directors of PG&E Corporation authorized an additional $500 million for the purpose of repurchasing shares of PG&E Corporation's common stock. The authorization for share repurchases extends through September 30, 2001. As of December 31, 2000, a subsidiary of PG&E Corporation had repurchased 23.8 million shares at a cost of $690 million. On January 10, 2001, the Board of Directors of PG&E Corporation suspended the payment of its fourth quarter 2000 stock dividend of $.30 per common share declared by the Board of Directors on October 18, 2000 and payable on January 15, 2001 to shareholders of record as of December 15, 2000. On March 2, 2001, PG&E Corporation refinanced its debt obligations with the $1 billion aggregate proceeds of two term loans under a common credit agreement with General Electric Capital Corporation and Lehman Commercial Paper, Inc. (see Note 3). In accordance with the credit agreement, a part of the proceeds, together with other PG&E Corporation cash, was used to pay $116 million to PG&E Corporation shareholders of record as of December 15, 2000, in satisfaction of the defaulted fourth quarter 2000 common stock dividend. PG&E Corporation is precluded by these loan agreements from declaring further dividends or repurchasing its common stock. Utility PG&E Corporation and a subsidiary of the Utility hold all of the Utility's outstanding common stock. The Utility has authorized 800 million shares of $5 par value common stock of which 321 million shares were issued as of December 31, 2000 and 1999. In April 2000, a subsidiary of the Utility repurchased from PG&E Corporation 11.9 million shares of the Utility's common stock at a cost of $275 million. In December 1999, 7.6 million shares of the Utility's common stock, with an aggregate purchase price of $200 million, was purchased by the same subsidiary of the Utility. Total shares purchased were 19.5 million with an aggregate purchase price of $475 million. These repurchases are reflected as stock held by subsidiary in the Utility's Consolidated Balance Sheet. Earlier in 1999, the Utility repurchased and cancelled 20 million shares of its common stock from PG&E Corporation for an aggregate purchase price of $726 million to maintain its authorized capital structure. The CPUC requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation. On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $110 million, declared in October 2000, to PG&E Corporation. The Utility has suspended payment of its common and preferred dividends. Dividends on preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on common stock. Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures Shareholder Rights Plan of PG&E Corporation On December 20, 2000, the Board of Directors of PG&E Corporation declared a distribution of preferred stock purchase rights (the Rights) at a rate of one Right for each outstanding share of PG&E Corporation's common stock, no par value. The Rights apply to outstanding shares of PG&E Corporation common stock held as of the close of business on January 2, 2001, and for each share of common stock issued by PG&E Corporation thereafter and before the "distribution date", as described below. Each Right entitles the registered holder, in certain circumstances, to purchase from PG&E Corporation one one-hundredth of a share (a Unit) of PG&E Corporation's Series A Preferred Stock, par value $100 per share, at an initially fixed purchase price of $95 per Unit, subject to adjustment. Effective December 22, 2000, the PG&E Corporation Dividend Reinvestment Plan was modified to note these changes. The Rights are not exercisable until the distribution date and will expire December 22, 2010, unless redeemed earlier by the PG&E Corporation Board of Directors. The distribution date will occur upon the earlier of (1) 10 days following a public announcement that a person or group (other than the PG&E Corporation, any of its subsidiaries, or its employee benefit plans) has acquired or obtained the right to acquire beneficial ownership of 15% or more of the then-outstanding shares of PG&E Corporation common stock and (2) 10 business days (or later, as determined by the Board of Directors) following the commencement of a tender offer or exchange offer that would result in a person or group owning 15% or more of the then-outstanding shares of PG&E Corporation common stock. After the distribution date, certain triggering events will enable the holder of each Right (other than a potential acquiror) to purchase Units of Series A Preferred Stock having twice the market value of the initially fixed exercise price, i.e., at a 50% discount. Until a Right is exercised, the holder shall have no rights as a shareholder of PG&E Corporation, including, without limitation, the right to vote or to receive dividends. A total of 5,000,000 shares of preferred stock will be reserved for issuance upon exercise of the Rights. The Units of preferred stock that may be acquired upon exercise of the Rights will be non-redeemable and subordinate to any other shares of preferred stock that may be issued by PG&E Corporation. Each Unit of preferred stock will have a minimum preferential quarterly dividend rate of $.01 per Unit but will, in any event, be entitled to a dividend equal to the per share dividend declared on the common stock. In the event of liquidation, the holder of a Unit will receive a preferred liquidation payment. The Rights also have certain anti-takeover effects and will cause substantial dilution to a person or group that attempts to acquire the Utility on terms not approved by PG&E Corporation's Board of Directors unless the offer is conditioned on a substantial number of Rights being acquired. The Rights should not interfere with any approved merger or other business combination, as the Board of Directors, at its option, may redeem the Rights. Thus, the Rights are intended to encourage persons who may seek to acquire control of the PG&E Corporation to initiate such an acquisition through negotiations with the PG&E Corporation Board of Directors. However, the effect of the Rights may be to discourage a third party from making a partial tender offer or otherwise attempting to obtain a substantial equity position in the equity securities of, or seeking to obtain control of the PG&E Corporation. To the extent any potential acquirors are deterred by the Rights, the Rights may have the effect of preserving incumbent management in office. Preferred Stock of Utility The Utility has authorized 75 million shares of $25 par value preferred stock, which may be issued as redeemable or non-redeemable preferred stock. At December 31, 2000 and 1999, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock. At December 31, 2000 and 1999, the Utility had issued and outstanding 5,973,456 shares of redeemable preferred stock. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. Annual dividends and redemption prices per share at December 31, 2000, range from $1.09 to $1.76 and from $25.75 to $27.25, respectively. The Utility's redeemable preferred stock with mandatory redemption provisions consists of 3 million shares of the 6.57% series and 2.5 million shares of the 6.30% series at December 31, 2000. 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. At December 31, 2000, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions are $4 million per year beginning 2002, and $3 million per year beginning 2004 for the series 6.57% and 6.30%, respectively. Holders of the Utility's non-redeemable preferred stock 5%, 5.5%, and 6% series have rights to annual dividends per share ranging from $1.25 to $1.50. Due to the California energy crisis, the Utility's Board of Directors decided not to declare the regular preferred stock dividends for the three-month periods ending January 31, 2001 (normally payable on February 15, 2001) and April 30, 2001 (normally payable May 15, 2001). Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. The dividend for the three-month period ending January 31, 2001 became a dividend in arrears and, as such, will accumulate from period to period. 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. Until cumulative dividends on its preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock. Accumulated and unpaid preferred stock dividends for the three-month period ending January 31, 2001 amounted to $6 million. Preferred Stock of the NEG Preferred stock of the NEG consists of $57 million of preferred stock issued by a subsidiary of PG&E Gen. The preferred stock, with $100 par value, has a stated non-cumulative quarterly dividend of $3.35 per share, and is redeemable when there is an excess of available cash. There were 549,594 shares of preferred stock outstanding at December 31, 2000 and 1999. 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 7.9% QUIPS, with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities with an aggregate liquidation value of $9 million. The Trust in turn used the net proceeds from the QUIPS offering and issuance of the common stock securities to purchase subordinated debentures issued by the Utility with a face value of $309 million, due 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 value plus accrued interest through the redemption date. The proceeds of any redemption will be used by the Trust to redeem QUIPS in accordance with their terms. Upon liquidation or dissolution of the Utility, holders of these QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. On March 16, 2001, the Utility deferred quarterly interest payments on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series A, issued by PG&E Capital I due on April 2, 2001, have been similarly deferred. Distributions can be deferred up to a period of five years under the terms of the indenture. Investors will accumulate interest on the unpaid distributions at the rate of 7.90%. Note 8: Long-Term Debt For further information and discussion on credit ratings, downgrades, and events of default, see Note 3, Subsequent Events of the Notes to the Consolidated Financial Statements. Long-term debt at December 31, 2000 and 1999 consisted of the following:
Balance at December 31, ------------ (in millions) 2000 1999 Utility long-term debt First and refunding mortgage bonds Maturity Interest rates 2001-2003 6.25% to 8.75% $ 706 $ 816 2004-2008 5.875% to 6.25% 600 600 2009-2021 6.35% to 8.08% 160 160 2022-2026 5.85% to 8.80% 2,004 2,004 Principal amounts outstanding 3,470 3,580 Unamortized discount net of premium (28) (29) Total mortgage bonds 3,442 3,551 Senior notes, 7.375%, due 2005 680 -- Pollution control loan agreements, variable rates, due 2016-2026 1,267 1,348 Unsecured medium-term notes, 5.81% to 8.45%, due 2001-2014 305 418 Other Utility long-term debt 22 25 Total Utility long-term debt 5,716 5,342 Long-term debt, classified as current 2,374 465 Total Utility long-term debt, net of current portion $3,342 $4,877 National Energy Group long-term debt First mortgage notes, 10.02% to 11.50%, due 2001-2009 $ -- $ 333 Senior notes, 7.10%, due 2005 250 248 Medium term notes Maturity Interest Rates 2001-2003 6.61% to 6.96% 39 70 2001-2009 7.35% to 9.25% -- 229 Senior debentures Maturity Interest Rates 2010 10.00% 159 2025 7.80% 150 150 Stock margin loan, LIBOR + 0.40% due 2003 -- 8 Premium on long-term debt, due 2000-2009 -- 63 Amounts outstanding under credit facilities (See Note 10) 661 649 Capital lease obligations, 8.80%, due 2015 15 16 Term loans, various, 2009-2011 107 116 Mortgage loan payable, 30 day commercial paper rate plus 6.07%, due 2010 8 9 Other long-term debt 22 7 Total National Energy Group long-term debt 1,411 1,898 Current portion of long-term debt 17 93 Total National Energy Group long-term debt, net of current portion $1,394 $1,805 Total long-term debt $4,736 $6,682
PG&E Corporation Utility The Utility's revolving credit agreement balance of $614 million, as of December 31, 2000, went into default subsequent to year-end and remains as such. It has been reclassified to short-term borrowings and is discussed in Note 10 of the Notes to the Consolidated Financial Statements. For further discussion of default status, see Note 3 of the Notes to the Consolidated Financial Statements. For debt obligations, the priority and subordination is as follows: senior secured debt (first and refunding mortgage bonds), and then all other unsecured debt, including notes and bank loans. First and Refunding Mortgage Bonds First and refunding mortgage bonds are issued in series and bear annual interest rates ranging from 5.85% to 8.80%. All real properties and substantially all personal properties of the Utility are subject to the lien of the mortgage, and the Utility is required to make semi-annual sinking fund payments for the retirement of the bonds. Additional bonds may be issued subject to CPUC approval, up to a maximum total amount outstanding of $10 billion, assuming compliance with indenture covenants for earnings coverage and available property balances as security. The Utility redeemed or repurchased $110 million and $281 million of the bonds in 2000 and 1999, respectively, with interest rates ranging from 6.25% to 8.80%. Included in the total of outstanding bonds at December 31, 2000 and 1999 are $345 million of bonds held in trust for the California Pollution Control Financing Authority (CPCFA) with interest rates ranging from 5.85% to 6.625% and maturity dates ranging from 2009 to 2023. In addition to these bonds, the Utility holds long-term pollution control loan agreements with the CPCFA as described below. Senior Notes In November 2000, the Utility issued $680 million of five-year senior notes with an interest rate of 7.375%. The Utility used the net proceeds to repay short-term indebtedness incurred to finance scheduled payments due to the PX for August power purchases from the PX and for other general corporate purposes. The interest rate on the senior notes is subject to adjustment until May 1, 2002. As such, in the event of a downgrade in the rating below A3 by Moody's or A- by S&P prior to May 1, 2002, the interest rate on the notes will be readjusted accordingly. As a result of the credit rating downgrades by S&P and Moody's, as described in Note 3 of the Notes to the Consolidated Financial Statements, there will be an interest rate adjustment of 1.75% on the $680 million senior notes. The revised rate will be increased to 9.125% from 7.375% on May 1, 2001, the next interest payment date. An event of default under the senior notes occured subsequent to December 31, 2000. Under the default provisions, the trustee or holders of not less than 25% of the outstanding notes may declare the amounts outstanding due and payable by notice to the Utility. Accordingly, the amount outstanding, as of December 31, 2000, has been classified as current in the accompanying financial statements. Pollution Control Loan Agreements Pollution control loan agreements from the CPCFA totaled $1,267 million and $1,348 million at December 31, 2000 and 1999, respectively. Interest rates on the loans vary with average annual interest rates. For 2000 the interest rates ranged from 2.10% to 4.81%. These loans are subject to redemption by the holder under certain circumstances. These loans are secured primarily by irrevocable letters of credit (LOC), which mature in 2001 through 2003. In December 2000, two of these loans totaling $81 million, were reacquired by the Utility. On March 1, 2001, a $200 million loan was converted to a fixed interest rate of 5.35%. The Company is in default under the credit provider's reimbursement agreements due to nonpayment of $100 million of commercial paper. Due to this default, the credit providers can declare the $1,267 million of principal and interest immediately due and payable. Through March 29, 2001, no banks had accelerated the debt. Declaration of bankruptcy is also an event of default under certain of the pollution control loan agreements. Under certain of the default provisions, the trustee or holders of the pollution control bonds may declare the amount outstanding due and payable. Accordingly, amounts outstanding at December 31, 2000 under the pollution control agreements have been classified as current in the accompanying financial statements. Medium-Term Notes The Utility has outstanding $305 million of medium-term notes due 2001 to 2014 with interest rates ranging from 5.81% to 8.45%. An event of default under the medium-term notes occured subsequent to December 31, 2000. Under the default provisions, the trustee or holders of not less than 25% of the outstanding notes may declare amounts outstanding due and payable by notice to the Utility. Accordingly, the amount outstanding at December 31, 2000 has been classified as current in the accompanying financial statements. National Energy Group Long-term debt of the NEG consists of first mortgage notes and other secured and unsecured obligations. The first mortgage notes were comprised of three series due annually through 2009, and were secured by mortgages and security interests in the natural gas transmission and natural gas processing facilities and other real and personal property of PG&E GTT. The mortgage indenture required semi-annual payments with one-half of each interest payment and one-fourth of each annual principal payment escrowed quarterly in advance. The mortgage indenture also contained covenants that restricted the ability of PG&E GTT to incur additional indebtedness and precluded cash distributions if certain cash flow coverage were not met. In January 2000, PG&E GTT obtained an amendment that provided PG&E GTT the ability to redeem in whole or in part, its mortgage notes, including the premium set forth in the mortgage note indenture, anytime after January 1, 2000. These notes were assumed by the buyer of PG&E GTT as of December 31, 2000 (see Note 5). In May 1995, PG&E GTN issued $250 million of 10-year senior unsecured notes and $150 million of senior unsecured debentures. Other long-term debt consists of non-recourse project financing associated with unregulated PG&E Generating facilities, premiums, and other loans. Other long-term debt consists of project financing associated with unregulated generation facilities, premiums, and other loans. Repayment Schedule At December 31, 2000, PG&E Corporation's combined aggregate amounts of capital spending, maturing long-term debt, and sinking fund requirements are reflected in the table below:
Expected maturity date 2001 2002 2003 2004 2005 Thereafter Total (dollars in millions) Utility: Long-term debt Variable rate obligations $ 120 $ 697 $ 350 $ 40 $ 40 $ 20 $1,267 Fixed rate obligations $ 274 $ 379 $ 354 $ 392 $1,012 $2,038 $4,449 Average interest rate 8.0% 7.8% 6.3% 6.4% 6.9% 7.3% 7.2% Rate reductions bonds $ 290 $ 290 $ 290 $ 290 $ 290 $ 580 $2,030 Average interest rate 6.2% 6.3% 6.4% 6.4% 6.4% 6.4% 6.4% National Energy Group Long-term debt Variable rate obligations $ 16 $ 94 $ 584 $ 9 $ 9 $ 80 $ 792 Fixed rate obligations $ 1 $ 34 $ 7 $ 1 $ 251 $ 325 $ 619 Average interest rate 9.4% 6.9% 7.0% 9.4% 7.1% 8.9% 8.1%
Note 9: Rate Reduction Bonds In December 1997, PG&E Funding LLC (SPE), a special-purpose entity wholly owned by the Utility, issued $2.9 billion of rate reduction bonds to the California Infrastructure and Economic Development Bank Special Purpose Trust PG&E-1 (Trust), a special-purpose entity. The terms of the bonds generally mirror the terms of the pass-through certificates issued by the Trust. The proceeds of the rate reduction bonds were used by the SPE to purchase from the Utility the right, known as "transition property," to be paid a specified amount from a non-bypassable tariff levied on residential and small commercial customers which was authorized by the CPUC pursuant to state legislation. On January 4, 2001, S&P lowered the short-term credit rating of the SPE to A- 3, and on January 5, 2001, Moody's lowered the short-term credit rating of the SPE to P-3. As a result, on January 8, 2001, remittances for charges paid by ratepayers for the pass-through certificates issued by the Trust were required to be made on a daily basis, as opposed to once a month, as had previously been required. The rate reduction bonds have maturities ranging from 6 months to 7 years, and bear interest at rates ranging from 6.16% to 6.48%. The bonds are secured solely by the transition property and there is no recourse to the Utility or PG&E Corporation. At December 31, 2000, $2,030 million of rate reduction bonds were outstanding. The combined expected principal payments on the rate reduction bonds for the years 2001 through 2005 are $290 million for each year. While the SPE is consolidated with the Utility for purposes of these financial statements, the SPE is legally separate from the Utility. The assets of the SPE are not available to creditors of the Utility or PG&E Corporation, and the transition property is not legally an asset of the Utility or PG&E Corporation. Note 10: Credit Facilities and Short-term Borrowings See Note 3 for discussion of default status regarding credit facilities and short-term borrowings. At December 31, 2000 and 1999, PG&E Corporation had borrowed $5,191 million and $2,148 million, respectively, through short-term borrowings and various credit facilities. At December 31, 2000 and 1999, $661 million and $649 million, respectively, of these borrowings were outstanding balances related to NEG credit facilities, which are classified as long-term debt because the NEG has the ability and intent to finance the amounts outstanding on a long-term basis. The weighted average interest rate on the short-term borrowings as of December 31, 2000 and 1999, was 7.4% and 5.4%, respectively. The following table summarizes PG&E Corporation's lines of credit (see Note 8 of the Notes to the Consolidated Financial Statements) as of December 31, 2000 and 1999:
Amount of Credit Amount of Credit December 31, 2000 December 31, 1999 ----------------- ----------------- Lines of Credit Revolving Revolving (in millions) Credit Outstanding Credit Outstanding Limits Balance Limits Balance PG&E Corporation: 5-year Revolving Credit $ 500 $ 185 $ 500 $ -- 364-day Revolving Credit 436 -- 500 -- Utility: 5-year Revolving Credit 1,000 614 1,000 -- 364-day Revolving Credit 850 -- -- -- National Energy Group: Revolving Credit 1,350 661 1,600 649 Total Lines of Credit $4,136 $1,460 $3,600 $ 649 Short-Term Borrowings PG&E Corporation: Commercial Paper 746 450 Extendible Commercial Notes -- 76 Utility: Commercial Paper 1,225 449
Floating Rate Notes 1,240 -- National Energy Group: Commercial Paper 520 524 Total Commercial Paper and Short-Term Notes $3,731 $1,499 Sub-total $5,191 $2,148 Less: Classified as long-term debt NEG Revolving credit (661) (649) Total Short Term Borrowings $4,530 $1,499 PG&E Corporation PG&E Corporation had $436 million and $500 million revolving credit facilities, which were scheduled to expire in November 2001 and August 2002, respectively. These credit facilities were used to support PG&E Corporation's commercial paper program and other liquidity requirements. As a result of the credit downgrades on January 16 and 17, 2001 (see Note 3), PG&E Corporation began to default under these credit facilities and the banks refused any additional borrowing requests and terminated their commitments under the facilities. As of December 31, 2000, $185 million had been drawn from the $500 million facility. In March 2001, PG&E Corporation secured $1 billion in aggregate proceeds from two term loans under a common credit agreement with General Electric Capital Corporation and Lehman Commercial Paper Inc. to refinance defaulted commercial paper and revolving credit agreements. In connection with PG&E Corporation's refinancing, the revolving credit facilities were cancelled. The total amount of commercial paper outstanding at December 31, 2000, backed by the two facilities, was $746 million. The total amount of commercial paper outstanding at December 31, 1999, backed by the $500 million facility was $450 million. Utility The Utility had a $1 billion revolving credit facility which was scheduled to expire in December 2002. In October 2000, the Utility obtained an additional $1.0 billion credit facility (which was subsequently reduced to $850 million in December 2000) which expires in December 2001. These facilities were used to support the Utility's commercial paper program and other liquidity requirements. As of December 31, 2000, $614 million had been drawn from the $1 billion facility. Due to a subsequent credit rating downgrade, the banks refused any additional borrowing requests and terminated their outstanding commitments under the Utility's two credit facilities (see Note 3). The total amount of commercial paper outstanding at December 31, 2000 backed by the two facilities was $1,225 million. The weighted average interest rate on the Utility's short-term borrowings as of December 31, 2000 and 1999 was 7.5% and 5.3%, respectively. The total amount outstanding at December 31, 1999 backed by the $1 billion facility was $449 million in commercial paper. In addition, the Utility issued a total of $1,240 million in 364-day floating rate notes in November 2000. These notes mature on November 30, 2001, with interest payable quarterly. The nonpayment of the Utility's outstanding commercial paper is an event of default under the floating rate notes, entitling the floating rate note trustees to accelerate the repayment of these notes. (See Note 3) National Energy Group The NEG maintains $1,350 million in five revolving credit facilities, which support commercial paper and Eurodollar borrowing arrangements. At December 31, 2000 and 1999, the NEG had total outstanding balances related to such borrowings of $1,181 million and $1,173 million, respectively. In addition, certain letters of credit held by the NEG reduce the available outstanding facility commitments. At December 31, 2000, approximately $36 million in letters of credit were outstanding. Since the NEG has the ability and intent to refinance certain borrowings, $661 million and $649 million of such borrowings were classified as long-term debt as of December 31, 2000 and 1999, respectively (see Note 8). Certain credit arrangements contain, among other restrictions, customary affirmative covenants, representations, and warranties and are cross-defaulted to the NEG's other obligations. The credit agreements also contain certain negative covenants including restrictions on the following: consolidations, mergers, sales of assets and investments; certain liens on the NEG's property or assets; incurrence of indebtedness; entering into agreements limiting the right of any subsidiary of the NEG to make payments to its shareholders; and certain transactions with affiliates. Certain credit agreements also require that the NEG maintain a minimum ratio of cash flow available for fixed charges and a maximum ratio of funded indebtedness to total capitalization. The NEG was in compliance with all convenants at December 31, 2000. Note 11: Nuclear Decommissioning Decommissioning of the Utility's nuclear power facilities is scheduled to begin for ratemaking purposes in 2015 with scheduled completion in 2034. Nuclear decommissioning means to safely remove nuclear facilities from service and reduce residual radioactivity to a level that permits termination of the Nuclear Regulatory Commission license and release of the property for unrestricted use. The estimated total obligation for nuclear decommissioning costs, based on a 1997 site study, is $1.7 billion in 2000 dollars (or $5.1 billion in future dollars). This estimate assumes after-tax earnings on the tax-qualified and non- tax qualified decommissioning funds of 6.34% and 5.39%, respectively, as well as a future annual escalation rate of 5.5% 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 term of each facility. For the year ended December 31, 2000, 1999, and 1998 nuclear decommissioning costs recovered in rates were $25 million, $26 million, and $33 million, respectively. The CPUC has established a Nuclear Decommissioning Cost Triennial Proceeding to review, every three years, updated decommissioning cost estimates and to establish the annual trust contribution, absent General Rate Cases. At December 31, 2000, the total nuclear decommissioning obligation accrued was $1.3 billion and is included in the balance sheet classification of accumulated depreciation and decommissioning. Decommissioning costs recovered in rates are placed in external trust funds. These funds along with accumulated earnings will be used exclusively for decommissioning and cannot be released from the trust funds until authorized by CPUC. The following table provides a summary of fair value, based on quoted market prices, of these nuclear decommissioning funds:
For the year ended December 31, ------------ (in millions) Maturity Date 2000 1999 U.S. government and agency issues 2001-2030 $ 409 $ 380 Equity securities 239 223 Municipal bonds and other 2001-2034 252 201 Gross unrealized holding gains 447 474 Gross unrealized holding losses (19) (14) Fair value $1,328 $1,264
The proceeds received from sales of securities were $1.4 billion, $1.7 billion, and $1.4 billion in 2000, 1999, and 1998, respectively. The gross realized gains on sales of securities held as available-for-sale were $74 million, $59 million, and $52 million in 2000, 1999, and 1998, respectively. The gross realized losses on sales of securities held as available-for-sale were $64 million, $60 million, and $39 million in 2000, 1999, and 1998, respectively. The cost of debt and equity securities sold is determined by specific identification. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities. The DOE's current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. At the projected level of operation for Diablo Canyon, the Utility's facilities are sufficient to store on-site all spent fuel produced through approximately 2006. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2006. The Utility is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. Note 12: Employee Benefit Plans Several of PG&E Corporation's subsidiaries provide noncontributory defined benefit pension plans for their employees and retirees. In addition, these subsidiaries provide contributory defined benefit medical plans for certain retired employees and their eligible dependents and noncontributory defined benefit life insurance plans for certain retired employees (referred to collectively as other benefits). For both pension and other benefit plans, the Utility's plan represents substantially all of the plan assets and the benefit obligation. Therefore, all descriptions and assumptions are based on the Utility's plan. The schedules below aggregate all of PG&E Corporation's plans. The following schedule reconciles the plans' funded status (the difference between fair value of plan assets and the benefit obligation) to the prepaid or accrued benefit cost recorded on the consolidated balance sheet:
Pension Benefits Other Benefits ---------------- -------------- (in millions) 2000 1999 2000 1999 Change in benefit obligation Benefit obligation at January 1 $(4,807) $(4,977) $ (970) $ (949) Service cost for benefits earned (119) (121) (16) (19) Interest cost (386) (347) (72) (69) Plan amendments (347) -- -- (4) Actuarial gain (loss) (33) 372 (11) (19) Divestiture (acquisition) 7 -- 17 -- Participants paid benefits -- -- (14) (14) Benefits and expenses paid 280 266 57 104 Benefit obligation at December 31 $(5,405) $(4,807) $(1,009) $ (970) Change in plan assets Fair value of plan assets at January 1 $ 8,153 $ 7,104 $ 1,091 $ 951 Actual return on plan assets (66) 1,331 (33) 240 Company contributions 3 4 2 15 Plan participant contribution -- -- 14 14 Divestiture (2) -- -- -- Benefits and expenses paid (280) (286) (62) (103) Fair value of plan assets at December 31 $ 7,808 $ 8,153 $ 1,012 $1,117 Funded Status Plan assets in excess of benefit obligation $ 2,403 $ 3,346 $ 3 $ 121 Unrecognized prior service cost 399 93 15 17 Unrecognized net (loss) gain (2,001) (2,963) (348) (520) Unrecognized net transition obligation 50 65 314 339 Prepaid (accrued) benefit cost $ 851 $ 541 $ (16) $ (43)
The Utility's share of the plan's assets in excess of the benefit obligation for pensions in 2000 and 1999 was $2,407 million and $3,344 million, respectively. The Utility's share of the prepaid (accrued) benefit cost for the pensions in 2000 and 1999 was $864 million and $556 million, respectively. The plan assets of the Utility exceeded its share of the benefit obligation for other benefits by $3 million and $167 million in 2000 and 1999, respectively. The Utility's share of the accrued benefit liability for other benefits in 2000 and 1999 was $15 million and $22 million, respectively. Unrecognized prior service costs and the net gains are amortized on a straight-line basis over the average remaining service period of active plan participants. The transition obligations for pension benefits and other benefits are being amortized over 17.5 years from 1987. Net benefit income (cost) was as follows:
Pension Benefits Other Benefits December 31, December 31, ----------------------------- ----------------------------- (in millions) 2000 1999 1998 2000 1999 1998 Service cost for benefits earned $(119) $(121) $(108) $ (17) $ (19) $ (19) Interest cost (386) (347) (333) (72) (69) (64) Expected return on assets 679 634 567 91 83 73 Amortized prior service and transition cost (55) (25) (26) (28) (27) (28) Actuarial gain recognized 183 111 114 32 20 22 Settlement gain 6 -- -- 18 -- -- Benefit income (cost) $ 308 $ 252 $ 214 $ 24 $ (12) $ (16)
The Utility's share of the net benefit income for pensions in 2000, 1999, and 1998 was $302 million, $253 million, and $215 million, respectively. The Utility's share of the net benefit cost for other benefits in 2000, 1999, and 1998 was $7 million, $9 million, and $12 million, respectively. Net benefit income (cost) is calculated using expected return on plan assets of 8.5%. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future net benefit income (cost). In 1999 and 1998, actual return on plan assets exceeded expected return, while actual return on plan assets was below expected in 2000. In conformity with SFAS No. 71, regulatory adjustments have been recorded in the income statement and balance sheet of the Utility, which reflect the difference between Utility pension income determined for accounting purposes and Utility pension income determined for ratemaking, which is based on a funding approach. The CPUC has authorized the Utility to recover the costs associated with its other benefit plans for 1993 and beyond. Recovery is based on the lesser of the annual accounting costs or the annual contributions on a tax-deductible basis to the appropriate trusts. The amount of post-employment benefit costs included in the regulatory assets as of December 31, 2000 is $34 million, and is expected to be recovered through rates. The following actuarial assumptions were used in determining the plans' funded status and net benefit income (cost). Year-end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net benefit income (cost).
Pension Benefits Other Benefits December 31, December 31, ------------------------ ------------------------ 2000 1999 1998 2000 1999 1998 Discount rate 7.5% 7.5% 7.0% 7.5% 7.5% 7.0% Average rate of future compensation increases 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Expected long-term rate of return on plan assets 8.5% 8.5% 9.0% 8.5% 9.0% 9.0%
The assumed health care cost trend rate for 2001 is approximately 8.0%, grading down to an ultimate rate in 2005 and beyond of approximately 6.0%. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. A one-percentage point change would have the following effects:
(in millions) 1-Percentage 1-Percentage Point Increase Point Decrease Effect on total service and interest cost components $ 5 $ (4) Effect on postretirement benefit obligation $45 $(42)
PG&E Corporation and its subsidiaries also sponsor defined contribution pension plans. These plans are intended to qualify under Sections 401(a), 409(a), and 501(a) of the Internal Revenue Code. Employer contribution expense reflected in the accompanying PG&E Corporation Consolidated Statement of Income totaled $60 million, $53 million, and $49 million, for the years ended December 31, 2000, 1999, and 1998, respectively. Long-Term Incentive Program PG&E Corporation maintains a Long-Term Incentive Program (Program) that provides for grants of stock options to eligible participants with or without associated stock appreciation rights and dividend equivalents. As of December 31, 2000, 30,992,530 shares of PG&E Corporation common stock had been authorized for award under the Program, with 6,649,736 shares still available under the Program. Options granted in 2000, 1999, and 1998 had weighted average fair value at date of grant of approximately $3.26, $4.19, and $3.81 per share, respectively, using the Black-Scholes valuation method. In addition, PG&E Corporation granted stock options covering 26,852 shares on January 2, 2001 at an exercise price of $19.56, and 5,498,500 shares on January 5, 2001 at an exercise price of $12.63, the then-current market price. Significant assumptions used in the Black-Scholes valuation method for shares granted in 2000, 1999, and 1998 were: expected stock price volatility of 20.19%, 16.79%, and 17.60%, respectively; expected dividend yield of 5.18%, 3.77%, and 4.47%, respectively; risk-free interest rate of 6.10%, 4.69%, and 6.03%, respectively; and an expected 10-year life for all periods. Outstanding stock options become exercisable on a cumulative basis at one- third each year commencing two years from the date of grant and expire ten years and one day after the date of grant. Shares outstanding at December 31, 2000 had option prices ranging from $16.75 to $34.25 and a weighted-average remaining contractual life of 9.2 years. As permitted under SFAS No. 123, "Accounting for Stock-Based Compensation," PG&E Corporation applies Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" in accounting for the Program. As the exercise prices of all stock options is equal to the respective fair market value at the date of grant, PG&E Corporation does not recognize any compensation expense related to the Program using the intrinsic value-based method. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E Corporation's pro forma consolidated earnings (loss) per share would have been as follows:
2000 1999 1998 Net earnings (loss): As reported $(3,364) $ (73) $ 719 Pro-forma (3,374) (79) 717 Basic and diluted earnings (loss) per share: As reported (9.29) (0.20) 1.88 Pro-forma (9.32) (0.21) 1.88
The following table summarizes the Program's activity as of and for the years ended December 31: 2000 1999 1998 ---- ---- ----
Weighted Weighted Weighted Average Average Average Option Option Option (shares in million) Shares Price Shares Price Shares Price Outstanding--beginning of year 16.4 $29.42 11.1 $28.35 6.2 $26.21 Granted during year 10.2 $20.03 7.0 $30.94 6.4 $30.53 Exercised during year (1.2) $23.52 (0.5) $25.86 (0.7) $29.63 Cancellations during year (1.1) $26.57 (1.2) $29.82 (0.8) $28.16 Outstanding--end of year 24.3 $25.90 16.4 $29.43 11.1 $28.35 Exercisable--end of year 6.3 $27.73 3.0 $29.08 2.4 $29.06
The following summarizes information for options outstanding and exercisable at December 31, 2000. Of the outstanding options at December 31, 2000, 11,271,169 shares had exercise prices ranging from $16.75 to $24.38 with a weighted average remaining contractual life of 9.7 years, of which 2,143,943 shares were exercisable at a weighted average exercise price of $21.90, while 13,071,625 shares had option prices ranging from $24.50 to $34.25, with a weighted average remaining contractual life of 8.8 years, of which 4,155,548 shares were exercisable at a weighted average exercise price of $30.73. Performance Unit Plan PG&E Corporation grants performance units to certain officers of PG&E Corporation and its affiliates. The performance units vest one-third in each of the three years following the year of grant. Each time a cash dividend is declared on PG&E Corporation common stock, an amount equal to the cash dividend per share multiplied by the number of outstanding but unearned units held by the recipient of a performance unit will be accrued on behalf of the recipient. As soon as practicable following the end of each year, recipients will receive a cash payment of the dividends accrued for the year, modified by performance for that year as measured against the applicable performance target. The number of performance units granted and the amounts of compensation expense recognized in connection with the issuance of performance units during the years ended December 31, 2000, 1999, and 1998 was not material. Note 13: Income Taxes The significant components of income tax (benefit) expense for continuing operations were:
PG&E Corporation Utility Year Ended December 31, Year Ended December 31, -------------------------------- -------------------------- (in millions) 2000 1999 1998 2000 1999 1998 Current $(1,261) $1,002 $ 718 $(1,224) $1,133 $ 886 Deferred (728) (702) (51) (891) (433) (201) Tax credits, net (39) (52) (56) (39) (52) (56) Income tax (benefit) expense $(2,028) $ 248 $ 611 $(2,154) $ 648 $ 629
In 2000, the income tax expense of PG&E Corporation was allocated to continuing operations ($2,028 million benefit) and discontinued operations ($36 million tax benefit). The significant components of net deferred income tax liabilities were:
PG&E Corporation Utility Year ended Year ended ---------- ---------- December 31, December 31, ------------ ------------- 2000 1999 2000 1999 (in millions)
Deferred income tax assets: Customer advances for construction $ 176 $ 109 $ 176 $ 109 Unamortized investment tax credits 114 118 114 118 Provision for injuries and damages 203 185 203 185 Tax benefit of loss carryforward 70 -- 100 -- Deferred contract costs 124 182 -- -- Other 322 544 233 442 Total deferred income tax assets $1,009 $1,138 $ 826 $ 854 Deferred income tax liabilities: Regulatory balancing accounts 17 (47) 17 (47) Plant in service 2,185 2,827 1,719 2,428 Income tax regulatory asset 68 297 65 287 Other 564 1,075 126 577 Total deferred income tax liabilities 2,834 4,152 1,927 3,245 Total net deferred income taxes $1,825 $3,014 $1,101 $2,391 Classification of net deferred income taxes: Included in current liabilities (assets) $ 169 $ (133) $ 172 $ (119) Included in noncurrent liabilities 1,656 3,147 929 2,510 Total net deferred income taxes $1,825 $3,014 $1,101 $2,391
The differences between income taxes and amounts determined by applying the federal statutory rate to income before income tax expense for continuing operations were:
PG&E Corporation Utility Year ended December 31, Year ended December 31, ------------------------ ---------------------- 2000 1999 1998 2000 1999 1998 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) 4.4 10.1 3.2 4.3 6.2 6.6 Effect of regulatory treatment of depreciation differences (2.1) 51.7 9.7 (2.0) 9.4 9.8 Tax credits--net 0.7 (19.9) (4.0) 0.7 (3.6) (4.1) Effect of foreign earnings at different tax rates 0.1 (1.3) 0.6 -- -- -- Stock sale differences (1.4) (6.8) -- -- -- -- Stock sale valuation allowance 1.5 30.2 -- -- -- -- Other--net (0.3) (4.0) (0.3) 0.2 (1.9) (1.0) Effective tax rate 37.9% 95.0% 44.2% 38.2% 45.1% 46.3%
As a result of the Utility's purchased power costs which were not recovered in rates charged to the customers, PG&E Corporation and the Utility incurred a Net Operating Loss (NOL) for 2000. The NOL was carried back to prior years in accordance with federal income tax law resulting in a refund of approximately $1.2 billion. For California income tax purposes 55% of the California NOL may only be carried forward. The amount of this NOL carryforward is $1.2 billion for PG&E Corporation of which $1.7 billion is attributable to the Utility. The Company has recognized the benefits of its NOLs in the consolidated financial statements. During 1999, PG&E Corporation generated a capital loss carryforward from the sale of stock of approximately $225 million. The capital loss carryforward expires in 2005. A valuation allowance of approximately $75 million was recorded in 1999 reflecting the estimated net realizable value of this capital loss carryforward. PG&E Corporation, based upon its forecasted net capital gains, believed that it was more likely than not that it would not be able to fully utilize the full capital loss carryforward. Note 14: Commitments Surety Bonds Utility PG&E Corporation has arranged on behalf of the Utility $456 million in surety bonds to secure future workers' compensation liabilities. Effective in March, 2001, three of the five insurers of surety bonds have cancelled their coverage. The aggregate amount of this cancellation is approximately $285 million. This cancellation relieves the insurers only for claims arising from incidents occurring after the date of cancellation. They will still be responsible indefinitely for all future claims arising from incidents occurring prior to the date of cancellation. This cancellation has not impacted the Utility's self- insurance program under California law or its ability to meet its current plan obligations. Restructuring Trust Guarantees Utility A tax-exempt restructuring trust was established to oversee the development of the operating framework for the competitive generation market in California. The CPUC has authorized California utilities to guarantee bank loans of up to $85 million to be used by the trust for this purpose. Under the CPUC authorization, the Utility's remaining guarantee is for up to a maximum of $38 million of the loan. Although the remaining bank loan was repaid, the guarantee remains in place until the earlier of voluntary termination by the trust of the commitments, or the trust obtaining proceeds from permanent financing or recovery in rates, or the expiration date of bank loan commitments in December 2001. Tolling Agreements National Energy Group In 2000 and 1999, the NEG, through PG&E ET, entered into tolling agreements with several counterparties giving the NEG the right to sell electricity generated by facilities owned and operated by other parties which are under construction until June 2003. Under the tolling agreements, the NEG, at its discretion, supplies the fuel to the power plants, then sells the plant's output in the competitive market. Committed payments are reduced if the plant facilities do not achieve agreed-upon levels of performance criteria. At December 31, 2000, the annual estimated committed payments under such contracts ranged from approximately $21 million to $304 million, resulting in total committed payments over the next 28 years of approximately $6.2 billion commencing at the completion of construction. Estimated amounts payable in future years are as follows: (in millions) 2001 $ 21 2002 98 2003 220 2004 280 2005 285 Thereafter 5,300 Total $6,204 During 2000, the NEG paid total committed payments of approximately $12 million under tolling agreements. Power Purchase Contracts Utility The Utility is required to purchase electric energy and capacity provided by independent power producers that are QFs under the Public Utilities Regulatory Policies Act of 1978 (PURPA.) The CPUC required the Utility to enter into a series of QF long-term power purchase contracts and approved 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. Costs associated with these contracts are eligible for recovery by the Utility as transition costs through the collection of the non-bypassable CTC. The Utility's contracts with these power producers expire on various dates through 2028. Deliveries from these power producers account for approximately 23% of the Utility's 2000 electric energy requirements, and no single contract accounted for more than five percent of the Utility's energy needs. Prior to 2000, the Utility has negotiated with several QFs for early termination of their power purchase contracts. At December 31, 2000, the total discounted future payments due under the renegotiated contracts was approximately $145 million. Approximately half of the Utility's suppliers under long-term QF contracts have currently elected to receive PX-based prices for energy in addition to contractual capacity payments. However, pursuant to a CPUC order issued on February 22, 2001, PX-based-priced QFs reverted back to transition formula prices on January 19, 2001. Since the end of January 2001, the Utility has been partially paying amounts due QFs. On March 27, 2001, the CPUC issued a decision requiring the Utility and the other California investor-owned utilities to pay QFs fully for energy deliveries made on and after the date of the decision, within 15 days of the end of the QFs' billing period. The decision permits QFs to establish a 15-day billing period as compared to the current monthly billing period. The decision also adopts a revised pricing formula relating to the California border price of gas applicable to energy payments to all QFs, including those that do not use natural gas as a fuel. Based on the Utility's preliminary review of the decision, the revised pricing formula would reduce the Utility's 2001 average QF energy and capacity payments from approximately 12.7 cents per kWh to 12.3 cents per kWh. The amount of energy received and the total payments made under all of these power purchase contracts were: Year Ended December 31, ----------------------- (in millions) 2000 1999 1998 Kilowatt-hours received 25,446 25,910 25,994 Energy payments $ 1,549 $ 837 $ 943 Capacity payments $ 519 $ 539 $ 529 Irrigation district and water agency pay $ 56 $ 60 $ 53 National Energy Group The NEG, through its indirect subsidiary, USGenNE, assumed rights and duties under several power purchase contracts with third-party independent power producers as part of the acquisition of the NEES assets. At December 31, 2000, these agreements provided for an aggregate of 800 MW of capacity. Under the transfer agreement, the NEG is required to pay to NEES amounts due to the third- party power producers under the power purchase contracts. The approximate dollar amounts under these agreements are as follows: (in millions) 2001 $ 228 2002 215 2003 217 2004 220 2005 220 Thereafter 1,585 Total $2,685 Natural Gas Supply and Transportation Commitments Utility The Utility has long-term gas transportation service contracts 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 the Utility will pay each year may change due to changes in tariff rates. The total demand and volumetric transportation charges the Utility paid under these agreements were $94 million, $97 million, and $113 million in 2000, 1999, and 1998, respectively. These amounts include payments made by the Utility to PG&E GTN of $46 million, $47 million, and $49 million in 2000, 1999, and 1998, respectively, which are eliminated in the consolidated financial statements of PG&E Corporation. The Utility's obligations related to capacity held pursuant to long-term contracts on various pipelines are as follows: (in millions) 2001 $100 2002 101 2003 77 2004 77 2005 68 Thereafter 29 Total $452 As a result of regulatory changes, the Utility no longer procures gas for most of its industrial and larger commercial (non-core) customers, resulting in a decrease in the Utility's need for capacity on these pipelines. Despite these changes, the Utility continues to procure gas for substantially all of its residential and smaller commercial (core) customers and its non-core 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. The Utility's deteriorating credit situation has caused many of its gas suppliers to decline to sell the Utility any more gas, even under existing gas contracts, in the absence of accelerated payments. Specifically, some gas suppliers (1) have made demands that the Utility provide prepayment, cash on delivery, or other forms of payment assurance for gas supplies instead of the normal payment terms under which the Utility would pay for gas delivery, which the Utility is unable to meet given its current cash constraints, and (2) have refused to sell gas to the Utility for future periods. Failure to procure gas supplies to meet residential and smaller commercial gas (core) customer demands could result in diverting gas supplies from industrial and larger commercial gas (non-core) customers, which would only exacerbate the crisis. The U.S. Secretary of Energy issued a temporary order on January 19, 2001 requiring the gas suppliers to continue to make deliveries to avoid a worsening natural gas shortage emergency. However, this order expired on February 7, 2000, and certain companies, representing about 10% of the Utility's natural gas suppliers, terminated deliveries after the order expired. The Utility has tried to mitigate the worsening supply situation by withdrawing more gas from storage and, when able, purchasing additional gas on the spot market. Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge its gas account receivables and its gas inventories for up to 90 days (extended to 180 days in a CPUC draft decision issued on February 15, 2001) to secure gas for its core customers. At March 29, 2001, the amount of gas accounts receivable pledged was approximately $900 million. To date, approximately 30% of the Utility's suppliers of natural gas have signed security agreements with the Utility and discussions are continuing with the Utility's other suppliers. Additionally, the Utility is currently implementing a program to obtain longer term summer and winter supplies and daily spot supplies of natural gas. National Energy Group The NEG, through its subsidiaries PG&E Gen and PG&E ET, has entered into various gas supply and firm transportation agreements with various pipelines and transporters. Under these agreements, the NEG must make specific minimum payments each month. The approximate dollar obligations under these gas supply and transportation agreements are as follows: (in millions) 2001 $ 87 2002 87 2003 87 2004 85 2005 85 Thereafter 708 Total $1,139 Acquisition of Turbine Rights National Energy Group On September 8, 2000, the NEG, through one of its subsidiaries, entered into operative documents with a special purpose entity (the Lessor) in order to facilitate the development, construction, financing, and leasing of several power generation projects. The Lessor has an aggregate financing commitment from debt and equity participants (the Investors) of $7.8 billion. The NEG, in its role as construction agent for the Lessor, is responsible for completing construction by the sixth anniversary of the closing date, but has limited its risk related to construction completion to less than 90% of project costs incurred to date. Upon completion of an individual project, the NEG is required to make lease payments to the Lessor in an amount sufficient to provide a return to the Investors. At the end of an individual project's operating lease term (three years from construction completion), the NEG has the option to extend the lease at fair value, purchase the project at a fixed amount (equal to the original construction cost), or act as remarketing agent for the Lessor and sell the project to an independent third party. If the NEG elects the remarketing option, the NEG may be required to make a payment to the Lessors, up to 85% of the project cost, if the proceeds from remarketing are deficient to repay the Investors. PG&E Corporation committed to fund up to $314 million of equity to support the NEG's obligation to the Lessor during the construction and post-construction periods. The NEG is attempting to replace PG&E Corporation equity support commitments with substitute commitments of the NEG. Standard Offer Agreements National Energy Group USGenNE entered into three standard offer agreements with NEES' retail subsidiaries under which USGenNE will provide "standard offer" service to such subsidiaries. The standard offer agreements initially covered all of the retail customers served by NEES' distribution subsidiaries in Rhode Island, New Hampshire, and Massachusetts at the date of USGenNE's acquisition of the NEES assets. The Standard Offer Agreements continue through June 30, 2002 in New Hampshire; December 31, 2004 in Massachusetts; and December 31, 2009 in Rhode Island. The pricing per MWh is standard for all contracts and was below market prices at the date of the agreement. On January 7, 2000, USGenNE paid approximately $15 million by entering into an agreement with a third party which assumed the obligation to deliver power to NEES to serve 10% of the Massachusetts customers and 40% of the Rhode Island customers under the terms of the standard offer agreements. The payment was recorded as a deferred standard offer fee and is amortized over the remaining life of the standard offer agreements. Operating Leases National Energy Group The NEG and its subsidiaries have entered into several operating lease agreements for generating facilities and office space. Lease terms vary between three and 48 years. In November 1998, a subsidiary of the NEG entered into a $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped storage station under an operating lease. During 2000 and 1999, two indirect wholly owned subsidiaries of the NEG entered into two operating lease commitments relating to projects that are under construction, for which they act as the construction agent for the lessors. Upon completion of the construction projects, expected to be in 2001 and 2002, the lease terms of five years and three years, respectively, will commence. At the conclusion of each of the operating lease terms, the NEG has the option to extend the leases at fair market value, purchase the projects, or act as remarketing agent for the lessors for sales to third parties. If the Company elects to remarket the projects, then the NEG would be obligated to the lessors for up to 85% of the project costs if the proceeds are deficient to pay the lessor's investors. PG&E Corporation has committed to fund up to $604 million in the aggregate of equity to support the NEG's obligation to the lessors during the construction and post-construction periods. The NEG is attempting to replace PG&E Corporation's equity support commitments with substitute commitments of NEG. The approximate obligations under these operating lease agreements as of December 31, 2000 were as follows: (in millions) 2001 $ 97 2002 159 2003 166 2004 162 2005 88 Thereafter 965 Total $1,637 Operating lease expense amounted to $58 million, $67 million, and $35 million in 2000, 1999, and 1998, respectively. In addition to those obligations described above, the NEG entered into operative agreements with a special purpose entity that will own and finance construction of a facility totaling $775 million. PG&E Corporation has committed to fund up to $122 million of equity support commitments to meet the obligations to the entity. The NEG is attempting to replace the PG&E Corporation's equity support commitments with substitute commitments of NEG. Construction National Energy Group An indirect wholly owned subsidiary of PG&E Gen entered into a turnkey construction contract with a third-party contractor to construct a 360-MW natural gas-fired combined-cycle power plant in Charlton, Massachusetts. The total contract value is $72 million. The contractor's responsibilities include designing and engineering the project and providing procurement and construction services, start-up, training, and performance testing. The contractor had guaranteed that substantial completion will occur on or prior to August 20, 2000. Through the date of these financial statements, substantial completion has not occurred and the contractor is paying delay damages in accordance with the terms of the turnkey construction contract. At December 31, 2000 and 1999, approximately $69 million and $54 million, respectively, had been paid to the contractor under the turnkey construction contract. The same subsidiary also entered into a power island equipment and supply contract with Westinghouse Power Corporation (WPC) to provide the power island, the steam turbine, and the heat recovery steam generator. The total contract value is $69 million. At December 31, 2000 and 1999, approximately $67 million had been paid to WPC under the power island contract. In another construction transaction, an indirect wholly-owned subsidiary of PG&E Gen contracted with Siemens Westinghouse Power (SWP) in 2000 to provide the combustion turbine generator, steam turbine generator and heat recovery steam generator for its 1,080-MW natural gas-fired combined cycle power plant under development in Greene County, New York. The total contract value is approximately $223 million. At December 31, 2000, approximately $69 million had been paid to SWP. Construction is expected to commence June 2001. Long-Term Service Agreements National Energy Group The NEG has entered into long-term service agreements for the maintenance and repair of certain of its combustion turbine or combined-cycle generating plants under construction. These agreements, which are for periods up to 20 years, may be terminated in the event a planned construction project is cancelled. Annual amounts for long-term service agreements committed for the next five years under the current construction plan are as follows as of December 31, 2000: (in millions) 2001 $ 12 2002 35 2003 35 2004 34 2005 35 Thereafter 269 Total $420 Note 15: 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 insurance, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $12 million (property damage) and $4 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection, which provides an additional $9.3 billion in coverage, which is mandated by federal legislation. It provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, then the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation Utility The Utility may be required to pay for environmental remediation at sites where it has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by it for the storage or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances, even if it did not deposit those substances on the site. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. At December 31, 2000, the Utility expects to spend $320 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility could spend as much as $462 million on these costs. The Utility estimates the upper limit of the range 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 clean-up costs at additional sites or expected outcomes change. The Utility had an environmental remediation liability of $320 million and $271 million at December 31, 2000 and 1999, respectively. The $320 million accrued at December 31, 2000 includes (1) $140 million related to the pre- closing remediation liability, associated with the divested generation facilities discussed further in the "Generation Divestiture" section of Note 2 of the Notes to the Consolidated Financial Statements, and (2) $180 million related to remediation costs for those generation facilities that the Utility still owns, manufactured gas plant sites, and gas gathering compressor stations. Of the $320 million environmental remediation liability, the Utility has recovered $168 million through rates, and expects to recover another $87 million in future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate. In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings. In March 2000, the Central Coast Board requested the Utility to provide specific information regarding the "backflush" procedure used at Moss Landing. The Utility provided the requested information to the Board in April 2000. The Utility's investigation indicated that while it owned Moss Landing, significant amounts of water discharged from the cooling water intake. While the Utility's investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes that the temperature of the discharged water was higher than that of the ambient receiving water. In December 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which it would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. Settlement negotiations are continuing. The Utility's Diablo Canyon employs a "once through" cooling water system which is regulated under a NPDES Permit issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shell fish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order (CDO) alleging that, although the temperature limit has never been exceeded, the Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology reflects the "best technology available" under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $4.5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in California's Superior Court. PG&E Corporation believes the ultimate outcome of these matters will not have a material impact on its or the Utility's financial position or results of operations. National Energy Group In October and November 1999, the U.S. Environmental Protection Agency (EPA) and several states filed suits or announced their intention to file suits against a number of coal-fired power plants in Midwestern and Eastern states. These suits relate to alleged violations of the Clean Air Act. More specifically, they allege violations of the deterioration prevention and non- attainment provisions of the Clean Air Act's new source review requirements arising out of certain physical changes that may have been made at these facilities without first obtaining the required permits. In May 2000, the NEG received a request for information seeking detailed operating and maintenance histories for the Salem Harbor and Brayton Point power plants. If EPA were to find that there were physical changes in the past that were undertaken without first receiving the required permits under the Clean Air Act, then penalties may be imposed and further emission reductions might be necessary at these plants. In addition to the EPA, states may impose more stringent air emissions requirements. The Commonwealth of Massachusetts is considering the adoption of more stringent air emission reductions from electric generating facilities. If adopted, these requirements will impact Salem Harbor and Brayton Point. The NEG has proposed an emission reduction plan that may include modernization of the Salem Harbor power plant and use of advanced technologies for emissions removal. It is also studying various advanced technologies for emissions removal for the Brayton Point power plant. The NEG's subsidiary, USGenNE, has proposed a number of state and regional initiatives that will require it to achieve significant reductions of emissions by 2010. The NEG expects that USGenNE will meet these requirements through a combination of installation of controls, use of emission allowances it currently owns, and purchase of additional allowances. The NEG currently estimates that USGenNE's total capital cost for complying with these requirements will be approximately $270 million. PG&E Gen's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permit have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $55 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits. During September 2000, USGenNE signed a series of agreements that require, among other things, that USGenNE alter its existing waste water treatment facilities at two facilities by replacing certain unlined treatment basins, submit and implement a plan for the closure of such basins, and perform certain environmental testing at the facilities. USGenNE has incurred $4 million in 2000 and expects to complete the required steps on or before December 2001. The total expected cost of these improvements is $21 million. Legal Matters Utility The Utility's Chapter 11 bankruptcy filing on April 6, 2001, discussed in Notes 2 and 3, automatically stayed the litigation described below against the Utility. Chromium Litigation: Several civil suits are pending against the Utility in California state court. The suits seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinckley, Kettleman, and Topock, California. Currently, there are claims pending on behalf of approximately 1,050 individuals. The trial of 18 test cases is currently scheduled for July 2001. The Utility is responding to the suits and asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation has recorded a legal reserve in its financial statements in the amount of $160 million for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded as of December 31, 2000, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations. Wilson vs PG&E Corporation and Pacific Gas and Electric Company: On February 13, 2001, two complaints were filed against PG&E Corporation and the Utility in the Superior Court of the State of California, San Francisco County: Richard D. Wilson v. Pacific Gas and Electric Company et al. (Wilson I), and Richard D. Wilson v. Pacific Gas and Electric Company, et al. (Wilson II). In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation violated its fiduciary duties and California Business and Professions Code Section 17200 by causing the Utility to repurchase shares of Pacific Gas and Electric Company common stock from PG&E Corporation at an aggregate price of $2,326 million. The complaint alleges an unlawful business act or practice under Section 17200 because these repurchases allegedly violated PG&E Corporation's fiduciary duties, a first priority capital requirement allegedly imposed by the CPUC's decision approving the formation of a holding company, and also an implicit public trust imposed by Assembly Bill 1890, which granted authority for the issuance of rate reduction bonds. The complaint seeks to enjoin the repurchase by the Utility of any more of its common stock from PG&E Corporation or other entities or persons unless good cause is shown, and seeks restitution from PG&E Corporation of $2,326 million, with interest, on behalf of the Utility. The complaint also seeks an accounting, costs of suit, and attorney's fees. In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and other subsidiaries have been parties to a tax-sharing arrangement under which PG&E Corporation annually files consolidated federal and state income tax returns for, and pays, the income taxes of PG&E Corporation and participating subsidiaries. According to the plaintiff, between 1997 and 1999, PG&E Corporation collected $2,957 million from the Utility under this tax-sharing arrangement, but paid only $2,294 million (net of refunds) to all governments under the tax-sharing agreement. Plaintiff alleges that these monies were held under an express and implied trust to be used by PG&E Corporation to pay the Utility's share of income taxes under the tax-sharing arrangement. Plaintiff alleges that PG&E Corporation overcharged the Utility $663 million under the tax-sharing arrangement and has declined voluntarily to return these monies to the Utility, in violation of the alleged trust, the alleged first priority capital condition, and California Business and Professions Code Section 17200. The complaint seeks to enjoin PG&E Corporation from engaging in the activities alleged in the complaint (including the tax- sharing arrangement), and seeks restitution from PG&E Corporation of $663 million, with interest, on behalf of the Utility. The complaint also seeks an accounting, costs of suit, and attorney's fees. PG&E Corporation's and the Utility's analysis of these complaints is at a preliminary stage, but PG&E Corporation and the Utility believe them to be without merit and intend to present a vigorous defense. PG&E Corporation and the Utility are unable to predict whether the outcome of this litigation will have a material adverse affect on their financial condition or results of operation. National Energy Group The NEG is involved in various litigation matters in the ordinary course of its business. Except as described below, the NEG is not currently involved in any litigation that is expected, either individually or in the aggregate, to have a material adverse effect on financial condition or results of operations. Texas Franchise Fee Litigation Against PG&E GTT PG&E GTT and various of its affiliates are defendants in at least two class action suits and five separate suits filed by various Texas cities. Generally, these cities allege, among other things, that (1) owners or operators of pipelines occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities, and (2) the gas marketers failed to pay the cities for accessing and utilizing the pipelines located in the cities to flow gas under city streets. Plaintiffs also allege various other claims against the defendants for failure to secure the cities' consent. Damages are not quantified. PG&E Corporation believes that the ultimate outcome of these matters will not have a material adverse impact on its financial position or its results of operations. The NEG completed the sale of PG&E GTT in December 2000. Recorded Liability for Legal Matters: In accordance with SFAS No. 5 "Accounting for Contingencies," PG&E Corporation makes a provision for a liability when both it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. The following table reflects the current year's activity to the recorded liability for legal matters: PG&E (in millions) Corporation Utility Beginning balance, January 1, 2000 $106 $ 50 Provisions for liabilities 144 144 Payments (45) (43) Adjustments (20) 34 Ending balance, December 31, 2000 $185 $185 Note 16: Segment Information PG&E Corporation has identified four reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distributions, the regulatory environment, and how information is reported to PG&E Corporation's key decision makers. The Utility is one reportable operating segment and the other three are part of PG&E Corporation's NEG. These four reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. PG&E Corporation's reportable segments are described below. Utility PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to its customers. National Energy Group PG&E Corporation's subsidiary, the NEG, is an integrated energy company with a strategic focus on power generation, new power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. The NEG businesses include its power plant development and generation unit, PG&E Generating Company, LLC and its affiliates; its natural gas transmission unit, PG&E Gas Transmission Corporation; and its wholesale energy marketing and trading unit, PG&E Energy Trading Holdings Corporation which owns PG&E Energy Trading--Power, L.P., PG&E Energy Trading-Gas Corporation, and their affiliates. During 2000, the NEG sold its energy services unit, PG&E Energy Services Corporation. Also during the fourth quarter of 2000, the NEG sold its Texas natural gas and natural gas liquids business operated through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries. Segment information for the years 2000, 1999, and 1998 was as follows:
National Energy Group/(4)/ -------------------------------------------------- PG&E GT ---------------------- Eliminations & (in millions) Utility PG&E Gen/(4)/ Northwest Texas/(4)/ PG&E ET Other/(5)/ Total 2000 Operating revenues $ 9,623 $1,201 $ 188 $ 817 $14,414 $ (11) $26,232 Intersegment revenues/(1)/ 14 10 51 56 1,640 (1,771) -- Total operating revenues 9,637 1,211 239 873 16,054 (1,782) 26,232 Depreciation, amortization and decommissioning 3,511 91 41 70 11 (65) 3,659 Interest income 186 66 1 (4) 7 10 266 Interest expense/(3)/ (619) (61) (41) (49) (5) (13) (788) Income taxes (benefits)/(2)/ (2,154) 57 37 (35) 55 12 (2,028) Income (loss) from continuing operations (3,508) 84 58 20 27 (5) (3,324) Capital expenditures/(6)/ 1,245 495 15 -- 3 -- 1,758 Total assets at year-end/(5)/(6)/ $21,988 $4,568 $1,204 $ -- $ 7,098 $ 433 $35,291 1999 Operating revenues $ 9,084 $1,116 $ 172 $1,034 $ 9,404 $ 10 $20,820 Intersegment revenues/(1)/ 144 6 52 114 1,117 (1,433) -- Total operating revenues 9,228 1,122 224 1,148 10,521 (1,423) 20,820 Depreciation, amortization and decommissioning 1,564 89 41 75 9 2 1,780 Interest income 45 62 -- 9 4 (2) 118 Interest expense/(3)/ (593) (63) (41) (59) (12) (4) (772) Income taxes (benefits)/(2)/ 648 16 32 (407) (36) (5) 248 Income (loss) from continuing operations 763 97 68 (897) (34) 16 13 Capital expenditures/(6)/ 1,181 323 30 19 14 17 1,584 Total assets at year-end/(5)/(6)/ $21,470 $3,852 $1,160 $1,217 $ 1,876 $ (105) $29,470 1998 Operating revenues $ 8,919 $ 645 $ 185 $1,640 $ 8,183 $ 5 $19,577 Intersegment revenues/(1)/ 5 4 52 301 326 (688) -- Total operating revenues 8,924 649 237 1,941 8,509 (683) 19,577 Depreciation, amortization and decommissioning 1,438 52 39 65 5 3 1,602 Interest income 96 29 1 9 6 (40) 101 Interest expense/(3)/ (621) (43) (43) (77) (7) 10 (781) Income taxes (benefits)/(2)/ 629 28 31 (47) (17) (13) 611 Income (loss) from continuing operations 702 106 65 (71) (6) (25) 771 Capital expenditures/(6)/ 1,382 98 49 39 12 39 1,619 Total assets at year-end/(5)/(6)/ $22,950 $3,844 $1,169 $2,655 $ 2,555 $ 61 $33,234
(1) Inter-segment electric and gas revenues are recorded at market prices, which for the Utility and GTN are tariffed rates prescribed by the CPUC and the FERC, respectively. (2) Income tax expense for the Utility is computed on a stand-alone basis. The balance of the consolidated income tax provision is allocated among the National Energy Group. (3) Interest expense incurred by PG&E Corporation is allocated to the segments using specific identification. (4) Income from equity-method investees for 2000, 1999, and 1998 was $65 million, $63 million, and $113 million, respectively, for PG&E Gen, and $1 million, zero, and $3 million, respectively, for PG&E GTT. (5) Assets of PG&E Corporation are included in "Eliminations & Other" column exclusive of investment in its subsidiaries. (6) Capital expenditures and assets of the discontinued operations of Energy Services are included in "Eliminations & Other" column. Total assets for PG&E ES at December 31, 2000, 1999, and 1998 were $1 million, $197 million, and $202 million, respectively. Capital expenditures for 2000, 1999, and 1998 were zero, $17 million, and $38 million, respectively. QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
Quarter ended December 31 September 30 June 30 March 31 (in millions, except per share amounts) 2000 PG&E Corporation Operating revenues $ 8,082 $7,504 $5,638 $5,008 Operating income (loss)/(1)(4)/ (6,734) 629 622 676 Income (loss) from continuing operations (4,096) 244 248 280 Net income (loss)/(1)(4)/ (4,117) 225 248 280 Earnings (loss) per common share from continuing operations, basic (11.28) .67 .69 .78 Earnings (loss) per common share from continuing operations, diluted (11.28) .67 .68 .77 Dividends declared per common share .30 .30 .30 .30 Common stock price per share High 28.78 30.90 26.67 22.01 Low 18.25 22.50 20.39 18.80 Utility Operating revenues $ 2,600 $2,523 $2,296 $2,218 Operating income (loss) (6,856) 533 552 570 Net income (loss) (4,156) 217 222 234 Income (loss) available for (allocated to) common stock (4,163) 211 216 228 1999 PG&E Corporation Operating revenues $ 4,795 $6,217 $4,682 $5,126 Operating income (loss)/(1)(2)(3)/ (579) 516 480 461 Income (loss) from continuing operations (547) 197 196 167 Net income (loss)/(1)(2)(3)/ (611) 185 182 171 Earnings (loss) per common share from continuing operations, basic (1.49) 0.54 0.53 0.45 Earnings (loss) per common share from continuing operations, diluted (1.49) 0.54 0.50 0.39 Dividends declared per common share 0.30 0.30 0.30 0.30 Common stock price per share High 26.69 33.25 34.00 33.69 Low 20.25 25.00 30.56 29.50 Utility Operating revenues $ 2,323 $2,587 $2,233 $2,085 Operating income/(3)/ 633 486 452 422 Net income/(3)/ 272 185 178 153 Income available for common stock 265 179 172 147
(1) In the fourth quarter 1999, the NEG adopted a plan to dispose of the PG&E ES segment. This planned transaction has been accounted for as a discontinued operation. Results of operations of PG&E ES have been excluded from continuing operations for all periods presented. The operating loss and net loss of PG&E ES for the quarters ending March 31, June 30, and September 30, 1999, were $15 million and $8 million, $23 million and $14 million, and $20 million and $12 million, respectively. An estimated loss of $19 million ($0.05 per share), net of income taxes of $13 million, was recorded for the quarter and nine months ended September 30, 2000. Additionally, an estimated loss of $21 million ($0.06 per share), net of income taxes of $23 million, was recorded for the quarter and three-month period ended December 31, 2000. (2) Amounts have been restated to reflect the change in accounting for major maintenance and overhauls at the NEG (see Note 1), and reclassification of PG&E ES operating results to discontinued operations (see above). The accounting change resulted in a cumulative effect being recorded as of January 1, 1999 of $12 million ($0.03 per share), net of income taxes of $8 million. Operating income previously reported for 1999 was $442 million, $454 million, and $492 million for each of the first three quarters, respectively. Net income previously reported for 1999 was $156 million ($0.42 per share), $180 million ($0.49 per share), and $183 million ($0.50 per share) for the same periods. (3) In the fourth quarter of 1999, the Utility recorded the effects of the outcome of the GRC. This resulted in an increase of $256 million in operating income and an increase of $153 million in net income. Additionally, the NEG recorded an after-tax charge of $890 million reflecting PG&E GTT's assets at their fair market value. (See MD&A and Note 5.) (4) In the fourth quarter of 2000, the Utility recorded a charge to earnings for the write-off of regulatory assets representing transition costs and undercollected purchased power costs. The write-off was $6.9 billion ($4.1 after-tax) and reflected the fact that based upon the current status of the California energy crisis, the Utility could no longer conclude that the regulatory assets were probable of recovery through regulated rates. Also in the fourth quarter of 2000, the Utility recognized a $140 million ($83 million, after tax) provision for an increase in legal reserves. INDEPENDENT AUDITORS' REPORT To the Boards of Directors and Shareholders of PG&E Corporation and Pacific Gas and Electric Company We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries and Pacific Gas and Electric Company and subsidiaries as of December 31, 2000 and 1999, and the related statements of consolidated operations, cash flows and common stock equity of PG&E Corporation and the related statements of consolidated operations, cash flows and stockholders' equity of Pacific Gas and Electric Company for the years then ended. 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. The consolidated financial statements for the year ended December 31, 1998 were audited by other auditors whose report, dated February 8, 1999, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits 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, such 2000 and 1999 financial statements present fairly, in all material respects, the financial position of PG&E Corporation and Pacific Gas and Electric Company as of December 31, 2000 and 1999, and the results of their consolidated operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 of the Notes to Consolidated Financial Statements, in 1999 PG&E Corporation changed its method of accounting for major maintenance and overhauls. The accompanying consolidated financial statements have been prepared on a going concern basis of accounting. As discussed in Notes 2 and 3 of the Notes to the Consolidated Financial Statements, Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, has incurred power purchase costs substantially in excess of amounts charged to customers in rates. On April 6, 2001, Pacific Gas and Electric Company sought protection from its creditors by filing a voluntary petition under provisions of Chapter 11 of the U.S. Bankruptcy Code. These matters raise substantial doubt about Pacific Gas and Electric Company's ability to continue as a going concern. Managements' plans in regard to these matters are also described in Notes 2 and 3 of the Notes to the Consolidated Financial Statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. DELOITTE & TOUCHE LLP San Francisco, California April 6, 2001 RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS In 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 accounting principles generally accepted in the United States of America. Management considers materiality and uses its best judgment to ensure that such statements reflect fairly the financial position, results of operations, and cash flows of PG&E Corporation and the Utility. PG&E Corporation and the Utility maintain systems of internal controls supported by formal policies and procedures which are communicated throughout PG&E Corporation and the Utility. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and that necessary records are produced for the preparation of consolidated financial statements. There are limits inherent in all systems of internal controls, based on recognition that the costs of such systems should not exceed the benefits to be derived. PG&E Corporation and the Utility believe that their systems of internal control provide this appropriate balance. PG&E Corporation management also maintains a staff of internal auditors who evaluate the adequacy of, and assess the adherence to, these controls, policies, and procedures for all of PG&E Corporation, including the Utility. Both PG&E Corporation's and the Utility's 2000 and 1999 consolidated financial statements have been audited by Deloitte & Touche LLP, PG&E Corporation's independent auditors. The audit includes consideration of internal accounting controls and performance of 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 Deloitte & Touche, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The internal auditors and Deloitte & Touche LLP have free access to the Audit Committee, which consists of five outside directors. The Audit Committee has reviewed the financial data contained in this report. PG&E Corporation and the Utility are committed to full compliance with all laws and regulations and to conducting business in accordance with high standards of ethical conduct. Management has taken the steps necessary to ensure that all employees and other agents understand and support this commitment. Guidance for corporate compliance and ethics is provided by an officers' Ethics Committee and by a Legal Compliance and Business Ethics organization. PG&E Corporation and the Utility believe that these efforts provide reasonable assurance that each of their operations is conducted in conformity with applicable laws and with their commitment to ethical conduct. EX-21 33 dex21.txt SUBSIDIARES OF THE REGISTRANT EXHIBIT 21 Subsidiaries of PG&E Corporation and Pacific Gas and Electric Company --------------------------------------------------------------------- 1. Name, State of organization, location and nature of business of registrants and every subsidiary thereof, 1.1. PG&E Corporation ("Claimant") California corporation PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Corporation, incorporated under the laws of the State of California, is a holding company formed by Pacific Gas and Electric Company, a public utility. On January 1, 1997 PG&E Corporation became the parent of Pacific Gas and Electric Company pursuant to a corporate reorganization plan. PG&E Corporation is also the parent of nonutility subsidiaries formerly owned by Pacific Gas and Electric Company. 1.2. Subsidiaries 1.2.1. Elm Power Corporation Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Elm Power Corporation, incorporated under the laws of the State of Delaware, is a wholly subsidiary of PG&E Corporation. 1.2.2. Pacific Gas and Electric Company California corporation 77 Beale Street P.O. Box 770000 San Francisco, CA 94177 Pacific Gas and Electric Company is a wholly owned subsidiary of PG&E Corporation. Pacific Gas and Electric Company is an operating public utility engaged principally in the business of supplying electric and natural gas service throughout most of Northern and Central California. 1.2.2.1. Alberta and Southern Gas Co., Ltd. Alberta corporation 1500 Bankers Hall 855 Second Street, SW Calgary, Alberta T2P 4J7 Alberta and Southern Gas Co. Ltd. is a wholly owned Canadian subsidiary of Pacific Gas and Electric Company. Alberta and Southern Gas Co. Ltd. formerly purchased natural gas in Canada for the California market. 1.2.2.1.1. Alberta and Southern Gas Marketing, Inc. Alberta corporation 1500 Bankers Hall 855 Second Street, SW Calgary, Alberta T2P 4J7 Alberta and Southern Gas Marketing, Inc. is a wholly owned subsidiary of Alberta and Southern Gas Co. Ltd. Alberta and Southern Gas Marketing, Inc., formerly marketed natural gas in non-California markets. 1 1.2.2.2. Natural Gas Corporation of California California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Natural Gas Corporation of California is a wholly owned subsidiary of Pacific Gas and Electric Company. Natural Gas Corporation of California acts as the vehicle for the amortization of certain regulatory assets. 1.2.2.2.1. NGC Production Company California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 NGC Production Company is a wholly owned subsidiary of Natural Gas Corporation of California. NGC Production Company facilitates project financing for Natural Gas Corporation of California's capital requirements. 1.2.2.2.2. Alaska Gas Exploration Associates California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Alaska Gas Exploration Associates is 50% owned by Natural Gas Corporation of California. 1.2.2.3. Pacific Conservation Services Company California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Pacific Conservation Services Company is a wholly owned subsidiary of Pacific Gas and Electric Company. Pacific Conservation Services Company engages in borrowing and lending operations required to fund Pacific Gas and Electric Company conservation loan programs. 1.2.2.4. Calaska Energy Company California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Calaska Energy Company is a wholly owned subsidiary of Pacific Gas and Electric Company. Calaska Energy Company was Pacific Gas and Electric Company's representative in the Alaska Highway Pipeline Project, which was formed to bring Prudhoe Bay natural gas to the lower 48 states. 1.2.2.5. Eureka Energy Company California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Eureka Energy Company is a wholly owned subsidiary of Pacific Gas and Electric Company. Eureka Energy Company owns land in San Luis Obispo County. 2 1.2.2.6. Standard Pacific Gas Line, Incorporated California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Standard Pacific Gas Line, Incorporated is a subsidiary of Pacific Gas and Electric Company. Standard Pacific Gas Line, Inc. transports natural gas in California. Pacific Gas and Electric Company owns a 85.71% interest, and Chevron Pipe Line Company owns the remaining 14.29% interest. 1.2.2.7. Pacific California Gas System, Inc. California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Pacific California Gas System, Inc. is a wholly owned subsidiary of Pacific Gas and Electric Company. Pacific California Gas System, Inc. was created to hold intrastate gas pipeline operations. 1.2.2.8. Pacific Energy Fuels Company California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Pacific Energy Fuels Company is a wholly owned subsidiary of Pacific Gas and Electric Company. Pacific Energy Fuels Company owns and finances nuclear fuel inventory. 1.2.2.9. Pacific Gas Properties Company California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Pacific Gas Properties Company is a wholly owned subsidiary of Pacific Gas and Electric Company. Pacific Gas Properties Company owns California property. 1.2.2.9.1. Pacific Properties California corporation P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 Pacific Properties is 50% owned by Pacific Gas Properties Company. Pacific Properties owns California property. 1.2.2.10. Chico Commons, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Chico Commons, L.P. is 41% owned by Pacific Gas and Electric Company as a limited partner. Chico Commons, L.P. was created to construct and own low income housing. 1.2.2.11. PG&E Capital I P.O. Box 770000 77 Beale Street, 32nd Floor San Francisco, CA 94177 3 PG&E Capital I, a business trust, is 3% owned by Pacific Gas and Electric Company. PG&E Capital I was formed as a special purpose financing vehicle for the purpose of issuing deferrable income securities. 1.2.2.12. PG&E Funding, LLC Delaware corporation 245 Market Street, Suite 424 San Francisco, CA 94105 PG&E Funding, LLC is a wholly owned subsidiary of Pacific Gas and Electric Company. PG&E Funding, LLC is a special purpose financing vehicle formed for the ownership of transition property and issuance of securities. 1.2.2.13. 201 Turk Street, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 201 Turk Street, L.P. is 32.4% owned by Pacific Gas and Electric Company as a limited partner. 201 Turk Street, L.P. was created to construct and own a low income housing project. 1.2.2.14. 1989 Oakland Housing Partnership Associates, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 1989 Oakland Housing Partnership Associates, L.P. is owned 40% by Pacific Gas and Electric Company as a limited partner. 1989 Oakland Housing Partnership Associates, L.P. was created to construct and own low income housing. 1.2.2.15. 1992 Oakland Regional Housing Partnership Associates, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 1992 Oakland Regional Housing Partnership Associates, L.P. is owned 17% by Pacific Gas and Electric Company as a limited partner. 1992 Oakland Housing Partnership Associates, L.P. was created to construct and own low income housing. 1.2.2.16. 1994 Oakland Regional Housing Partnership Associates, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 1994 Oakland Regional Housing Partnership Associates, L.P. is owned 12% by Pacific Gas and Electric Company as a limited partner. 1994 Oakland Regional Housing Partnership Associates, L.P. was created to construct and own low income housing. 1.2.2.17. Pacific Gas and Electric Housing Fund Partnership, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Pacific Gas and Electric Housing Fund Partnership, L.P. is owned 99.9% by Pacific Gas and Electric Company as a limited partner. Pacific Gas and Electric Housing Fund Partnership, L.P., invests in projects that construct and own low income housing. 1.2.2.18. Merritt Community Capital Fund V, L.P. California partnership 4 One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Merritt Community Capital Fund V, L.P. is owned 2.2% by Pacific Gas and Electric Company as a limited partner. Merritt Community Capital Fund V, L.P., was created to construct and own low income housing. 1.2.2.19. Schoolhouse Lane Apartments, L.P. California partnership One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Schoolhouse Lane Apartments, L.P. is owned 99% by Pacific Gas and Electric Company as a limited partner. Schoolhouse Lane Apartments, L.P., was created to construct and own low income housing. 1.2.2.20. PG&E Holdings, LLC Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Holdings, LLC is a wholly owned subsidiary of Pacific Gas and Electric Company. PG&E Holdings, LLC was formed as a holding company for repurchased shares. 1.2.2.21. PG&E CalHydro, LLC California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E CalHydro, LLC is a wholly owned subsidiary of Pacific Gas and Electric Company. PG&E CalHydro, LLC was formed for the purpose of owning and operating a system of hydroelectric facilities and related watershed. 1.2.3. PG&E National Energy Group, Inc. Delaware corporation 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 PG&E National Energy Group, Inc. is a wholly owned subsidiary of PG&E Corporation. PG&E National Energy Group, Inc. was formed for the purpose of holding ownership of PG&E Corporation's unregulated subsidiaries, both direct and indirect. 1.2.3.1. PG&E Enterprises California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Enterprises is a wholly owned subsidiary of PG&E National Energy Group, Inc. PG&E Enterprises was formed as a holding company for oil and gas, real estate, electric generation, and technology investments. 1.2.3.1.1. PG&E Shareholdings, Inc. California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Shareholdings, Inc is a wholly owned non-regulated subsidiary of PG&E Enterprises. Through its subsidiaries, PG&E Shareholdings, Inc. develops real estate in Pacific Gas and Electric Company's service territory. In addition, some subsidiaries of PG&E Shareholdings, Inc. have made fuel-related investments and a limited number of non-energy 5 related investments. 1.2.3.1.1.1. Gilia Enterprises California corporation 4615 Cowell Blvd. Davis, CA 95616 100% owned by PG&E Shareholdings, Inc. A wholly owned, non- regulated indirect subsidiary of PG&E Enterprises through its ownership of PG&E Sharingholdings, Inc. Formed to hold interest in real estate investment 1.2.3.1.1.1.1. Marengo Ranch Joint Venture California partnership 4615 Cowell Blvd. Davis, CA 95616 63% owned by PG&E Shareholdings, Inc. as limited partner 1.3% owned by Gilia Enterprises as general partner Land development in Sacramento County 1.2.3.1.1.1.2. Oat Creek Associates Joint Venture California partnership 4615 Cowell Blvd. Davis, CA 95616 50% owned by PG&E Shareholdings, Inc. as limited partner 50% owned by Gilia Enterprises as general partner Land development in Yolo County 1.2.3.1.1.2. Rancho Murieta Joint Venture California partnership 4615 Cowell Blvd. Davis, CA 95616 45% owned by PG&E Shareholdings, Inc. as limited partner. Real estate development. 1.2.3.1.1.3. 1701 Oak Partnership California partnership 4615 Cowell Blvd. Davis, CA 95616 50% owned by PG&E Shareholdings, Inc. as limited partner. Real estate development. 1.2.3.1.1.4. 1801 Oak Partnership California partnership 4615 Cowell Blvd. Davis, CA 95616 50% owned by PG&E Shareholdings, Inc. as limited partner. Real estate development. 1.2.3.1.1.5. BPS I, Inc. California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% owned by PG&E Shareholdings, Inc. A wholly-owned, non- regulated real estate development subsidiary of PG&E Enterprises through its ownership of PG&E Shareholdings, Inc. 1.2.3.1.1.5.1. Alhambra Pacific (Joint Venture) California partnership 4615 Cowell Blvd. 6 Davis, CA 95616 80% owned by PG&E Shareholdings, Inc. as general partner; 20% owned by BPS I, Inc. as limited partner Ownership of property in Yolo County. 1.2.3.1.1.6. The Conaway Ranch Company California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% owned by PG&E Shareholdings, Inc. A wholly-owned, non- regulated indirect subsidiary of PG&E Enterprises through its ownership of PG&E Shareholdings, Inc., in partnership with the Conaway Conservancy Group, an existing California general partnership owning the Conaway Ranch. 1.2.3.1.1.6.1. Conaway Conservancy Group Joint Venture California partnership 4615 Cowell Blvd. Davis, CA 95616 70% by PG&E Shareholdings, Inc.; and 30% by Conaway Ranch Company Ownership of property in Yolo County. 1.2.3.1.1.7. DPR, Inc. California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% owned by PG&E Shareholdings, Inc. A wholly-owned, non- regulated indirect subsidiary of PG&E Enterprises through its ownership of PG&E Shareholdings, Inc.; general partner in a real estate partnership. 1.2.3.1.1.8. McSweeney Ranch Joint Venture California partnership 4615 Cowell Blvd. Davis, CA 95616 50% owned by PG&E Shareholdings, Inc. 1.2.3.1.1.9. PG&E Energy Trading Holdings, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Shareholdings, Inc. Formed for the limited purpose of holding stock in PG&E Energy Trading - Power Holdings Corporation. 1.2.3.1.1.9.1. PG&E Energy Trading - Power Holdings Corporation California corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Energy Trading Holdings, LLC. Holding company for energy trading and overseas entities. 1.2.3.1.1.9.1.1. PG&E ET Investments Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Energy Trading - Power Holdings Corporation. Owns the 98% limited partner interest in 7 PG&E Energy Trading - Power, L.P., and the 98% membership interest in PG&E ET Synfuel 166, LLC. 1.2.3.1.1.9.1.1.1. PG&E Energy Trading-Power, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 98% owned by PG&E ET Investments Corporation; 2% owned by PG&E Energy Trading - Power Holdings Corporation Engages in electric power marketing and trading. 1.2.3.1.1.9.1.1.2. PG&E ET Synfuel 166, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 98% owned by PG&E ET Investments Corporation; and 2% owned by PG&E Energy Trading - Power Holdings Corporation. Formed to acquire a synthetic fuel production facility located in South Carolina. 1.2.3.1.1.9.1.2. PG&E International Inc. California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E International Inc. is a wholly owned subsidiary of PG&E Energy Trading Power Holdings Corporation, and is a holding company for overseas project companies. 1.2.3.1.1.9.1.2.1. PG&E International Development Holdings, LLC Delaware limited liability company One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 A wholly-owned subsidiary of PG&E International, Inc., formed to own and sell an Australian pipeline development company. 1.2.3.1.1.9.1.2.2. Gannet Power Corporation California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% owned by PG&E International Inc. 1.2.3.1.1.9.1.2.3. PG&E Overseas Holdings I, Ltd. Cayman Islands Company P.O. Box 309, George Town Grand Cayman, Cayman Islands, BWI A wholly-owned subsidiary of PG&E International, Inc., and is a holding Company for PG&E Overseas Holdings II, Ltd. 1.2.3.1.1.9.1.2.3.1. PG&E Overseas Holdings II, Ltd. Labuan Company Unit Level 9(A2), Main Office Tower Financial Park Labuan, Jalan Merdeka 87000 W.P. Labuan Malaysia 100% owned by PG&E Overseas Holdings I, LTD., and is an investment company 1.2.3.1.1.9.1.2.3.1.1. PG&E Corporation Australian Holdings Pty, Ltd. Australian corporation 8 Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 100% owned by PG&E Overseas Holding II, Ltd. Holding company for Australian companies 1.2.3.1.1.9.1.2.3.1.1.1. PG&E Gas Transmission Australia Pty Ltd. Australian corporation Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 100% owned by PG&E Corporation Australian Holdings Pty, Ltd. Investment company. 1.2.3.1.1.9.1.2.3.1.1.2. PG&E Gas Transmission Queensland Pty Ltd Australian corporation Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 100% owned by PG&E Corporation Australian Holdings Pty, Ltd. Pipeline operator. 1.2.3.1.1.9.1.2.3.1.1.3. PG&E Gas Transmission Unit Holdings Pty Ltd Australian corporation Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 100% owned by PG&E Corporation Australian Holdings Pty, Ltd. Investment company. 1.2.3.1.1.9.1.2.3.1.1.4. PG&E Energy Trading Australia Pty Ltd Australian corporation Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 100% owned by PG&E Corporation Australian Holdings Pty, Ltd. Energy marketing company. 1.2.3.1.1.9.1.2.3.1.1.5. PG&E Corporation Australia Pty Ltd. Australian corporation Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 100% owned by PG&E Corporation Australian Holdings Pty, Ltd. Provides corporate services. 1.2.3.1.1.9.1.2.4. PG&E Gas Transmission Bundaberg Pty Ltd. Australian corporation Level 33, Waterfront Place One Eagle Street Brisbane, Queensland 4000 Australia 9 100% owned by PG&E International, Inc. Project development company. 1.2.3.1.1.9.1.2.5. Rocksavage Services I, Inc. Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% owned by PG&E International Inc. 1.2.3.1.1.9.1.3. PG&E Energy Trading - Gas Corporation California corporation 7500 Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 100% owned by PG&E Energy Trading - Power Holdings Corporation. Engages in natural gas marketing and trading activities in the United States. 1.2.3.1.1.9.1.3.1. PG&E Energy Trading, Canada Corporation Alberta corporation 335 Eighth Avenue, S.W. Suite 1740 Calgary, Alberta T2P 1CP Canada 100% owned by PG&E Energy Trading - Gas Corporation. Engages in natural gas marketing and trading activities in Canada. 1.2.3.1.1.9.1.3.1.1. CEG Energy Options Inc. Saskatchewan corporation 2366 Avenue C North, Suite 101 Saskatoon, Saskatchewan S7L 5X5 Canada 100% owned by PG&E Energy Trading, Canada Corporation. Engages in natural gas marketing in Saskatchewan. 1.2.3.1.1.9.1.3.2. True Quote LLC Kentucky limited liability company 9931 Corporate Campus Drive, Suite 2400 Louisville, KY 40223 46.24% owned by PG&E Energy Trading - Gas. Engages in the business of designing, developing, implementing, operating and commercializing a business-to-business e- commerce venture for the transmission of energy and energy-related products 1.2.3.1.1.10. PG&E Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 100% owned by PG&E Shareholdings, Inc. Holding company for PG&E Generating Company activities. 1.2.3.1.1.10.1. PG&E Generating Energy Group, LLC Delaware limited liability company 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Company, LLC Holding company for PG&E National Energy Group merchant projects and USGen New England, Inc. 1.2.3.1.1.10.1.1. PG&E Generating Energy Holdings, Inc. Delaware corporation 10 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC. Formed to be the holding company for the 1% membership interests of the limited liability companies under PG&E Generating Energy Group, LLC 1.2.3.1.1.10.1.1.1. Badger Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Badger Generating Company, LLC. 1.2.3.1.1.10.1.1.1.1. Badger Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Badger Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Formed to develop, own, manage and operate a merchant electric generating facility to be located in Wisconsin. 1.2.3.1.1.10.1.2. Black Hawk Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Energy Group, LLC General and limited partner in Athens Generating Company, L.P. 1.2.3.1.1.10.1.3. Black Hawk III Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Energy Group, LLC General and limited partner in Lake Road Generating Company, L.P.; holds membership interest in Lake Road Power I, LLC. 1.2.3.1.1.10.1.3.1. Lake Road Power I, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Black Hawk III Power Corporation. Formed to own a future partnership Interest in Lake Road Generating Company, L.P. 1.2.3.1.1.10.1.4. Harlan Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Energy Group, LLC General and limited partner in Umatilla Generating Company, L.P. 1.2.3.1.1.10.1.4.1. Umatilla Generating Company, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor 11 Bethesda, MD 20814-6161 51% owned by Harlan Power Corporation, and 49% owned by Juniper Power Corporation Electric generating facility to be located near Umatilla, Oregon. 1.2.3.1.1.10.1.5. Peach I Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Holds general partnership interest in Athens Generating Company, L.P. 1.2.3.1.1.10.1.6. Peach IV Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Holds general partnership interest in Lake Road Generating Company, L.P. 1.2.3.1.1.10.1.6.1. Lake Road Power II, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Peach IV Power Corporation Formed to hold a future partnership interest in Lake Road Generating Company, L.P. 1.2.3.1.1.10.1.7. Juniper Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC General partner in Umatilla Generating Company, L.P. 1.2.3.1.1.10.1.8. Plover Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Energy Group, LLC General and limited partner in Mantua Creek Generating Company, L.P. and Mantua Creek Urban Renewal, L.P. 1.2.3.1.1.10.1.9. Beech Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC General partner in Mantua Creek Generating Company, L.P. and Mantua Creek Urban Renewal, L.P. 1.2.3.1.1.10.1.9.1. Mantua Creek Urban Renewal, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 51% owned by Plover Power Corporation, and 49% owned by Beech Power Corporation Special purpose tax partnership formed for Mantua Creek Project; formed to operate under the Long Term 12 Tax exemption Law, and to initiate and conduct projects for redevelopment of a redevelopment area pursuant to a redevelopment plan, and, when authorized by financial agreement with the municipality, to acquire, plan, develop, construct, alter, maintain, or operate industrial, commercial or administrative projects. 1.2.3.1.1.10.1.10. Black Hawk II Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Energy Group, LLC Inactive; formerly a general partner in the "old" Millennium Power Partners, L.P. 1.2.3.1.1.10.1.11. Peach III Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formerly held interest in Millennium Power Partners, L.P. Inactive and in process of dissolution. 1.2.3.1.1.10.1.12. First Arizona Land Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to enter into real estate options in the State of Arizona for the Harquahala Project. 1.2.3.1.1.10.1.13. First California Land Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC. Formed to enter into real estate options and/or leases in the State of California 1.2.3.1.1.10.1.14. PG&E Generating New England, Inc. Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own membership interst in PG&E Generating New England, LLC. 1.2.3.1.1.10.1.14.1. PG&E Generating New England, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating New England, Inc. Formed to be the successor company to USGen New England, Inc. in the Patriot Project. 1.2.3.1.1.10.1.15. Attala Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group LLC. Investment company for the Duke/Attala acquisition; 13 owner of Attala Generating Company, LLC. 1.2.3.1.1.10.1.15.1. Attala Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Attala Power Corporation. Merchant electric generating facility being constructed in Kosciusko, Mississippi. 1.2.3.1.1.10.1.16. Osprey Power Corporation California corporation 100 Pine Street, 20th Floor San Francisco, CA 94111 100% owned by PG&E Generating Energy Group, LLC General and limited partner in Millennium Power Partners, L.P. (f/k/a East Syracuse Generating Company, L.P.); owns Magnolia Power Corporation. 1.2.3.1.1.10.1.16.1. Magnolia Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Osprey Power Corporation General partner in Millenium Power Parners, L.P. 1.2.3.1.1.10.1.17. San Gorgonio Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC. Investment company for the acquisition of the Sea West Wind Project. 1.2.3.1.1.10.1.18. Kennerdell Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership in Kennerdell Generating Company, LLC 1.2.3.1.1.10.1.18.1. Kennerdell Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Kennerdell Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Formed to develop, own, manage, and operate a merchant electric generating facility to be located in Western Pennsylvania. 1.2.3.1.1.10.1.19. La Paloma Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in La Paloma Generating Company, LLC. 1.2.3.1.1.10.1.20. Liberty Generating Corporation Delaware corporation 14 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Liberty Generating Company, LLC. 1.2.3.1.1.10.1.20.1 Liberty Urban Renewal LLC Delaware limited liability corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Liberty Generating Corporation, 1% owned by PG&E Generating Energy Holdings, Inc. Formed to own and lease a merchant electric generating facility to be located in Linden, New Jersey 1.2.3.1.1.10.1.21. Otay Mesa Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Otay Mesa Generating Company, LLC. 1.2.3.1.1.10.1.21.1. Otay Mesa Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Otay Mesa Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Formed to develop, manage, and operate a merchant electric generating facility to be located in San Diego County, California. 1.2.3.1.1.10.1.22. Bluebonnet Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Bluebonnet Generating Company, LLC. 1.2.3.1.1.10.1.22.1. Bluebonnet Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Bluebonnet Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Formed to develop, own manage, and operate a merchant electric generating facility to be located in Texas. 1.2.3.1.1.10.1.23. Harquahala Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Owns a membership interest in Harquahala Generating Company, LLC. 1.2.3.1.1.10.1.23.1. Harquahala Generating Company, LLC Delaware limited liability company 15 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Harquahala Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Formed to develop, own, manage, and operate a merchant electric generating facility to be located in Arizona. 1.2.3.1.1.10.1.24. Madison Wind Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Madison Wind Power, LLC. 1.2.3.1.1.10.1.25. Okeechobee Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Okeechobee Generating Company, LLC. 1.2.3.1.1.10.1.26. PG&E Dispersed Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own membership interest in PG&E Dispersed Generating Company, LLC. 1.2.3.1.1.10.1.27. Covert Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC Formed to own a membership interest in Covert Generating Company, LLC. 1.2.3.1.1.10.1.28. Goose Lake Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Energy Group, LLC. Formed to own a membership interest in Goose Lake Generating Company, LLC 1.2.3.1.1.10.1.28.1. Goose Lake Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Goose Lake Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Merchant electric generating facility to be constructed in Goose Lake, Illinois 1.2.3.1.1.10.1.29. Meadow Valley Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 16 100% owned by PG&E Generating Energy Group, LLC, Formed to own a membership interest in Meadow Valley Generating Company, LLC 1.2.3.1.1.10.1.29.1. Meadow Valley Generating Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 99% owned by Meadow Valley Power Corporation, and 1% owned by PG&E Generating Energy Holdings, Inc. Formed to develop, own, manage, and operate a merchant electric generating facility to be located near Las Vegas, Nevada. 1.2.3.1.1.10.2. PG&E Generating Power Group, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Company, LLC Holding company for PG&E Generating Company operating projects 1.2.3.1.1.10.2.1. Aplomado Power Corporation California corporation 100 Pine Street, 20th Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC Investment company for the Panther Creek Project. 1.2.3.1.1.10.2.2. Beale Generating Company Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 89% owned by PG&E Generating Power Group, LLC Holding company 1.2.3.1.1.10.2.2.1. Indian Orchard Generating Company, Inc. Delaware corporation 7500 Old Georgetown Road Bethesda, MD 20814-6161 100% owned by Beale Generating Company 49% membership interest in MASSPOWER, L.L.C. 1.2.3.1.1.10.2.2.1.1. MASSPOWER, L.L.C. (formerly MASSPOWER, Inc.) Delaware limited liability company One Bowdoin Square Boston, MA 02114 49% owned by Indian Orchard Generating Company, Inc. 39% general partnership interest in MASSPOWER, L.L.C. 1.2.3.1.1.10.2.2.2. JMC Altresco, Inc. Colorado corporation One Bowdoin Square Boston, MA 02114 100% owned by Beale Generating Company Holding company for subsidiaries/projects acquired through acquisition of Altresco Financial, Inc. 1.2.3.1.1.10.2.2.2.1. Altresco, Inc. 17 Colorado corporation One Bowdoin Square Boston, MA 02114 100% owned by JMC Altresco, Inc. General Partners - Pittsfield Generating Company, L.P. 1.2.3.1.1.10.2.2.2.2. Berkshire Pittsfield, Inc. Colorado corporation One Bowdoin Square Boston, MA 02114 100% owned by JMC Altresco, Inc. General Partner - Berkshire Feedline Acquisition Limited Partnership 1.2.3.1.1.10.2.2.2.2.1. Berkshire Feedline Acquisition Limited Partnership Massachusetts partnership One Bowdoin Square Boston, MA 02114 1% owned by Berkshire Pittsfield, Inc. Owner of pipeline connecting Pittsfield Generating Company, L.P. facility and Tennessee Gas Pipeline Company facilities 1.2.3.1.1.10.2.2.2.3. Pittsfield Partners, Inc. Colorado corporation One Bowdoin Square Boston, MA 02114 100% owned by JMC Altresco, Inc. Limited Partner - Pittsfield Generating Company, L.P. 1.2.3.1.1.10.2.2.3. JMC Iroquois, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by Beale Generating Company 4.57% General Partner and .36% Limited Partner in Iroquois Gas Transmission System, L.P. 1.2.3.1.1.10.2.2.3.1. Iroquois Gas Transmission System, L.P. Delaware partnership One Bowdoin Square Boston, MA 02114 4.93% owned by JMC Iroquois, Inc. Owner of a 375 mile natural gas pipeline extending through New York State and Connecticut providing services to markets in New York, New Jersey and New England 1.2.3.1.1.10.2.2.4. JMC Selkirk Holdings, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by Beale Generating Company 100% ownership of JMC Selkirk, Inc. and JMCS I Holdings, Inc. 18 1.2.3.1.1.10.2.2.4.1. JMC Selkirk, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by JMC Selkirk Holdings, Inc. Managing General Partner and Limited Partner of Selkirk Cogen Partners, L.P. Limited Partner interest (46.57%) in PentaGen Investors, L.P. 1.2.3.1.1.10.2.2.4.1.1. PentaGen Investors, L.P. Delaware partnership One Bowdoin Square Boston, MA 02114 46.57% owned by JMC Selkirk, Inc., and 3.43% owned by JMCS I Holdings, Inc. Limited partner (5.2502% preferred percentage Interest) in Selkirk Cogen Partners, L.P. 1.2.3.1.1.10.2.2.4.2. JMCS I Holdings, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by JMC Selkirk Holdings, Inc. General Partner (.50%) and Limited Partner (2.93%) interests in PentaGen Investors, L.P. 1.2.3.1.1.10.2.2.5. Orchard Gas Corporation Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by Beale Generating Company Administration and monitoring of gas supply for MASSPOWER project. 1.2.3.1.1.10.2.3. Mason Generating Company Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 89% owned by PG&E Generating Power Group, LLC Holding Company 1.2.3.1.1.10.2.3.1. Bowdoin Storage Services, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by Mason Generating Company Serves as Administrator for PentaGen Investors, L.P. 1.2.3.1.1.10.2.3.2. J. Makowski Associates, Inc. Massachusetts corporation One Bowdoin Square Boston, MA 02114 100% owned by Mason Generating Company Serve as Administrator for PentaGen Investors, L.P. 1.2.3.1.1.10.2.3.3. JMC Avoca, Inc. Delaware corporation 19 One Bowdoin Square Boston, MA 02114 100% owned by Mason Generating Company General Partner - Avoca Natural Gas Storage Project. Voluntary petition for relief under Chapter 11 filed on July 29, 1997 with the United States Bankruptcy Court, District of Delaware. 1.2.3.1.1.10.2.3.3.1. Avoca Natural Gas Storage New York general partnership One Bowdoin Square Boston, MA 02114 46.88% owned by JMC Avoca, Inc. 1.2.3.1.1.10.2.3.4. JMC Cayuta, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by Mason Generating Company 1.2.3.1.1.10.2.4. Eagle Power Corporation California corporation 100 Pine Street, 20th Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General partner in Logan Generating Company, L.P., Granite Generating Company, L.P., and Keystone Cogeneration Company, L.P. 1.2.3.1.1.10.2.4.1. Granite Generating Company, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 50% owned by Eagle Power Corporation Limited Partner in Keystone Urban Renewal Limited Partnership. 1.2.3.1.1.10.2.4.1.1. Granite Water Supply Company, Inc. Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Granite Generating Company, L.P. Supplies water for the Logan Project. 1.2.3.1.1.10.2.4.2. Keystone Cogeneration Company, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 50% owned by Eagle Power Corporation General Partner in Keystone Urban Renewal Limited Partnership. 1.2.3.1.1.10.2.5. Larkspur Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General Partner and limited partner in Hermiston Generating Company, L.P. 20 1.2.3.1.1.10.2.6. Buckeye Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Power Group, LLC General Partner in Hermiston Generating Company, L.P. 1.2.3.1.1.10.2.7. Raptor Holdings Company California corporation 100 Pine Street, 20th Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC Holding company for Cedar Bay Project entities; owns PG&E Management Services. 1.2.3.1.1.10.2.7.1. Gray Hawk Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Raptor Holdings Company Investment Company for Cedar Bay Project. 1.2.3.1.1.10.2.7.1.1. Cedar Bay Cogeneration, Inc. Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Gray Hawk Power Corporation General partner in Cedar Bay Generating Company, Limited Partnership. 1.2.3.1.1.10.2.7.2. PG&E Management Services Company California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by Raptor Holdings Company Inactive. 1.2.3.1.1.10.2.8. Toyan Enterprises California corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Power Group, LLC Limited partner in Indiantown Cogeneration, L.P.; general partner in Indiantown Project. 1.2.3.1.1.10.2.8.1. Indiantown Project Investment Partnership, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 24.817% owned by Toyan Enterprises General partner in Indiantown Cogeneration, L.P. 1.2.3.1.1.10.2.9. Spruce Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Power Group, LLC Holds general partnership interest in Spruce Limited Partnership. 21 1.2.3.1.1.10.2.9.1. Spruce Limited Partnership Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 35.5% owned by Spruce Power Corporation Hold limited partnership interest in Colstrip Energy Limited Partnership. 1.2.3.1.1.10.2.9.1.1. Colstrip Energy Limited Partnership Montana limited partnership 314 N. Last Chance Gulch Helena, MT 59624 37.5% owned by Spruce Limited Partnership Owns and operates an electric generating facility in Colstrip, Montana. 1.2.3.1.1.10.2.10. Merlin Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General partner in Fellows Generating Company, L.P. 1.2.3.1.1.10.2.10.1. Fellows Generating Company, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 51% owned by Merlin Power Corporation Formed to own, develop, finance, construct, operate and maintain an electric generation facility near Fellows, CA. 1.2.3.1.1.10.2.11. Pelican Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General partner in Okeelanta Power Limited Partnership. 1.2.3.1.1.10.2.11.1. Okeelanta Power Limited Partnership Florida limited partnership 316 Royal Poinciana Plaza Palm Beach, FL 33480 37.54% owned by Pelican Power Corporation Formed to develop, own and operate an electric generating facility in Okeelanta, Florida. Voluntarily filed a petition for relief under Chapter 11 on May 14, 1997. 1.2.3.1.1.10.2.12. Peregrine Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General partner in Chambers Cogeneration Limited Partnership. 1.2.3.1.1.10.2.13. Heron Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 22 100% owned by PG&E Generating Power Group, LLC General and limited partner in Gator Generating Company, L.P. (Osceola Project). 1.2.3.1.1.10.2.13.1. Gator Generating Company, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 79.2% owned by Heron Power Corporation Formed to develop, own, operate and lease (as lessor) a cogeneration facility (Osceola) in Palm Beach County, Florida. Filed a voluntary petition for bankruptcy protection under Chapter 11 on May 14, 1997. 1.2.3.1.1.10.2.14. Jaeger Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC Partner in Northampton Generating Company, L.P. 1.2.3.1.1.10.2.15. Falcon Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General and Limited partner in Scrubgrass Generating Company, L.P.; owner of Scrubgrass Power Corp. 1.2.3.1.1.10.2.15.1. Scrubgrass Power Corp. Pennsylvania corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by Falcon Power Corporation General partner in Scrubgrass Generating Company, L.P. 1.2.3.1.1.10.2.16. Eucalyptus Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Power Group, LLC General Partner in Citrus Generating, Company, L.P. 1.2.3.1.1.10.2.16.1. Citrus Generating Company, L.P. Delaware limited partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 49% owned by Cooper's Hawk Power Corporation, 49% owned by Eucalyptus Power Corporation, and 2% owned by PG&E Shareholdings, Inc. Inactive Company. Originally formed to own and operate an electric generating facility. 1.2.3.1.1.10.2.17. Cooper's Hawk Power Corporation California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Power Group, LLC General partner in Citrus Generating Company, L.P. 23 1.2.3.1.1.10.2.18. Loon Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Power Group, LLC Investment company. 1.2.3.1.1.10.3. PG&E Generating Services, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Company, LLC Holding company for PG&E Generating Company service entities. 1.2.3.1.1.10.3.1. J. Makowski Pittsfield, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by PG&E Generating Services, LLC 1.2.3.1.1.10.3.2. J. Makowski Services, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by PG&E Generating Services, LLC 1.2.3.1.1.10.3.3. JMCS I Management, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by PG&E Generating Services, LLC 1.2.3.1.1.10.3.4. USGen Fuel Services, Inc. Delaware corporation One Bowdoin Square Boston, MA 02114 100% owned by PG&E Generating Services, LLC 1.2.3.1.1.10.3.5. PG&E Construction Agency Services I, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Services, LLC. Formed to act as construction agent under the Master Turbine Trust with GE. 1.2.3.1.1.10.3.6. PG&E Construction Agency Services II, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Services, LLC. Formed to act as construction agent under the Master Turbine Trust with Mitsubishi. 1.2.3.1.1.10.3.7. PG&E Construction Agency Services III, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor 24 Bethesda, MD 20814-6161 100% owned by PG&E Generating Services, LLC. Formed to act as construction agent under the Master Turbine Trust. 1.2.3.1.1.10.3.8. PG&E Turbine Acquisition Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Generating Services, LLC. Formed to act as construction agent under the Master Turbine Trust with GE. 1.2.3.1.1.10.3.9. PG&E Operating Services Holdings, Inc. California corporation 100 Pine Street, 20/th/ Floor San Francisco, CA 94111 100% owned by PG&E Generating Services, LLC General partner in PG&E Generating Company and PG&E Operating Services Company; sole member of PG&E National Energy Group Acquisition Company. 1.2.3.1.1.10.3.9.1. USOSC Holdings, Inc. Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Operating Services Holdings, Inc. Holds a partnership interest in PG&E Operating Services Company. 1.2.3.1.1.10.3.9.1.1. PG&E Operating Services Company California general partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 98% owned by PG&E Operating Services Holdings, Inc.; and 2% owned by USOSC Holdings, Inc. Formed to enter into operations and maintenance activities. 1.2.3.1.1.10.3.9.2. USGen Holdings, Inc. Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% Owned by PG&E Generating Services, LLC Holds a partnership interest in PG&E National Energy Group Company. 1.2.3.1.1.10.3.9.2.1. PG&E National Energy Group Company (formerly PG&E Generating Company) California general partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 98% owned by PG&E Operating Services Holdings, Inc., and 2% owned by USGen Holdings, Inc. Develops and manages electrical generation facilities. 1.2.3.1.1.10.3.9.2.1.1. First Oregon Land Corporation 25 Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E National Energy Group Company Formed to enter into real estate options in the State of Oregon. 1.2.3.1.1.10.3.9.2.1.2. Topaz Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E National Energy Group Company Holds partnership interest in Carneys Point Generating Company. 1.2.3.1.1.10.3.9.2.1.2.1. Carneys Point Generating Company Delaware general partnership 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 50% owned by Topaz Power Corporation, and 50% owned by Garnet Power Corporation. Formed to lease, manage, operate and maintain a cogeneration facility in Carneys Point, New Jersey. 1.2.3.1.1.10.3.9.2.1.3. Garnet Power Corporation Delaware corporation 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E National Energy Group Company Holds partnership interest in Carneys Point Generating Company. 1.2.3.1.1.10.3.9.3. PG&E National Energy Group Acquisition Company, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Operating Services Holdings, Inc. Formed for acquisitions purposes. 1.2.3.1.1.11. Valley Real Estate, Inc California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% owned by PG&E Shareholdings, Inc.; was formed for real estate development. 1.2.3.1.2. PG&E Overseas, Inc. California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 100% by PG&E Enterprises. U.S. shareholder of PG&E Overseas, Ltd., and PG&E Overseas II, Ltd. 1.2.3.1.2.1. PG&E Australia California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 A wholly-owned, non-regulated indirect subsidiary of PG&E Enterprises through its ownership of PG&E 26 Overseas, Inc. for business development in Australia. 1.2.3.1.2.2. PG&E Overseas, Ltd. Cayman Islands company Maples & Calder P.O. Box 309 George Town, Grand Cayman Cayman Islands, B.W.I. A wholly-owned, indirect subsidiary of PG&E Enterprises through its ownership of PG&E Overseas, Inc.; holding company for PG&E Pacific I, Ltd. and PG&E Pacific II, Ltd. 1.2.3.1.2.2.1. PG&E Pacific I, Ltd. Cayman Islands company Maples & Calder P.O. Box 309 George Town, Grand Cayman Cayman Islands, B.W.I. A non-regulated indirect subsidiary of PG&E Enterprises through its ownership of PG&E Overseas Inc.; an overseas distribution company of PG&E Overseas, Ltd. 1.2.3.1.2.2.2. PG&E Pacific II, Ltd. Cayman Islands company Maples & Calder P.O. Box 309 George Town, Grand Cayman Cayman Islands, B.W.I. A non-regulated indirect subsidiary of PG&E Enterprises through its ownership of PG&E Overseas Inc.; an overseas distribution company of PG&E Overseas, Ltd. 1.2.3.1.3. Quantum Ventures California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 A wholly-owned, non-regulated subsidiary of PG&E Enterprises. 1.2.3.1.3.1. PG&E Energy Services Ventures, Inc. (Formerly PG&E Energy Services Ventures, LLC) Delaware corporation 345 California St., 23rd Floor San Francisco, CA 94105 PG&E Energy Services Ventures, Inc. is a wholly owned, non-regulated indirect subsidiary of PG&E Enterprises through its ownership in Quantum Ventures. PG&E Energy Services Ventures, Inc. provides energy-related goods and services. 1.2.3.1.3.2. Barakat & Chamberlin, Inc. California corporation 345 California Street, Suite 3200 San Francisco, CA 94104 100% owned by Quantum Ventures 1.2.3.1.3.3. Creston Financial California corporation 345 California Street, Suite 3200 San Francisco, CA 94104 27 100% owned by Quantum Ventures 1.2.3.1.3.4. Real Estate Energy Solutions, LLC Delaware limited liability company 888 S.W. Fifth Avenue, Suite 3200 Portland, OR 97204 50% owned by Quantum Ventures, and 50% owned by Jones Lang LaSalle Management Services, Inc. 1.2.3.2. PG&E Gas Transmission Corporation California corporation 1400 SW Fifth Avenue, Suite 900 Portland, OR 97201 100% owned by PG&E National Energy Group, Inc. Gas holding company 1.2.3.2.1. PG&E Gas Transmission, Holdings Corporation (formerly PG&E Gas Transmission, Northeast Corporation) California corporation 1400 SW Fifth Avenue, Suite 900 Portland, Oregon 97201 100% owned by PG&E Gas Transmission Corporation. Formed to pursue gas transmission business opportunities. 1.2.3.2.1.1. North Baja Pipeline, LLC Delaware limited liability company 1400 SW Fifth Avenue, Suite 900 Portland, OR 97201 100% owned by PG&E Gas Transmission Holdings Corporation. Formed for the construction and operation of a natural gas pipeline capable of transporting natural gas from Arizona to the Mexico border. 1.2.3.2.2. GTN Holdings, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Gas Transmission Corporation. Formed for the limited purpose of holding stock in PG&E Gas Transmission, Northwest Corporation 1.2.3.2.2.1. PG&E Gas Transmission, Northwest Corporation California corporation 1400 SW Fifth Avenue, Suite 900 Portland, Oregon 97201 100% owned by GTN Holdings LLC. Owns and operates gas transmission pipelines and associated facilities capable of transporting natural gas from the Canadian-U.S. border to the Oregon-California border. 1.2.3.2.2.1.1. Pacific Gas Transmission International, Inc. California corporation 1400 SW Fifth Avenue, Suite 900 Portland, Oregon 97201 100% owned by PG&E Gas Transmission, Northwest Corporation. Previously owned 99% of the beneficial interest of PG&E Queensland Unit Trust (which interest was sold to PG&E Gas Transmission Unit Holdings Pty Ltd. in September 1997). 28 1.2.3.2.2.1.2. Pacific Gas Transmission Company California corporation 1400 SW Fifth Avenue, Suite 900 Portland, Oregon 97201 100% owned by PG&E Gas Transmission, Northwest Corporation. Formed to pursue business opportunities in the natural gas business in the United States. 1.2.3.2.2.1.3. Stanfield Hub Services, LLC Washington limited liability company 1400 SW Fifth Avenue, Suite 900 Portland, Oregon 97201 50% owned by PG&E Gas Transmission, Northwest Corporation. Formed to pursue opportunities for construction and operation of natural gas storage facilities. 1.2.4. PG&E Strategic Capital, Inc. Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Strategic Capital, Inc. is a wholly-owned subsidiary of PG&E Corporation. PG&E Strategic Capital, Inc. was formed for general business purposes. 1.2.5. PG&E Corporation Support Services, Inc. Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Corporation Support Services, Inc. is a wholly- owned subsidiary of PG&E Corporation that provides general corporate support services to the PG&E Corporation family outside the State of California. 1.2.6. PG&E National Energy Group, LLC Delaware limited liability company 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 100% owned by PG&E Corporation and was formed for the limited purpose of holding stock in PG&E National Energy Group, Inc. 1.2.7. The PG&E Corporation Foundation California corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 The PG&E Corporation Foundation is a wholly-owned non-profit entity of PG&E Corporation that was formed and operates exclusively for charitable, scientific, educational and literary purposes. 1.2.8. PG&E Ventures ePro, LLC Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Ventures ePro, LLC is a wholly-owned subsidiary of PG&E Corporation that was formed to make and hold an investment in an e-procurement exchange. 1.2.9. PG&E Ventures, LLC Delaware corporation One Market, Spear Tower, Suite 2400 29 San Francisco, CA 94105 PG&E Ventures, LLC incorporated under the laws of the State of Delaware, is a wholly-owned subsidiary of PG&E Corporation that was formed for the purpose of holding interests in other businesses, financing and other transactions. 1.2.9.1. Pacific Venture Capital, LLC Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 Pacific Venture Capital, LLC is a wholly-owned subsidiary of PG&E Ventures, LLC that was formed to build and manage a portfolio of capital investments in growing energy and telecommunications companies. 1.2.9.2. PG&E Telecom, LLC Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Telecom, LLC is a wholly-owned subsidiary of PG&E Ventures, LLC that was formed for the purpose of engaging in telecommunications and related business activities. 1.2.9.2.1. PG&E Capital, LLC Delaware corporation One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Capital, LLC is a wholly-owned subsidiary of PG&E Telecom, LLC, formed for financing and other transactions related to the energy industry. 30 4.1. PITTSFIELD GENERATING COMPANY, L.P. Pittsfield Generating Company, L.P. 235 Merrill Road Pittsfield, MA 01202 Pittsfield Generating Company, L.P. is a 165 megawatt (MW) combined cycle, natural gas-fired cogeneration facility (the "Facility") selling power to Commonwealth Electric Company, Cambridge Electric Company, and USGen New England, Inc. and selling steam to General Electric Company. 4.2. SELKIRK COGEN PARTNERS, L.P. Selkirk Cogen Partners, L.P. 24 Power Park Drive Selkirk, NY 12158 Selkirk Cogen Partners, L.P. Unit I is an 80 MW natural gas fired dispatchable cogeneration facility selling power to Niagara Mohawk Power Corporation. Selkirk Cogen Partners, L.P. Unit II is a 265 MW natural gas fired dispatchable cogeneration facility (Unit I and Unit II together, the "Facility") selling power to Consolidated Edison Company of New York, Inc. 4.3. KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP Keystone Urban Renewal Limited Partnership Box 169-C, Route 130 South, Swedesboro, NJ 08085 Keystone Urban Renewal Limited Partnership is a 225 MW pulverized coal-fired dispatchable generation facility (the "Facility") selling power to Connectiv (formerly Atlantic Energy Company). 4.4. LOGAN GENERATING COMPANY, L.P. Logan Generating Company, L.P. Box 169-C, Route 130 South, Swedesboro, NJ 08085 Logan Generating Company, L.P. is a 225 MW pulverized coal fired dispatchable generation facility (the "Facility") selling power to Connectiv (formerly Atlantic Electric Company). 4.5. HERMISTON GENERATING COMPANY, L.P. Hermiston Generating Company, L.P. Box 930, Hermiston, OR 97838 Hermiston Generating Company, L.P. is a 474 MW natural gas fired dispatchable cogeneration facility (the "Facility") selling power to PacifiCorp. PacifiCorp owns a 50% undivided interest in the Facility. 31 4.6. MASSPOWER MASSPOWER 750 Worcester Street Indian Orchard, MA 01151 MASSPOWER is a 240 MW natural gas-fired combined cycle cogeneration facility located in Springfield, MA, selling power to Western Massachusetts Electric Company, Boston Edison Company, Commonwealth Electric Company and Massachusetts Municipal Wholesale Electric Company, and selling steam to Monsanto Company. 4.7. MILLENNIUM POWER PARTNERS, L.P. Millennium Power Partners, L.P. P.O. Box 588 10 Sherwood Lane Charlton, Massachusetts 01508-0588 Millennium Power Partners, L.P. is currently under construction, with commercial operation expected in the spring of 2001. Millennium Power Partners, L.P. will be a nominal 360 MW natural gas-fired combined cycle merchant power facility which anticipates selling power into the New England Power Pool on a spot basis as well as under short-to medium-term bilateral contracts. 4.8. CEDAR BAY GENERATING COMPANY, LIMITED PARTNERSHIP Cedar Bay Generating Company, Limited Partnership 9640 Eastport Road Jacksonville, FL 32218 Cedar Bay Generating Company, Limited Partnership owns and operates a 250 MW coal-fired electric generating facility in Jacksonville, Florida, selling power to Florida Power & Light Company, and selling steam to Smurfit Stone Container Corporation (formerly Stone Container Corporation). 4.9. NORTHAMPTON GENERATING COMPANY, L.P. Northampton Generating Company, L.P. One Horwith Drive Northampton, PA 18067 Northampton Generating Company, L.P. owns and operates an approximately 98 MW anthracite waste coal-fired electric generating facility in Northampton, Pennsylvania, selling power to Metropolitan Edison Company, and selling steam to unrelated industrial operations. 4.10. SCRUBGRASS GENERATING COMPANY, L.P. Scrubgrass Generating Company, L.P. RR1 Lisbon Road Kennerdell, PA 16374 Scrubgrass Generating Company, L.P. leases an 87 MW waste coal-fired electric generating facility in Venango County, Pennsylvania, to Buzzard Power Corporation. 32 4.11. INDIANTOWN COGENERATION, L.P. Indiantown Cogeneration, L.P. 19140 SW Warfield Boulevard Indiantown, FL 34956 Indiantown Cogeneration, L.P. owns and operates a 330 MW coal-fired electric generating facility in Indiantown, Florida, selling power to Florida Power & Light Company, and selling steam to Caulkins Indiantown Citrus Co. 4.12. CHAMBERS COGENERATION LIMITED PARTNERSHIP Chambers Cogeneration Limited Partnership 500 Shell Road Carneys Point, NJ 08069-2926 Chambers Cogeneration Limited Partnership owns and operates a 252 MW coal-fired electric generating facility in Carneys Point, New Jersey, selling power to Connectiv (formerly Atlantic Energy Company), and selling power and steam to DuPont. 4.13. ATHENS GENERATING COMPANY, L.P. Athens Generating Company, L.P. 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 Athens Generating Company, L.P. is currently developing a 1,080 MW natural gas-fired electric generating merchant power facility in Athens, New York, with commercial operation expected in the summer of 2003. 4.14. LA PALOMA GENERATING COMPANY, LLC La Paloma Generating Company, LLC 1760 W. Skyline Road McKittrick, CA 93251 La Paloma Generating Company, LLC is currently constructing a 1,020 MW gas-fired electric generating merchant power facility in Kern County, California. It anticipates selling power into the California market on a spot basis as well as under short-to-medium term bilateral contracts. 33 4.15. LAKE ROAD GENERATING COMPANY, L.P. Lake Road Generating Company, L.P. 56 Alexander Parkway Dayville, CT 06241 Lake Road Generating Company, L.P. is currently under construction, with commercial operation expected in the summer of 2001. Lake Road Generating Company, L.P. will be a nominal 792 MW natural gas-fired combined cycle merchant power facility which anticipates selling power into the New England Power Pool on a spot basis as well as under short-to medium-term bilateral contracts. 4.16. MANTUA CREEK GENERATING COMPANY, L.P. Mantua Creek Generating Company, L.P. 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 4.17. OKEECHOBEE GENERATING COMPANY, LLC Okeechobee Generating Company, LLC 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 Okeechobee Generating Company, LLC is currently developing a 550 MW natural gas-fired electric generating merchant power facility in Okeechobee, Florida 4.18. USGEN NEW ENGLAND, INC. USGen New England, Inc. 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 USGen New England, Inc. owns and operates 17 generating facilities comprising of approximately 3,962 megawatts of generation, selling power in the New England area markets. 34 4.19. PG&E DISPERSED GENERATING COMPANY, LLC PG&E Dispersed Generating Company, LLC 7500 Old Georgetown Road, 13/th/ Floor Bethesda, MD 20814-6161 PG&E Dispersed Generating Company, LLC is currently developing and/or operating small peaker facilities in Ohio and is acting as an engineering procurement construction contractor on two small peaker facilities in California. 4.20. LIBERTY GENERATING COMPANY, LLC Liberty Generating Company, LLC 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 Liberty Generating Company, LLC is currently developing a 1,100 MW natural gas-fired electric generating merchant power facility in Linden, New Jersey. 4.21. BADGER GENERATING COMPANY, LLC Badger Generating Company, LLC 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 Badger Generating Company, LLC is currently developing a 1,100 MW natural gas-fired electric generating merchant power facility in Pleasant Prairie, Wisconsin. 4.22. MADISON WINDPOWER LLC Madison Windpower LLC 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 Madison Windpower, LLC is currently operating a 12MW wind-powered merchant power facility in Madison, New York. 4.23. COVERT GENERATING COMPANY, LLC Covert Generating Company, LLC 7500 Old Georgetown Road, 13th Floor Bethesda, MD 20814-6161 Covert Generating Company, LLC is currently developing a 1,080 natural gas-fired electric generating merchant power facility in Covert Township, Michigan. 35 EX-23.1 34 dex231.txt CONSENT OF DELOITTE & TOUCHE LLP EXHIBIT 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statements No. 333-16255 and 333-25685 on Form S-3 and 333-16253, 333-27015, 333-68155, 333- 46772, 333-77145 and 333-77149 on Form S-8 of PG&E Corporation and Registration Statements No. 33-64136, 33-50707, 33-62488 and 33-61959 on Form S-3 of Pacific Gas and Electric Company of our reports dated April 6, 2001 (which express an unqualified opinion and include an explanatory paragraph relating to items discussed in Notes 2 and 3 of the notes to the consolidated financial statements), appearing in and incorporated by reference in this Annual Report on Form 10-K of PG&E Corporation and Pacific Gas and Electric Company for the year ended December 31, 2000. DELOITTE & TOUCHE LLP San Francisco, California April 11, 2001 EX-23.2 35 dex232.txt CONSENT OF ARTHUR ANDERSEN LLP EXHIBIT 23.2 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 8,1999, incorporated by reference in this Form 10-K, into the Company's previously filed registration statements as follows: (1) PG&E Corporation's Form S-3 Registration Statement File No. 333-16255 (relating to PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-64136 (relating to $2,000,000,000 aggregate principal amount of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds and Medium-Term Notes); (3) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal amount of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds); (4) 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); (5) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-61959 (relating to $335,000,000 aggregate liquidation value of Cumulative Quarterly Income Preferred Securities); (6) PG&E Corporation's Form S-8 Registration Statement File No. 333-16253 (relating to PG&E Corporation's Long-Term Incentive Program); (7) 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); (8) 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); (9) PG&E Corporation's Form S-8 Registration Statement File No. 333-68155 (relating to PG&E Gas Transmission, Northwest Corporation Savings Fund Plan for Non- Management Employees); (10) PG&E Corporation's Form S-8 Registration Statement File No. 333-77145 (relating to the PG&E Corporation Retirement Savings Plan); (11) PG&E Corporation's Form S-8 Registration Statement File No. 333-77149 (relating to PG&E Corporation's Long- Term Incentive Program) and (12) PG&E Corporation's Form S-8 Registration Statement File No. 333-46772 (relating to Pacific Gas and Electric Company Savings Fund Plan for Union-Represented Employees). ARTHUR ANDERSEN LLP San Francisco, California April 11, 2001 EX-24.1 36 dex241.txt RESOLUTIONS OF THE BOARD OF DIRECTORS - PG&E CORP. EXHIBIT 24.1 RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PG&E CORPORATION ---------------- April 5, 2001 ------------- WHEREAS, the Audit Committee of this Board of Directors has reviewed the audited consolidated financial statements for this corporation for the year ended December 31, 2000, and has recommended to the Board that such financial statements be included in the corporation's Annual Report on Form 10-K for the year ended December 31, 2000, to be filed with the Securities and Exchange Commission; BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby authorized to sign on behalf of this corporation and as attorneys in fact for the Chairman of the Board, President, and Chief Executive Officer, the Senior Vice President, Chief Financial Officer, and Treasurer, and the Vice President and Controller of this corporation the Form 10-K Annual Report for the year ended December 31, 2000, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereunder with regard to said Form 10-K Annual Report. I, LINDA Y.H. CHENG, do hereby certify that I am an Assistant Corporate Secretary of PG&E CORPORATION, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true, and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held at the office of said corporation on April 5, 2001; 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 11th day of April, 2001. LINDA Y.H. CHENG ------------------------------- Linda Y.H. Cheng Assistant Corporate Secretary PG&E CORPORATION C O R P O R A T E S E A L RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PACIFIC GAS AND ELECTRIC COMPANY -------------------------------- April 5, 2001 ------------- WHEREAS, the Audit Committee of this Board of Directors has reviewed the audited consolidated financial statements for this company for the year ended December 31, 2000, and has recommended to the Board that such financial statements be included in the company's Annual Report on Form 10-K for the year ended December 31, 2000, to be filed with the Securities and Exchange Commission; BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby authorized to sign on behalf of this company and as attorneys in fact for the President and Chief Executive Officer and the Senior Vice President - Chief Financial Officer, and Treasurer, and the Vice President - Controller of this company the orm 10-K Annual Report for the year ended December 31, 2000, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereunder with regard to said Form 10-K Annual Report. I, LINDA Y.H. CHENG, do hereby certify that I am Senior Assistant Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true, and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held on April 5, 2001; 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 11th day of April, 2001. LINDA Y.H. CHENG ---------------------------------- Linda Y.H. Cheng Senior Assistant Corporate Secretary PACIFIC GAS AND ELECTRIC COMPANY C O R P O R A T E S E A L EX-24.2 37 dex242.txt POWERS OF ATTORNEY EXHIBIT 24.2 POWER OF ATTORNEY Each of the undersigned Directors of PG&E Corporation hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. DAVID R. ANDREWS DAVID M. LAWRENCE - -------------------------- -------------------------------- David R. Andrews David M. Lawrence, MD DAVID A. COULTER MARY S. METZ - -------------------------- -------------------------------- David A. Coulter Mary S. Metz C. LEE COX CARL E. REICHARDT - -------------------------- -------------------------------- C. Lee Cox Carl E. Reichardt WILLIAM S. DAVILA BARRY LAWSON WILLIAMS - -------------------------- -------------------------------- William S. Davila Barry Lawson Williams ROBERT D. GLYNN, JR. - -------------------------- Robert D. Glynn, Jr. POWER OF ATTORNEY ROBERT D. GLYNN, JR., the undersigned, Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Chairman of the Board, Chief Executive Officer, and President (principal executive officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. ROBERT D. GLYNN, JR. -------------------------------- Robert D. Glynn, Jr. POWER OF ATTORNEY PETER A. DARBEE, the undersigned, Senior Vice President, Chief Financial Officer, and Treasurer of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Senior Vice President, Chief Financial Officer, and Treasurer (principal financial officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. PETER A. DARBEE ------------------------------ Peter A. Darbee POWER OF ATTORNEY CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President and Controller (principal accounting officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. CHRISTOPHER P. JOHNS --------------------------- Christopher P. Johns POWER OF ATTORNEY Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. DAVID R. ANDREWS DAVID M. LAWRENCE, MD - ------------------------ -------------------------- David R. Andrews David M. Lawrence, MD DAVID A. COULTER MARY S. METZ - ------------------------ -------------------------- David A. Coulter Mary S. Metz C. LEE COX CARL E. REICHARDT - ------------------------ -------------------------- C. Lee Cox Carl E. Reichardt WILLIAM S. DAVILA GORDON R. SMITH - ------------------------ -------------------------- William S. Davila Gordon R. Smith ROBERT D. GLYNN, JR. BARRY LAWSON WILLIAMS - ------------------------ -------------------------- Robert D. Glynn, Jr. 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, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as President and Chief Executive Officer (principal executive officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. GORDON R. SMITH ------------------------------ Gordon R. Smith POWER OF ATTORNEY KENT M. HARVEY, the undersigned, Senior Vice President - Chief Financial Officer and Treasurer of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Senior Vice President - Chief Financial Officer and Treasurer (principal financial officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. KENT M. HARVEY ------------------------------ Kent M. Harvey POWER OF ATTORNEY DINYAR B. MISTRY, the undersigned, Vice President - Controller of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President - Controller (principal accounting officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 2000, 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 5th day of April, 2001. DINYAR B. MISTRY --------------------- Dinyar B. Mistry -----END PRIVACY-ENHANCED MESSAGE-----