-----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, U3SOzMVCRsnlWdLzXnepnhYapne+OMPnFQRvmcHoyXyiDRTW6UFuRtB4vDa2ny+U KvM4QWR2otZexvJMf8mqng== 0000898430-97-000819.txt : 19970305 0000898430-97-000819.hdr.sgml : 19970305 ACCESSION NUMBER: 0000898430-97-000819 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970304 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: PG&E CORP CENTRAL INDEX KEY: 0001004980 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 943234914 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-12609 FILM NUMBER: 97550497 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 MAIL CODE B32 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4159737000 MAIL ADDRESS: STREET 1: 77 BEALE ST B32 STREET 2: PO BOX 770000 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 FORMER COMPANY: FORMER CONFORMED NAME: PG&E PARENT CO INC DATE OF NAME CHANGE: 19951214 10-K405 1 FORM 10-K FOR PG&E CORPORATION SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION EXACT NAME OF REGISTRANT IRS EMPLOYER FILE AS SPECIFIED IN ITS STATE OF IDENTIFICATION NUMBER CHARTER INCORPORATION NUMBER ---------- ------------------------ ------------- -------------- 1-12609 PG&E CORPORATION California 94-3234914 1-2348 PACIFIC GAS AND ELECTRIC California 94-0742640 COMPANY
77 Beale Street 94177 P.O. Box 770000 (ZIP CODE) San Francisco, California (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (415) 973-7000 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS WHICH REGISTERED - ------------------- --------------------------- PG&E CORPORATION Common Stock, no par value New York Stock Exchange and Pacific Stock Exchange PACIFIC GAS AND ELECTRIC COMPANY First Preferred Stock, cumulative, American Stock Exchange and par value $25 per share: Pacific Stock Exchange
Redeemable: 7.44% 5% Series A 7.04% 4.80% 6-7/8% 4.50% 5% 4.36% Mandatorily Redeemable: 6.57% 6.30% Nonredeemable: 6% 5-1/2% 5% 7.90% Cumulative Quarterly Income Preferred American Stock Exchange and Securities, Series A (liquidation preference Pacific Stock Exchange $25), issued by PG&E Capital I and guaranteed by Pacific Gas and Electric Company SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT AS OF FEBRUARY 18, 1997: PG&E Corporation Common Stock $9,460 million Pacific Gas and Electric Company First Preferred Stock $453 million COMMON STOCK OUTSTANDING AS OF FEBRUARY 18, 1997: PG&E Corporation: 416,528,027 Pacific Gas and Electric Company: Wholly owned by PG&E Corporation The market values of certain series of First Preferred Stock, for which market prices as of a date within 60 days prior to the date of filing were not available, were derived by dividing the annual dividend rate of each such series of stock by the average yield of all of Pacific Gas and Electric Company's Preferred Stock outstanding for which market prices were available. DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. (1) Designated portions of the Annual Report to Shareholders for the year ended December 31, 1996.......................... Part II (Items 5, 6, 7 and 8) Part IV (Item 14) (2) Designated portions of the Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders.................... Part III (Items 10, 11, 12 and 13) TABLE OF CONTENTS
PAGE ---- Glossary of Terms PART I Item 1. Business......................................................... 1 GENERAL.......................................................... 1 Corporate Structure and Business................................. 1 Competition and the Changing Regulatory Environment.............. 2 Electric Industry.............................................. 3 Gas Industry................................................... 4 Regulation of PG&E............................................... 5 State Regulation............................................... 5 Federal Regulation............................................. 5 Local Regulation............................................... 5 Licenses and Permits........................................... 5 Regulation of PG&E Corporation................................... 6 Rate Matters..................................................... 6 California Ratemaking Mechanisms............................... 6 1997 Revenues.................................................. 8 Future Ratemaking................................................ 9 Electric Ratemaking............................................ 9 Gas Ratemaking................................................. 11 Capital Requirements and Financing Programs...................... 11 Risk Management Programs......................................... 13 ELECTRIC UTILITY OPERATIONS...................................... 14 Electric Industry Restructuring Legislation...................... 14 Independent System Operator and Power Exchange................. 14 Direct Access.................................................. 14 Rate Levels and Recovery of CTCs............................... 14 Base Revenue Increases......................................... 15 Public Purpose Programs........................................ 15 Electric Operating Statistics.................................... 17 Electric Generating and Transmission Capacity.................... 18 Diablo Canyon.................................................... 20 Diablo Canyon Operations....................................... 20 Diablo Settlement.............................................. 20 Nuclear Fuel Supply and Disposal............................... 21 Insurance...................................................... 22 Decommissioning................................................ 22 Other Electric Resources......................................... 23 QF Generation and Other Power Purchase Contracts............... 23 Geothermal Generation.......................................... 24 Helms Pumped Storage Plant..................................... 24 Electric Load Forecast and Resource Planning and Procurement..... 24 Electric Transmission............................................ 25 GAS UTILITY OPERATIONS........................................... 26 Gas Operations................................................... 26 Gas Operating Statistics......................................... 27 Natural Gas Supplies............................................. 28 Gas Regulatory Framework......................................... 28
i TABLE OF CONTENTS--(CONTINUED)
PAGE ---- Transportation Commitments..................................... 29 El Paso and PGT Capacity..................................... 29 Transwestern Capacity........................................ 30 Gas Reasonableness Proceedings................................. 30 1988-1990 Canadian Gas Procurement Activities................ 30 Gas Settlement Agreement..................................... 31 PGT/PG&E Pipeline Expansion ................................... 31 CPUC Ratemaking.............................................. 31 FERC Ratemaking.............................................. 32 DIVERSIFIED OPERATIONS......................................... 32 PG&E ENVIRONMENTAL MATTERS..................................... 33 Environmental Matters.......................................... 33 Environmental Protection Measures............................ 33 Hazardous Waste Compliance and Remediation................... 34 Potential Recovery of Hazardous Waste Compliance and Remediation Costs............................................ 36 Compressor Station Litigation................................ 36 Electric and Magnetic Fields................................. 36 Low Emission Vehicle Programs................................ 37 FORMATION OF PG&E CORPORATION.................................. 38 Item 2. Properties..................................................... 39 Item 3. Legal Proceedings.............................................. 39 Antitrust Litigation......................................... 39 Counties Franchise Fees Litigation........................... 39 Cities Franchise Fees Litigation............................. 40 Norcen Litigation............................................ 41 California Attorney General Investigation.................... 41 Diablo Canyon Environmental Litigation....................... 42 Compressor Station Chromium Litigation....................... 42 Item 4. Submission of Matters to a Vote of Security Holders............ 43 EXECUTIVE OFFICERS OF THE REGISTRANT........................... 44 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters............................................ 46 Item 6. Selected Financial Data........................................ 46 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................................... 46 Item 8. Financial Statements and Supplementary Data.................... 46 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................................... 46 PART III Item 10. Directors and Executive Officers of the Registrant............. 46 Item 11. Executive Compensation......................................... 47 Item 12. Security Ownership of Certain Beneficial Owners and Management. 47 Item 13. Certain Relationships and Related Transactions................. 47 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...................................................... 47 Signatures............................................................... 52 Report of Independent Public Accountants................................. 53 Financial Statement Schedule............................................. 54
ii GLOSSARY OF TERMS AB 1890......... Assembly Bill 1890, the California electric industry restructuring legislation AEAP............ Annual Earnings Assessment Proceeding AER............. Annual Energy Rate AFUDC........... allowance for funds used during construction Bechtel......... Bechtel Enterprises, Inc. BCAP............ Biennial Cost Allocation Proceeding BRPU............ Biennial Resource Plan Update BTA............. best technology available Btu............. British thermal unit California Superfund...... California Hazardous Substance Account Act CARE............ California Alternate Rates for Energy CCAA............ California Clean Air Act CEC............. California Energy Commission Central Coast Board.......... Central Coast Regional Water Quality Control Board CERCLA.......... Comprehensive Environmental Response, Compensation, and Liability Act CIG............. customer identified gas program Company......... Pacific Gas and Electric Company and its subsidiaries, or PG&E Corporation and its subsidiaries, as determined by the context core customers.. residential and smaller commercial gas customers core subscription customers...... noncore customers who choose bundled service CPIM............ core procurement incentive mechanism CPUC............ California Public Utilities Commission CTC............. competition transition costs Diablo Canyon... Diablo Canyon Nuclear Power Plant Diablo Settlement..... Diablo Canyon rate case settlement DOE............. U.S. Department of Energy DSM............. Demand Side Management ECAC............ Energy Cost Adjustment Clause EDRA............ electric deferred refund account El Paso......... El Paso Natural Gas Company EMF............. electric and magnetic fields Enterprises..... PG&E Enterprises EPA............. United States Environmental Protection Agency ERAM............ Electric Revenue Adjustment Mechanism ESI............. Energy Source, Inc. FERC............ Federal Energy Regulatory Commission Gas Accord...... Gas Accord Settlement Geysers......... The Geysers Power Plant GRC............. General Rate Case Helms........... Helms hydroelectric pumped storage plant Holding Company Act............ Public Utility Holding Company Act of 1935 Humboldt........ Humboldt Bay Power Plant ICIP............ Incremental Cost Incentive Price InterGen........ International Generating Company, Ltd. ISO............. Independent System Operator ITCS............ Interstate Transition Cost Surcharge
kV.............. kilovolts kVa............. kilovolt-amperes kW.............. kilowatts kWh............. kilowatt-hour LEV............. low emission vehicle Mcf............. thousand cubic feet MMcf............ million cubic feet MMcf/d.......... million cubic feet per day MW.............. megawatts NEIL............ Nuclear Electric Insurance Limited NML............. Nuclear Mutual Limited noncore customers...... industrial and larger commercial gas customers NOx............. oxides of nitrogen NRC............. Nuclear Regulatory Commission Nuclear Waste Act............ Nuclear Waste Policy Act of 1982 ORA............. Office of Ratepayer Advocates, formerly known as the Division of Ratepayer Advocates PBR............. performance-based ratemaking PEPR............ Pipeline Expansion Project Reasonableness case PG&E............ Pacific Gas and Electric Company PG&E Expansion.. the PG&E portion of the Pipeline Expansion PGT............. Pacific Gas Transmission Company PGT Expansion... the PGT portion of the Pipeline Expansion Pipeline Expansion...... PGT/PG&E Pipeline Expansion PPPs............ public purpose programs PRP............. potentially responsible party PX.............. California Power Exchange QF.............. qualifying facility RAP............. Revenue Adjustment Proceeding SEC............. Securities and Exchange Commission Teco............ Teco Pipeline Company TRA............. Transition Revenue Account transition period......... the period during which electric rates are frozen at 1996 levels, which extends until the earlier of March 31, 2002 or the point in time when PG&E has recovered its transition costs Transwestern.... Transwestern Pipeline Company TURN............ The Utility Reform Network USGen........... U.S. Generating Company USOSC........... U.S. Operating Services Company Vantus.......... Vantus Energy Corporation Valero.......... Valero Natural Gas Company
PART I ITEM 1. BUSINESS. GENERAL CORPORATE STRUCTURE AND BUSINESS PG&E Corporation was incorporated in California in 1995 for the purpose of becoming the parent holding company of Pacific Gas and Electric Company (PG&E). Effective January 1, 1997, PG&E became a subsidiary of PG&E Corporation. PG&E's ownership interest in PG&E Enterprises (Enterprises) and Pacific Gas Transmission Company (PGT) has been transferred to PG&E Corporation. PG&E's outstanding common stock was converted on a share-for- share basis into PG&E Corporation common stock. PG&E's debt securities and preferred stock were unaffected and remain securities of PG&E. The consolidated financial statements of PG&E incorporated herein include the accounts of PG&E and its wholly-owned and controlled subsidiaries (collectively, the Company), and, therefore, also represent the accounts of PG&E Corporation and its subsidiaries (also referred to collectively as, the Company). For financial information summarizing certain pro forma financial effects of the restructuring of PG&E, see "Formation of PG&E Corporation" below. The principal executive offices of PG&E Corporation and PG&E are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and their telephone number is (415) 973-7000. PG&E, incorporated in California in 1905, is an operating public utility engaged principally in the business of providing electric and natural gas services throughout most of Northern and Central California. As of December 31, 1996, the Company had $26.1 billion in assets. The Company generated $9.6 billion in operating revenues for 1996. As of December 31, 1996, the Company had approximately 22,000 employees. PG&E's gas and electric utility operations, which include Diablo Canyon Nuclear Power Plant (Diablo Canyon) operations, represent the principal component of its business, contributing $9.2 billion in revenues in 1996 (96% of the Company's total revenues). PG&E's utility operations contributed $1.83 of the Company's total 1996 earnings per share of $1.75. (Utility earnings were offset by losses at Enterprises.) 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. In 1996, Diablo Canyon contributed $1.8 billion of revenues (19% of the Company's total revenues) and $1.18 in earnings per share (67% of the Company's total 1996 earnings per share). PG&E has proposed a modification to existing Diablo Canyon ratemaking, which if adopted, would significantly reduce PG&E's future revenues from Diablo Canyon operations. See "Future Ratemaking--Electric Ratemaking" below. PG&E's utility service territory covers 70,000 square miles with an estimated population of approximately 13 million, and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, financial services, food processing, petroleum refining, agriculture, and tourism. At December 31, 1996, PG&E served approximately 4.5 million electric customers. PG&E serves its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, Diablo Canyon's two units, 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. (PG&E has announced plans to sell four fossil-fueled power plants, with an aggregate of 12 units, in connection with the ongoing electric industry restructuring. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below.) PG&E also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal, and cogeneration. In addition, PG&E is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling, and transmitting power. 1 PG&E served approximately 3.7 million gas customers at December 31, 1996. To ensure a diverse and competitive mix of natural gas supplies, PG&E purchases gas from both Canadian and United States suppliers. In 1996, about 65% of PG&E's gas supply came from fields in Canada, about 7% came from fields in California, and about 28% came from fields in other states (substantially all from the U.S. Southwest). PG&E's utility operations in 1996 also included PGT's gas pipeline operations. PGT owns and operates gas transmission pipelines and associated facilities capable of transporting approximately 2.4 billion cubic feet per day of natural gas over 612 miles from the Canada-U.S. border to the Oregon- California border, as well as two smaller diameter pipeline extensions within Oregon, totaling 106 miles. In 1996, PGT acquired the PGT Queensland Gas Pipeline, an approximately 389-mile 12-inch pipeline in Queensland, Australia, which provides natural gas transportation service to customers in the vicinity of the pipeline. As noted above, at present PGT is a wholly owned subsidiary of PG&E Corporation. Building on its expertise in the energy industry, PG&E Corporation is expanding its operations in the "midstream" portion of the gas business, the independent power generation business, and the energy services business. The midstream portion of the gas business includes gas gathering, processing, storage, and transportation. The energy services business includes obtaining gas and electricity from competitive producers, arranging for distribution and transmission service, and providing customized energy billing and analysis, power quality assessments, energy efficiency products and services, and facility improvements. Enterprises, through its subsidiaries and affiliates, develops, owns, and operates unregulated electric and gas projects both in and outside the United States. Vantus Energy Corporation (Vantus), a subsidiary of Enterprises, markets gas and electricity commodities and provides energy services. In 1996, Enterprises generated approximately $127 million in revenues and accounted for $(0.08) of the Company's total 1996 earnings per share of $1.75. As noted above, Enterprises is now a wholly owned subsidiary of PG&E Corporation. In December 1996, PGT acquired the gas marketing operations of Edisto Resources Corporation in the United States and Canada, known jointly as Energy Source, Inc. (ESI). The acquisition included most of ESI's existing contracts for the purchase, sale, and transportation of natural gas and natural gas futures. In January 1997, PG&E Corporation acquired Teco Pipeline Company (Teco) in Texas. Teco is an owner of a 500-mile natural gas pipeline system in Texas. Teco also has investments in gas gathering and processing facilities, and owns a gas marketing company in Houston, Texas. Also in January 1997, PG&E Corporation agreed to acquire Valero Natural Gas Company (Valero). Valero's operations include the gathering, transportation, marketing, and storage of natural gas, the processing, transportation, and marketing of natural gas liquids, and the marketing of electric power. Valero operates approximately 7,500 miles of natural gas pipeline and also owns and operates approximately 540 miles of natural gas liquid pipelines and eight natural gas processing plants in Texas. The acquisition is expected to be completed by mid-1997 and is subject to applicable regulatory and shareholder approvals. The following discussion of the Company's business includes some forward- looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," and similar expressions identify forward-looking statements involving risks and uncertainties. Those risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas industries and the outcome of regulatory proceedings related to that restructuring. The ultimate impacts of both increased competition and the changing regulatory environment on future results are uncertain, but are expected to fundamentally change how the Company conducts its business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by the Company. COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal 2 access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies are challenging the utilities' exclusive relationship with their customers and are seeking to replace certain utility functions with their own. Customers, too, are asking for choice in their energy provider. These pressures are causing a move from the existing regulatory framework to a framework under which competition would be allowed in certain segments of the gas and electric industries. For several years, PG&E has been working with its regulators to achieve an orderly transition to competition and to ensure that PG&E has an opportunity to recover investments made under traditional regulatory policies. In addition, PG&E has proposed alternative forms of regulation for those services for which prices and terms will not be determined by competition. These alternative forms include performance-based ratemaking (PBR) and other incentive-based alternatives. Over the next five years, a significant portion of PG&E's business will be transformed from the current utility monopoly to a competitive operation. This change will impact PG&E's financial results and may result in greater earnings volatility. During the transition period, PG&E expects the return on Diablo Canyon and certain other generation assets to be significantly lower than historical levels. ELECTRIC INDUSTRY In 1995, the California Public Utilities Commission (CPUC) issued a decision that provides a plan to restructure California's electric industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called competition transition costs, or CTCs, through a nonbypassable charge to be collected over a period of years. In 1996, legislation on electric industry restructuring, Assembly Bill 1890 (AB 1890), was signed into law in California. AB 1890 adopts the basic tenets of the CPUC's restructuring decision and establishes the operating framework for a competitive electric generation market. Key features of AB 1890 include: --mandatory unbundling of transmission, distribution, and generation services; --formation by January 1, 1998, of a California Power Exchange (PX) to provide a competitive auction process to establish the price of electricity; --establishing an Independent System Operator (ISO) to ensure system reliability and provide electric generators with open and comparable access to transmission and distribution services; --an electric rate freeze at 1996 levels until the earlier of March 31, 2002, or the point in time when PG&E has recovered its CTCs (the transition period); --a 10% rate reduction by January 1, 1998, for residential and small commercial customers, financed through "rate reduction bonds"; --nonbypassable charges to provide the opportunity for utilities to recover their CTCs and required accelerated recovery of CTCs associated with utility owned generation facilities; --direct access for all electric customers; --market valuation for utility owned fossil generation assets by 2001, followed by an end to cost-of-service ratemaking for most plants; and --continued support for renewable generation resources, conservation and other public purpose programs. Under AB 1890, PG&E and other utilities will continue to own transmission and distribution facilities and must continue to offer bundled electric service to customers who request it. 3 Recent regulatory changes enacted at the federal level are also changing the electric industry. In 1996, the Federal Energy Regulatory Commission (FERC) paved the way for the transition to more competitive electric markets by providing open access to electric transmission. See "Electric Utility Operations--Electric Transmission" below. Additional information concerning electric industry restructuring, the expected operating framework for a competitive generation market and the financial impact of these changes on the Company is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 29 of the 1996 Annual Report to Shareholders. GAS INDUSTRY Restructuring of the natural gas industry on both the national and state levels has given customers greater options in meeting their gas supply needs. PG&E's customers may buy commodity gas directly from competing suppliers and purchase transmission- and distribution-only services from PG&E. PG&E's transmission and distribution services have remained "bundled," or sold together at a combined rate, within California. PGT, as an interstate pipeline, has provided nondiscriminatory transmission-only service since 1993, and no longer sells commodity gas. Most of PG&E's industrial and larger commercial (noncore) customers purchase their commodity gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers continue to buy commodity gas as well as transmission and distribution from PG&E as a bundled service. In 1995 and 1996, PG&E actively pursued changes in the California gas industry in an effort to promote competition and increase options for all customers, as well as to position itself for the competitive marketplace. In 1996, PG&E submitted to the CPUC the Gas Accord Settlement (Gas Accord). The Gas Accord is the result of an extensive negotiation process, begun in 1995, among a broad coalition of customer groups and industry participants. The Gas Accord must be approved by the CPUC before it can be implemented. A CPUC decision is expected in 1997. The Gas Accord consists of three broad initiatives: --The Gas Accord would separate, or "unbundle," PG&E's gas transmission and storage services from its distribution services and would change the terms of service and rate structure for gas transportation. Unbundling would give customers the opportunity to select from a menu of services offered by PG&E and would enable them to pay only for the services they use. PG&E would be at risk for variations in revenues resulting from differences between actual and forecasted transmission throughput. PG&E would also continue to provide cost-of-service based distribution service, much as it does today. --The Gas Accord would increase opportunities for PG&E's core customers to purchase gas from competing suppliers and, therefore, could reduce PG&E's role in procuring gas for such customers. However, PG&E would continue to procure gas as a regulated utility supplier for those customers who request it. The Gas Accord also would establish principles for continuing negotiations between PG&E and California gas producers for the mutual release of supply contracts and the sale of gas gathering facilities. Also related to PG&E's procurement activities, PG&E has proposed that traditional reasonableness reviews of its core gas costs be replaced with a core procurement incentive mechanism (CPIM) for the period June 1, 1994, through 2002. See "Future Ratemaking--Gas Ratemaking" below. --The Gas Accord would resolve various regulatory issues including the recovery of certain capital costs associated with the PG&E portion (PG&E Expansion) of the PGT/PG&E Pipeline Expansion (Pipeline Expansion), recovery of costs related to PG&E's capacity commitments with Transwestern Pipeline Company (Transwestern) through 2002, certain disallowances ordered by the CPUC in connection with PG&E's 1988 through 1995 gas reasonableness proceedings, and the recovery, through the Interstate 4 Transition Cost Surcharge (ITCS), of fixed demand charges paid to El Paso Natural Gas Company (El Paso) and PGT for firm capacity held by PG&E on behalf of its customers. Additional information concerning gas industry restructuring, and the financial impact of these changes on the Company is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 31 of the 1996 Annual Report to Shareholders. REGULATION OF PG&E STATE REGULATION The CPUC consists of five members appointed by the governor and confirmed by the senate for six-year terms. The CPUC regulates PG&E's rates and conditions of service, sales of securities, dispositions of utility property, rate of return, rates of depreciation, uniform systems of accounts, examination of records, long-term resource procurement, and transactions between PG&E and its subsidiaries and affiliates. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition, and the environment, to determine its future policies. The California Energy Commission (CEC) has discretion over electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California. Beginning January 1, 1998, the CEC will also administer funding for public purpose research and development, and renewable technologies programs. The funding will be collected from ratepayers through a nonbypassable public benefits charge. See "Electric Utility Operations--Electric Industry Restructuring Legislation--Public Purpose Programs" below. FEDERAL REGULATION Both PG&E and PGT are subject to regulation by the FERC. The FERC regulates electric transmission rates and access, compliance with the uniform systems of accounts, and electric contracts involving sales for resale. The FERC also regulates the interstate transportation of natural gas. In addition, most of PG&E's hydroelectric facilities are subject to licenses issued by the FERC. The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities. NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities. LOCAL REGULATION PG&E has separate electric and gas franchises with the 48 counties and the 241 cities in its service territory. These franchises allow PG&E to locate facilities for the transmission and distribution of electricity and gas in the streets and other public ways. With few exceptions, the franchises do not have fixed terms and remain in effect as long as PG&E meets the terms and conditions of the franchises. PG&E is currently involved in litigation brought by several counties and cities who have granted franchises to PG&E. See Item 3, Legal Proceedings, "Counties Franchise Fees Litigation" and "Cities Franchise Fees Litigation" below for more information. LICENSES AND PERMITS PG&E obtains a number of permits, authorizations, and licenses in connection with the construction and operation of its generating plants. Discharge permits, various Air Pollution Control District permits, FERC hydroelectric facility licenses, and NRC licenses are the most significant examples. Some licenses and permits 5 may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements imposed by the granting agency. 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) on the basis that PG&E Corporation and PG&E are incorporated in the same state and their business is predominantly intrastate in character and carried on substantially in the state of incorporation. It is necessary for PG&E Corporation to file an annual exemption statement with the Securities and Exchange Commission (SEC), and the exemption may be revoked by the SEC upon a finding that the exemption may be detrimental to the public interest or the interest of investors or consumers. At present, PG&E Corporation has no intention 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 PG&E to form a holding company was granted subject to various conditions related to finance, human resources, record and book-keeping, and the transfer of customer information. The financial conditions provide that PG&E is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, PG&E's dividend policy shall continue to be established by PG&E's Board of Directors as though PG&E were a comparable stand-alone utility company, and the capital requirements of PG&E, as determined to be necessary to meet PG&E's service obligations, shall be given first priority by the Boards of Directors of PG&E Corporation and PG&E. The conditions also provide that PG&E shall maintain on average its CPUC- authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition in the event an adverse financial event reduces the utility's equity ratio by 1% or more. PG&E Corporation and PG&E have agreed to be subject to the conditions included in the CPUC approval. PG&E Corporation may also be subject to additional conditions based upon the outcome of an audit of affiliate transactions currently underway. The audit is being conducted by an outside consultant and supervised by the CPUC's Office of Ratepayer Advocates (ORA), formerly known as the Division of Ratepayer Advocates. Other regulatory matters are described throughout this report. RATE MATTERS CALIFORNIA RATEMAKING MECHANISMS The principal ratemaking mechanisms currently applied by the CPUC in setting PG&E's revenue requirements are described below. It is expected that many of these mechanisms may be changed significantly or eliminated as both the electric and gas utility industries are restructured and regulatory reforms proposed by PG&E and government authorities are implemented. See "Future Ratemaking" below. PG&E's utility operations, other than Diablo Canyon, are regulated primarily under the traditional cost-based approach to ratemaking. In 1996, Diablo Canyon operations were regulated under a performance-based approach under which revenues for the plant are based primarily on the amount of electricity generated, rather than on the costs associated with the plant's operations. However, PG&E has proposed a significant modification to Diablo Canyon ratemaking. See "Electric Utility Operations--Diablo Canyon--Diablo Settlement" below. PG&E's basic business and operational costs for its utility operations, other than Diablo Canyon, are recovered through base revenues. Base revenues are intended to recover operation and maintenance expenses (excluding fuel expenses, fuel-related energy costs, and purchased power costs), depreciation expense, taxes, and return on invested capital. Base revenue requirements are currently set in general rate case (GRC) proceedings 6 held before the CPUC every three years. (PG&E's current base revenues were set in the 1996 GRC; its next scheduled GRC would establish base revenue requirements effective January 1, 1999.) During a GRC, the CPUC critically reviews PG&E's operations and general costs to provide service (excluding energy costs and, in certain instances, major plant additions), and then determines the revenue requirement to cover those costs. The revenue requirement is forecasted on the basis of a specified test year. (The return component of PG&E's revenue requirement is computed using the overall cost of capital authorized by the CPUC in the annual Cost of Capital consolidated proceeding, in which financing costs are reviewed and capital structures for all California energy utilities are adopted.) Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase, which allocates revenue requirements and establishes rate levels for the different classes of customers. The Electric Revenue Adjustment Mechanism (ERAM) allows rate adjustments to offset the effect on base revenues of differences between actual electric sales volumes and the forecasted volumes used to set rates in the last GRC. The ERAM eliminates the impact on earnings of sales fluctuations, including those resulting from conservation and weather conditions. Base revenue differences resulting from the disparity between actual and forecasted electric sales accumulate in a balancing account, with interest. ERAM rate adjustments are made as part of the Energy Cost Adjustment Clause (ECAC) proceeding described below. Most of PG&E's fuel, purchased-power, and energy-related costs of providing electric service, as well as revenues attributable to Diablo Canyon generation, are recovered through a balancing account mechanism called the ECAC. Under the ECAC balancing account procedure, actual costs are compared with revenues designated for recovery of such costs, and the difference is recorded as either an undercollection or overcollection. The differential between forecasted Diablo Canyon revenues under the Diablo Canyon rate case settlement (Diablo Settlement) and actual revenues also is tracked in the ECAC balancing account. In prior years, rates would be adjusted such that the amount of overcollections would be returned to ratepayers through lower rates and undercollections would be recovered through higher rates. However, as part of the electric industry restructuring, PG&E's electric rates have been frozen at 1996 levels, and the recorded overcollection in PG&E's ECAC/ERAM balancing accounts, if any, as of December 31, 1996, will be applied to offset PG&E's CTCs. See "1997 Revenues" below. The disposition of 1997 balancing accounts is being addressed at the CPUC in connection with electric industry restructuring. PG&E has proposed to recover 1997 year end balancing account balances through the CTC ratemaking mechanism. The Annual Energy Rate (AER) mechanism has provided for recovery of 9% of forecasted electric fuel and fuel-related costs, without balancing account protection for differences between actual and forecasted costs. However, the AER was indefinitely suspended by the CPUC in a December 1996 decision. In December 1996, the CPUC issued a decision establishing an electric deferred refund account (EDRA). The CPUC ordered PG&E to place into the EDRA credits for CPUC-ordered electric disallowances, the utility electric generation share of CPUC-ordered gas disallowances, electric and utility electric generation gas settlement amounts resulting from reasonableness disputes and fuel-related cost refunds made to PG&E based on regulatory agency decisions, plus interest charges. The CPUC ordered PG&E to file advice letters by January 31 of each year, setting forth its annual refund plans for directly refunding to electric customers the dollars accumulated in the EDRA. The CPUC also ordered PG&E to include initially in the EDRA any such credits which were already recorded in the ECAC and ERAM but had not yet been amortized in rates. The effect of this is to reduce the amount available to offset PG&E's CTCs by approximately $75 million. PG&E is seeking rehearing of this decision at the CPUC. PG&E is also seeking an injunction in federal court to block the refund of $50 million of the initial EDRA amount pending resolution of PG&E's lawsuit challenging the disallowance order issued in PG&E's 1988-1990 gas reasonableness proceeding that gave rise to that portion of the initial EDRA amount. Fuel and fuel-related costs included in an ECAC adjustment are subject to a subsequent reasonableness review, in which the CPUC determines whether those costs were reasonably incurred. Costs found to be unreasonable may be disallowed, or deducted, from the amount to be recovered in rates. Currently, the amount of Diablo Canyon revenues recovered through the ECAC is determined under the Diablo Settlement and is not subject to reasonableness review. See "Electric Utility Operations--Diablo Canyon--Diablo Settlement" below. 7 The Biennial Cost Allocation Proceeding (BCAP) is the major rate proceeding for PG&E's natural gas service, other than service on the PG&E Expansion which is addressed in a separate proceeding. Rates to recover the cost of gas procured for customers who buy gas from PG&E and the cost of providing gas transportation service for gas customers are determined in the BCAP. The BCAP normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. Balancing accounts for natural gas costs and sales volumes are similar to those for electric fuel costs and sales volumes. In addition to adopting the gas revenue requirements in the BCAP, the CPUC also allocates both the gas fuel and transportation revenue requirements among core and noncore classes and among the customer groups within those classes. The BCAP also includes the rate design process, in which it is determined how specific costs are recovered from customers, with rates set accordingly. 1997 REVENUES Cost Recovery Plan. In December 1996, the CPUC approved the cost recovery plan filed by PG&E in compliance with AB 1890. The provisions of the plan approved by the CPUC include a freeze of electric rates at 1996 levels beginning on January 1, 1997, and pursuant to the provisions of AB 1890, an increase in PG&E's electric base revenues for 1997 of approximately $164 million to be used to enhance transmission and distribution system safety and reliability. In January 1997, The Utility Reform Network (TURN) filed an application for rehearing of the CPUC's decision. TURN's application for rehearing argues that the CPUC exceeded its authority in interpreting AB 1890 to authorize a base revenue increase for PG&E, and that the CPUC's decision requires clarification to ensure that any such base revenue increase as is granted is used only to fund activities which are supplemental to those funded in the most recent GRC. PG&E believes it is entitled to the base revenue increase provided for in AB 1890. However, if the CPUC were to find that those funds were not properly used to supplement PG&E's system safety and reliability expenditures, the CPUC might order disallowances that could negatively impact 1997 earnings. ECAC. In December 1996, the CPUC issued a decision in PG&E's ECAC proceeding, authorizing a decrease in electric revenue requirements of approximately $720 million. The three elements of this decrease are: (1) a reduction in ECAC revenues of approximately $565 million; (2) a reduction in ERAM revenues of approximately $153 million; and (3) an increase in the California Alternate Rates for Energy (CARE) program, which supports energy rate discounts for low income customers, of approximately $2 million. This net reduction of approximately $720 million is partially offset by an electric revenue requirement increase of approximately $164 million resulting from the consolidation of revenue changes from the ERAM component of other proceedings, the base revenue increase authorized by AB 1890 and included in PG&E's cost recovery plan, the Cost of Capital proceeding, and the Annual Energy Assessment Proceeding (AEAP), which sets rate adjustments resulting from shareholder incentives earned on demand side management (DSM), or energy efficiency, programs. The ECAC decision also indefinitely suspends the AER mechanism, which had placed PG&E at partial risk for variations between actual and forecasted electric energy costs. Cost of Capital. The CPUC's decision in the 1997 Cost of Capital proceeding authorized a utility return on common equity of 11.60%, a continuation of the 1996 level. The decision authorizes a utility capital structure for PG&E of 48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. The combined authorized costs of debt, preferred stock, and the 11.60% return on common equity result in an overall return on utility rate base (excluding Diablo Canyon and the PG&E Expansion) of 9.45%, a decrease from the 9.49% authorized for 1996. (However, actual returns for 1997 are expected to be substantially less than authorized levels as a result of the electric industry restructuring. See "Future Ratemaking--Electric Ratemaking" below.) Also as part of the Cost of Capital decision, the CPUC set the authorized return on equity and capital structure for the PG&E Expansion. See "Gas Utility Operations--PGT/PG&E Pipeline Expansion--CPUC Ratemaking" below. BCAP. The CPUC's December 1995 decision in PG&E's last BCAP authorized an increase of approximately $60 million in annual gas revenues beginning January 1, 1996. In November 1996, PG&E submitted an interim filing, as permitted under the BCAP mechanism to set new rates for the second year of the 8 two-year BCAP period. If approved by the CPUC, the filing would result in an approximately $17 million increase in total gas revenues effective upon CPUC approval, which is not reflected in the table below. AEAP. The CPUC's December 1996 decision in the annual AEAP, which determines shareholder incentives earned for PG&E's DSM programs, adopted an incentive payment of approximately $72 million for PG&E's 1995 programs, to be collected in installments over a 10-year period. After consolidating incentive payment installments from prior years, the net revenue change in 1997 from DSM shareholder incentives is an electric increase of approximately $9 million and a gas decrease of approximately $2 million. The consolidated effect of these decisions on authorized revenue requirements for 1997 is indicated in the table below: SUMMARY OF RATE CASE DECISIONS EFFECTIVE AS OF JANUARY 1, 1997 (IN MILLIONS)
ELECTRIC GAS TOTAL -------- --- ----- ECAC/ERAM/CARE/AER......................................... $(720) $-- $(720) AB 1890 base revenue increase.............................. 164 -- 164 1997 Cost of Capital....................................... (5) (2) (7) ERAM in other proceedings.................................. (4) -- (4) BCAP....................................................... -- -- -- AEAP....................................................... 9 (2) 7 ----- --- ----- Total Change in Authorized Revenue Requirement from 1996 Levels........................................... $(556) $(4) $(560) ===== === =====
Pursuant to PG&E's cost recovery plan and AB 1890, electric rates will not be changed from 1996 levels. Instead, the consolidated net reduction in electric revenue requirements of approximately $556 million will be available to offset PG&E's CTCs and any increase in revenue requirements resulting from PG&E's proposed cost recovery plan. FUTURE RATEMAKING Although it is clear that ratemaking for both electric and gas utilities in California will be significantly different in the future as a result of the ongoing restructuring in both industries, many of the specifics concerning how rates will be set, adjusted, and billed after 1997 remain to be resolved by the relevant regulatory authorities, utilities, and other interested parties. Outlined below are the more significant regulatory rulings to date on this issue, and some of the proposals made by PG&E in connection with changes to ratemaking in the new restructured markets. ELECTRIC RATEMAKING In December 1996, the CPUC issued a "roadmap" decision outlining the necessary steps to accomplish electric industry restructuring and commence the transition period no later than January 1, 1998. In that decision, the CPUC notes that ratemaking has not changed in that the CPUC will still determine the rate components, revenue allocation, and rate design necessary to derive a rate for each customer class. However, the CPUC recognizes that the process must be revised to accommodate changes in the electric industry necessary for implementation of AB 1890 and the new market structure beginning in 1998. A consideration of necessary changes includes unbundling of rates, transition costs, PBR, and other activities that affect rates and revenue requirements. In its roadmap decision, the CPUC establishes a separate annual proceeding to consider ratemaking issues related to each electric utility's revenues, which will consolidate all pending revenue changes and track utility revenues at present rate levels for the purpose of comparison with authorized amounts. This annual Revenue Adjustment Proceeding (RAP) will be designed to annually review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and to make any necessary adjustments or 9 updates due to authorized revenues from PBR mechanisms and other proceedings, or revenues for various power purchase contracts, public purpose programs, nuclear facilities, nuclear decommissioning, and transition costs. The differential between actual recorded revenues and the consolidated authorized revenue requirement will be applied to recover CTCs. The authorized revenues will be established in their respective proceedings and consolidated into the RAP. The first RAP will begin in 1998. PG&E has filed numerous regulatory applications and proposals that detail its cost recovery plan during the transition period. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of- service revenue requirement for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) accelerated recovery of transition costs, and (3) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period. PG&E's unbundling application, filed in December 1996, proposes to unbundle PG&E's revenue requirements, enabling it to separate revenues provided by frozen rates into transmission, distribution, PPPs, and generation. As proposed, revenues collected under frozen rates would be assigned to transmission, distribution, and PPPs, based upon their respective cost of service. Revenue would also be provided for other costs, including nuclear decommissioning, rate-reduction-bond debt service, the ongoing cost of generation, and CTC recovery. The combination of a rate freeze and decreasing costs, based upon existing ratemaking and cost recovery periods, provides an adequate amount of revenue available for full CTC recovery. PG&E's unbundling application also presents a method to separate electric rates into the four functional cost categories of PPPs, distribution, transmission, and generation (including energy costs based on the PX price, and CTCs, determined after all other costs are accounted for), effective January 1, 1998. Bills for all customers would describe what portion of the bill is attributable to transmission, distribution, PPPs, energy, and CTCs and other nonbypassable charges. PG&E's unbundling application also proposes to replace the ECAC and ERAM during the transition period with a single balancing account, the Transition Revenue Account (TRA). The TRA would be functionally equivalent to the current system in that it would match revenues with cost components. With the TRA, CTC would be the only cost component for which recovery during the transition period would be affected by any variation in billed revenues due to sales fluctuations. PG&E has proposed to accelerate recovery for certain CTCs related to generation facilities, including Diablo Canyon. Additionally, PG&E would receive a reduced return on common equity associated with generation plant assets for which recovery is accelerated. The lower return is intended to reflect reduced risk associated with the shorter amortization period and increased certainty of recovery. In applying its cost recovery plan to Diablo Canyon, PG&E has proposed a significant modification to the existing Diablo Canyon ratemaking. Under the current Diablo Settlement, Diablo Canyon revenues are based on a pre- established price per kWh of plant generation. PG&E proposes to replace the existing settlement price with: (1) a sunk cost revenue requirement to recover fixed costs, including a return on those fixed costs, and (2) a PBR mechanism to recover the facility's variable costs and capital addition costs. As proposed, the sunk cost revenue requirement would accelerate recovery of Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five- year period beginning in 1997 and ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90% of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52% in 1996. The reduced rate of return combined with a shorter recovery period would result in an estimated $4.0 billion decrease in the net present value of PG&E's future revenues from Diablo Canyon operations. If the proposed cost recovery plan for Diablo Canyon had been adopted during 1996, Diablo Canyon's 1996 reported net income would have been reduced by $350 million ($0.85 per share). The assigned CPUC administrative law judge (ALJ) has issued a proposed decision on PG&E's proposal to modify existing Diablo Canyon ratemaking. With significant exceptions, the proposed decision generally adopts the overall ratemaking structure proposed by PG&E, but would substantially alter the proposed ICIP mechanism and would exclude certain items from the sunk cost revenue requirement. See "Electric Utility Operations--Diablo Canyon--Diablo Settlement" below for more information regarding PG&E's proposed modification and the proposed decision issued by the ALJ. The proposed decision is not a final decision of the CPUC, and is subject 10 to change prior to a vote of the full CPUC. The proposed decision currently is scheduled for consideration by the full CPUC at its April 9, 1997 meeting. PG&E has proposed a PBR mechanism for recovery of its hydroelectric and geothermal generating unit costs. The proposed mechanism consists of a base revenue amount that is adjusted to account for inflation less a productivity offset. In its unbundling application, PG&E proposed a starting point for the hydroelectric/geothermal generation PBR at approximately $545 million in 1998. Under the AB 1890 cost recovery plan submitted by PG&E and approved by the CPUC, the difference between the authorized revenue requirement for these units and revenues earned at PX prices would be credited against CTC recovery if, as currently expected, the revenues earned at market prices exceed the cost of operating these facilities as set under the PBR mechanism. Additional information concerning the Company's transition cost recovery plan, the financial impact of electric industry restructuring and these various proposals is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Notes 2 and 4 of the "Notes to Consolidated Financial Statements" beginning on pages 29 and 32, respectively, of the 1996 Annual Report to Shareholders. GAS RATEMAKING As noted above (see "Competition and the Changing Regulatory Environment-- Gas Industry" above), PG&E has submitted to the CPUC the Gas Accord, which would offer increased customer choice, establish gas transmission rates for the period July 1997 through December 2002, and resolve various pending regulatory issues. The Gas Accord must be approved by the CPUC before it can be implemented. Among other things, the Gas Accord would unbundle PG&E's gas transmission and storage services from its distribution services and would change the terms of service and rate structure for gas transportation. Unbundling would give customers the opportunity to select from a menu of services offered by PG&E and would enable them to pay only for the services they use. PG&E would be at risk for variations in revenues resulting from differences between actual and forecasted transmission throughput. PG&E would continue to provide cost-of-service based distribution service, much as it does today. Additional information concerning the potential financial impact of the Gas Accord is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 31 of the 1996 Annual Report to Shareholders. As part of the Gas Accord, PG&E has proposed that traditional reasonableness reviews of its core gas costs be replaced with a CPIM for the period June 1, 1994, through 2002. Under the CPIM, PG&E would be able to recover its gas commodity and interstate transportation costs and would receive benefits or be penalized depending on whether its actual core procurement costs were within, below, or above a "tolerance band" constructed around market benchmarks. Actual core procurement costs measured for the period June 1, 1994, through December 31, 1996, have generally been within the CPIM "tolerance band." The CPIM proposal also requests authorization to use derivative financial instruments to reduce the risk of gas price and foreign currency fluctuations. Gains, losses, and transaction costs associated with the use of derivative financial instruments would be included in the purchased gas account and the measurement against the benchmarks. CAPITAL REQUIREMENTS AND FINANCING PROGRAMS PG&E and PGT continue to require capital for improvements to facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. PG&E's and PGT's expenditures for these purposes, including the allowance for funds used during construction (AFUDC), were approximately $1,244 million for 1996. New investments totaled $159 million in 1996. 11 The following table sets forth PG&E Corporation's estimated total capital requirements, consisting of capital expenditures for PG&E's utility functions, including Diablo Canyon, as well as capital requirements for PGT and diversified operations and amounts for maturing debt and sinking funds for the years 1997 through 1999. These are forward-looking statements which involve a number of assumptions and uncertainties. Actual amounts may differ materially from the estimated amounts shown below. PG&E CORPORATION CAPITAL REQUIREMENTS (IN MILLIONS)
1997 1998 1999 TOTAL ---- ---- ---- ----- Utility(1)......................................... $1,773 $1,825 $1,705 $5,303 Diablo Canyon...................................... 38 39 41 118 Diversified Operations(2) U.S. Generating Company(3)........................ 160 57 169 386 Other(4).......................................... 51 23 3 77 ------ ------ ------ ------ Total Capital Expenditures....................... 2,022 1,944 1,918 5,884 Maturing Debt and Sinking Funds.................... 210 660 270 1,140 ------ ------ ------ ------ Total Capital Requirements....................... $2,232 $2,604 $2,188 $7,024 ====== ====== ====== ======
- -------- (1) Utility expenditures include PG&E's electric and gas operations and PGT's gas pipeline operations, are shown net of reimbursed capital, and include AFUDC. (2) Actual capital expenditures may vary significantly depending on the availability of attractive investment opportunities. PG&E has announced an agreement to sell its interest in International Generating Company, Ltd. in 1997 and capital requirements for that company are not included in the table. (3) U.S. Generating Company expenditures include commitments by PG&E Corporation, PG&E, and/or Enterprises to make capital contributions for Enterprises' equity share of currently identified generating facility projects. These contributions, payable upon commercial operation of the projects, are estimated to be $52 million and $15 million in 1997 and 1998, respectively. (4) Other expenditures include ongoing capital requirements for ESI and Teco. Most of Utility and Diablo Canyon capital expenditures for 1997 through 1999 are associated with short lead time, modest capital expenditure projects aimed at the replacement and enhancement of existing facilities, and compliance with environmental laws and regulations. Also included are expenditures to improve the safety and reliability of PG&E's electric transmission and distribution system consistent with AB 1890, as well as major projects associated with customer service improvements. PG&E Corporation estimates that its total capital requirements for the years 1997 through 1999 will include approximately $1,140 million for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt, as indicated above. The funds necessary for 1997-1999 capital requirements of PG&E Corporation and its subsidiaries will be obtained from (i) internal sources, principally net income before noncash charges for depreciation and deferred income taxes, and (ii) external sources, including short-term financing, such as bank loans and the sale of short-term notes, and long-term financing, such as sales of equity and long-term debt securities, when and as required. PG&E Corporation and its subsidiaries and affiliates conduct a continuing review of their capital expenditures and financing programs. The programs and estimates above are subject to revision and actual amounts may vary based upon changes in assumptions as to system load growth, rates of inflation, receipt of adequate and timely rate relief, availability and timing of regulatory approvals, total cost of major projects, availability and cost of suitable nonregulated investments, and availability and cost of external sources of capital, as well as the outcome of the ongoing restructuring in both the electric and gas industries. 12 In January 1997, PG&E Corporation acquired Teco and its subsidiaries for approximately $380 million, consisting of the purchase of a $61 million note, and $319 million of PG&E Corporation common stock. Also in January 1997, PG&E Corporation agreed to acquire Valero for approximately $1.5 billion, consisting of approximately $720 million of PG&E Corporation common stock and the assumption of debt and liabilities. The cost of these acquisitions is not included in the table above, nor are estimates of expected ongoing capital requirements for Valero. RISK MANAGEMENT PROGRAMS Due to the changing business environment, the Company's exposure to risks associated with changes in energy commodity prices, interest rates, and foreign currencies is increasing. To manage these risks, the Company has adopted a price risk management policy and established an officer-level price risk management committee. The Company's price risk management committee oversees implementation of the policy, approves each price risk management program, and monitors compliance with the policy. The Company's price risk management policy and procedures adopted by the committee establish guidelines for implementation of price risk management programs. Such programs may include the use of energy and financial derivatives. (A derivative is a contract whose value is dependent on or derived from the value of some underlying asset.) Additionally, the Company's policy allows derivatives to be used for hedging and non-hedging purposes. (Hedging is the process of protecting one transaction by means of another to reduce price risk.) Both hedging and non-hedging activities are limited to those specifically approved by the committee only after appropriate controls and procedures are put in place to measure, monitor, and control the risk of such activities. The Company's policy prohibits the use of derivatives whose payment formula includes a multiple of some underlying asset. In 1996, the Company approved and implemented interest rate and foreign exchange risk management programs, applied for regulatory approval to use energy derivatives to manage commodity price risk in its utility business, and acquired certain natural gas marketing operations which engage in both hedging and non-hedging derivative transactions. Gains and losses associated with price risk management activities during 1996 were immaterial. Additional information concerning the Company's risk management activities is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 18, and in Note 1 of the "Notes to Consolidated Financial Statements" on page 28 of the 1996 Annual Report to Shareholders. 13 ELECTRIC UTILITY OPERATIONS ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION In 1996, comprehensive legislation on electric industry restructuring, in the form of AB 1890, was signed into law in California. AB 1890 adopted the basic tenets of the CPUC's 1995 restructuring decision and provides guidance to the CPUC on a number of implementation issues. Although many details remain to be worked out, implementation of AB 1890 will have a significant impact on PG&E's electric utility operations beginning as early as 1998. Major provisions of AB 1890 include the following: INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE AB 1890 requires the CPUC to facilitate the development of an ISO and a PX, and establishes a five-member Oversight Board to oversee the ISO and PX and appoint the members of the ISO and PX Governing Boards. The ISO and PX Governing Boards will include representatives of investor owned utility transmission owners, publicly owned utility transmission owners, nonutility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives. In a November 1996 order approving in concept the proposed ISO/PX framework, the FERC limited the ongoing role of the Oversight Board and eliminated the requirement of AB 1890 that members of the Oversight Board be residents of California. Under AB 1890, it is intended that both California's investor owned utilities and its publicly owned utilities commit control of their transmission facilities to the ISO. The ISO is required to ensure reliable transmission services consistent with planning and operating reserve criteria no less stringent than those established by the Western Systems Coordinating Council and the North American Electric Reliability Council. Oversight responsibility for reliability of utility distribution systems remains with the CPUC. To prevent undue influence on the PX price by any participant in the competitive framework, PG&E has indicated that it is willing to proceed with voluntary divestiture of at least 50% of its fossil-fueled power plants as directed by the CPUC. PG&E has filed an application seeking approval from the CPUC to sell four plants (comprised of 12 units) before the end of 1997. The book value for these plants is approximately $400 million, and together they generate approximately 10% of PG&E's total electric sales. PG&E proposes to recover any shortfall in proceeds from divestitures of these plants as CTCs. DIRECT ACCESS AB 1890 authorizes direct transactions between electricity suppliers and customers, beginning January 1, 1998, and on a phased-in schedule, if justified by technical considerations, through December 31, 2001, that is equitable to all customer classes. Aggregation of customer electrical load for such direct transactions is authorized. RATE LEVELS AND RECOVERY OF CTCS AB 1890 provides for a 10% rate reduction for residential and small commercial electric customers, freezes electric customer rates for all other customers, and requires the accelerated recovery of CTCs associated with utility owned generation facilities. The rate freeze will continue until the end of the transition period, which extends to the earlier of March 31, 2002, or until PG&E has recovered its CTCs. The freeze will hold rates at 1996 levels for all customers except those receiving the 10% rate reduction. The rate freeze will hold the rates for these customers at the reduced level. To achieve the 10% rate reduction, AB 1890 authorizes utilities to finance a portion of their CTCs with "rate reduction bonds." PG&E expects to work with state authorities to coordinate the issuance of up to 14 $2.5 billion of these bonds by a special purpose entity. The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current cost of capital. Once the bonds are issued, PG&E would collect, on behalf of the special purpose entity, a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs will lower the amounts paid by these customers each year during the transition period thereby achieving the 10% reduction in rates. PG&E does not expect to secure the bonds with the Company's assets or unrelated future revenues. AB 1890 authorizes utilities to recover transition costs, or CTCs (the uneconomic costs of their generation-related assets and obligations, including regulatory assets and the costs associated with nuclear ratemaking settlements such as the Diablo Settlement), from all customers (with certain exceptions) through a nonbypassable charge included as part of rates over the period ending December 31, 2001. Recovery may extend beyond December 31, 2001, for certain CTCs, such as certain employee-related transition costs (recoverable through December 31, 2006) and costs resulting from implementation of direct access and creation of the PX and ISO, and above market costs associated with power purchase agreements. As a prerequisite to any consumer obtaining direct access services, the consumer must agree to pay its applicable nonbypassable CTC charge. CTCs associated with utility owned fossil generation would be limited to regulatory assets and the uneconomic net book value of the fossil capital investment as of January 1, 1998, plus the costs of capital additions subsequent to December 20, 1995, that the CPUC determines are reasonable and, in the case of fossil plant additions, are necessary to maintain the facilities through December 31, 2001. CTCs associated with utility owned generation-related costs not recovered during the transition period will be absorbed by PG&E. Operating costs for such facilities would generally be recoverable through market-based rates, excluding facilities that are required to be operated for reliability purposes by the ISO. Operating costs for those facilities would be recovered on a cost-of-service basis through ISO contracts. CTCs associated with existing power purchase contracts, such as those for purchases from qualifying facilities (QFs), also would be recoverable through nonbypassable rates, except that the recovery period would be over the duration of the contract or any restructuring thereof. Nuclear decommissioning costs would continue to be recovered through a nonbypassable charge separate from CTCs until fully recovered. Recovery of nuclear decommissioning costs may be accelerated. BASE REVENUE INCREASES AB 1890 provides for annual increases in base revenues for PG&E, effective in 1997 and 1998, equal to the inflation rate for the prior year plus two percentage points. Given the rate freeze, the base revenue increase would reduce the amount available for CTC recovery. The increases will remain in effect pending PG&E's next GRC, which will set rates effective January 1999. The base revenue increases must be used for enhancing transmission and distribution system safety and reliability, and any such revenues not expended for such purposes must be credited against subsequent safety and reliability revenue requirements in future years. In December 1996, the CPUC approved the cost recovery plan filed by PG&E in compliance with AB 1890, which included an increase in PG&E's electric base revenues for 1997 of approximately $164 million to be used to enhance transmission and distribution system safety and reliability as contemplated by AB 1890. TURN has filed an application for rehearing of the CPUC's decision, challenging the base revenue increase. See "General--Rate Matters--1997 Revenues" above. PUBLIC PURPOSE PROGRAMS Under AB 1890, energy efficiency, research and development, and low income programs will be funded in electric rates pursuant to a separate, nonbypassable charge at current levels from January 1, 1998, through December 31, 2001. Under this provision, PG&E is obligated to fund through electric rates energy efficiency and conservation programs at not less than $106 million per year, research and development programs at not less than $30 million per year, and renewable technologies at not less than $48 million per year. 15 In February 1997, the CPUC adopted a decision that changes the way these programs will be administered, beginning after 1997. Currently, PG&E and other utilities administer public purpose programs for energy efficiency and conservation, research and development and low income customer assistance. Under the CPUC's decision, the CPUC will appoint independent boards to oversee energy efficiency and low income assistance programs. These boards will solicit competitive bids to determine who will administer the programs from January 1, 1998, through 2001. PG&E or an affiliate will be permitted to bid for administration of the energy efficiency programs. The decision also turns over administration of the funding for research and development, and renewable technologies programs to the CEC, beginning January 1, 1998. Additional information concerning AB 1890 and its financial impact on the Company is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 29 of the 1996 Annual Report to Shareholders. 16 ELECTRIC OPERATING STATISTICS The following table shows PG&E's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31 -------------------------------------------------------- 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- CUSTOMERS (AVERAGE FOR THE YEAR): Residential.............. 3,874,223 3,825,413 3,788,044 3,748,831 3,708,374 Commercial............... 459,001 454,718 452,049 449,619 455,480 Industrial............... 1,248 1,253 1,260 1,243 1,207 Agricultural............. 87,250 88,546 90,520 91,376 94,562 Public street and highway lighting................ 17,583 17,089 16,709 16,096 15,681 Other electric utilities. 28 35 29 28 24 ---------- ---------- ---------- ---------- ---------- Total.................. 4,439,333 4,387,054 4,348,611 4,307,193 4,275,328 ========== ========== ========== ========== ========== GENERATED, RECEIVED AND SOLD -- KWH (IN MILLIONS): Generated: Hydroelectric plants..... 15,158 16,608 7,791 14,403 7,537 Thermal-electric plants: Fossil fueled........... 11,620 13,729 29,543 19,070 26,623 Geothermal.............. 4,514 4,001 6,024 6,491 7,007 Nuclear................. 16,720 16,269 15,265 16,816 16,698 ---------- ---------- ---------- ---------- ---------- Total thermal-electric plants................ 32,854 33,999 50,832 42,377 50,328 Wind and solar plants.... 2 1 1 -- -- Received from other sources(1).............. 57,134 54,935 47,199 48,859 46,243 ---------- ---------- ---------- ---------- ---------- Total gross system output(2)............. 105,148 105,543 105,823 105,639 104,108 Delivered for interchange or exchange............. 4,000 4,261 3,275 8,848 3,912 Delivered for the account of others(1)............ 19,356 18,946 18,622 13,726 17,235 Helms pumpback energy(3). 898 937 467 452 398 PG&E use, losses, etc.(4)................. 6,500 6,040 7,838 6,960 7,278 ---------- ---------- ---------- ---------- ---------- Total energy sold...... 74,394 75,359 75,621 75,653 75,285 ========== ========== ========== ========== ========== POWER PLANT FUEL SUPPLY (IN THOUSANDS): Natural gas (equivalent barrels)................ 20,193 23,143 44,119 28,791 43,446 Fuel oil................. 686 756 2,395 2,080 171 Nuclear (equivalent barrels)................ 28,574 27,814 26,135 28,724 28,540 ---------- ---------- ---------- ---------- ---------- Total.................. 49,453 51,713 72,649 59,595 72,157 ========== ========== ========== ========== ========== POWER PLANT FUEL COSTS (AVERAGE COST PER MILLION BTU'S): Natural gas.............. $ 1.83 $ 2.06 $ 2.19 $ 2.86 $ 2.61 Fuel oil................. $ 2.66 $ 1.28 $ 2.83 $ 3.49 $ 3.13 Weighted average......... $ 1.92 $ 2.03 $ 2.23 $ 2.90 $ 2.62 SALES -- KWH (IN MILLIONS): Residential.............. 25,458 24,391 24,326 24,111 23,664 Commercial............... 27,868 27,014 26,195 26,258 26,246 Industrial............... 15,786 16,879 16,010 16,492 16,600 Agricultural............. 3,631 3,478 4,426 3,672 4,741 Public street and highway lighting................ 438 425 418 419 400 Other electric utilities. 1,213 3,172 4,246 4,701 3,634 ---------- ---------- ---------- ---------- ---------- Total energy sold...... 74,394 75,359 75,621 75,653 75,285 ========== ========== ========== ========== ========== REVENUES (IN THOUSANDS): Residential.............. $3,033,613 $2,979,590 $2,980,966 $2,952,893 $2,790,605 Commercial............... 2,840,101 2,964,568 2,892,302 2,914,855 2,864,817 Industrial............... 1,005,694 1,160,938 1,128,561 1,183,728 1,210,754 Agricultural............. 396,469 395,531 477,330 419,628 478,941 Public street and highway lighting................ 55,372 56,154 55,545 55,976 53,133 Other electric utilities. 81,855 133,566 201,133 242,433 185,555 ---------- ---------- ---------- ---------- ---------- Revenues from energy sales................. 7,413,104 7,690,347 7,735,837 7,769,513 7,583,805 Miscellaneous............ 112,303 92,538 142,771 87,991 51,716 Regulatory balancing accounts................ (365,192) (396,578) 142,939 19,421 127,490 ---------- ---------- ---------- ---------- ---------- Operating revenues..... $7,160,215 $7,386,307 $8,021,547 $7,876,925 $7,763,011 ========== ========== ========== ========== ==========
- -------- (1) Includes energy supplied through PG&E's system by the City and County of San Francisco for San Francisco's own use and for sale by San Francisco to its customers, by the Department of Energy for government use and sale to its customers, and by the State of California for California Water Project pumping, as well as energy supplied by QFs and purchases from other utilities. (2) Includes energy output from Modesto and Turlock Irrigation Districts' own resources. (3) Represents energy required for pumping operations. (4) Includes use by business units other than the electric utility business units. 17
YEARS ENDED DECEMBER 31 ------------------------------------------------- 1996 1995 1994 1993 1992 --------- --------- --------- --------- --------- SELECTED STATISTICS: Total customers (at year- end)....................... 4,500,000 4,400,000 4,400,000 4,400,000 4,300,000 Average annual residential usage (kWh)................ 6,571 6,377 6,422 6,431 6,381 Average billed revenues per kWh (cents): Residential................ 11.92 12.22 12.25 12.25 11.79 Commercial................. 10.19 10.97 11.04 11.10 10.92 Industrial................. 6.37 6.88 7.05 7.18 7.29 Agricultural............... 10.92 11.37 10.78 11.43 10.10 Net plant investment per customer ($)............... 3,198 3,228 3,362 3,436 3,428 Electric control area capability(megawatts)(1)... 22,724 22,099 21,851 23,009 22,475 Electric net control area peak demand(megawatts)(2).. 21,437 20,317 19,118 19,607 18,594
- -------- (1) Area net capability at time of annual peak, based on actual water conditions. (2) Net control area peak demand includes demand served by Modesto and Turlock Irrigation Districts' own resources. ELECTRIC GENERATING AND TRANSMISSION CAPACITY As of December 31, 1996, PG&E owned and operated the following generating plants, all located in California, listed by energy source:
NET OPERATING NUMBER CAPACITY GENERATION TYPE COUNTY LOCATION OF UNITS KW --------------- --------------- -------- ---------- Hydroelectric: Conventional Plants(1)......... 16 counties in Northern and 109 2,698,100 Central California Helms Pumped Storage Plant..... Fresno 3 1,212,000 --- ---------- Hydroelectric Subtotal....... 112 3,910,100 --- ---------- Steam Plants: Contra Costa................... Contra Costa 2 680,000 Humboldt Bay................... Humboldt 2 105,000 Hunters Point(2)............... San Francisco 3 377,000 Morro Bay(2)................... San Luis Obispo 4 1,002,000 Moss Landing(2)................ Monterey 2 1,478,000 Pittsburg...................... Contra Costa 7 2,022,000 Potrero........................ San Francisco 1 207,000 --- ---------- Steam Subtotal................. 21 5,871,000 --- ---------- Combustion Turbines: Hunters Point.................. San Francisco 1 52,000 Oakland(2)..................... Alameda 3 165,000 Potrero........................ San Francisco 3 156,000 Mobile Turbines(3)............. Humboldt and Mendocino 3 45,000 --- ---------- Combustion Turbines Subtotal... 10 418,000 --- ---------- Geothermal: The Geysers Power Plant(4)..... Sonoma and Lake 14 1,224,000 Nuclear: Diablo Canyon.................. San Luis Obispo 2 2,160,000 --- ---------- Thermal Subtotal............. 47 9,673,000 --- ---------- Total................................................... 159 13,583,100 === ==========
- -------- (1) Two hydroelectric plants with approximately 5,000 kW of net operating capacity were sold in 1996. (2) PG&E has announced plans to sell these power plants in connection with electric industry restructuring. (3) Listed to show capability; subject to relocation within the system as required. (4) The Geysers Power Plant net operating capacity is based on adequate geothermal steam supply conditions. Any decrease in capacity, at peak, is included as unavailable capacity in the Control Area Net Capacity table below. 18 The following table sets forth the available capacity for the control area (the area served by PG&E and various publicly owned systems in Northern California) at the date of peak (including reduction for scheduled and forced outages and based on actual water conditions) by various sources of generation available to the control area and the total amount of generation provided by these sources during the year ended December 31, 1996.
CONTROL AREA NET CAPACITY (AT DATE OF 1996 PEAK) ---------------------- KW % -------------- ------- Sources of Electric Generation: PG&E-Owned Plants: Fossil Fueled.................... 6,289,000 48 Geothermal....................... 1,224,000 9 Nuclear.......................... 2,160,000 16 -------------- ------- Total Thermal................... 9,673,000 73 Hydroelectric (available)........ 3,603,300 27 Solar............................ 0 0 -------------- ------- Total PG&E-Owned Capacity........ 13,276,300 100 ============== ======= Less Unavailable Capacity........ 2,750,000 -------------- Total PG&E Available Capacity.... 10,526,300 46 Capacity Received from Others: QF Producers (available)......... 3,039,600 14 Area Producers & Imports......... 9,158,100 40 -------------- ------- Capacity from Others............. 12,197,700 54 -------------- ------- Total Available Capacity......... 22,724,000 100 ============== ======= Total Area Demand(1)(2)........... 21,437,000 ==============
GENERATION YEAR ENDED DECEMBER 31, 1996(3) -------------------- KWH THOUSANDS % -------------- ------ Electric Generation: PG&E-Owned Plants: Fossil Fueled................... 11,619,910 11 Geothermal...................... 4,514,643 4 Nuclear......................... 16,719,721 17 -------------- ------ Total Thermal.................. 32,854,274 32 Hydroelectric................... 15,157,798 15 Solar........................... 1,580 0 Total PG&E Generation........... 48,013,652 -- -------------- ------ Helms Pumpback Energy........... (897,506) (1) -------------- ------ Net PG&E Generation............. 47,116,146 46 ============== ====== Generation Received from Others: QF Producers.................... 20,351,814 20 Area Producers & Imports........ 34,532,040 34 -------------- ------ Generation from Others.......... 54,883,854 54 ============== ====== Total Area Generation........... 102,000,000 100 ============== ======
- -------- (1) The maximum control area peak demand to date was 21,437,000 kW which occurred in August 1996. (2) The reserve capacity margin at the time of the 1996 control area peak, taking into account short-term firm capacity purchases from utilities located outside PG&E's service area: PG&E's load responsibility for spinning reserve (capability already connected to the system and ready to meet instantaneous changes in demand) to the control area peak was 7.3% of the peak demand and total reserve (spinning reserve and capability available within a short period of time) was 7.8%. (3) Represents actual year net generation from sources shown. Generation received from others is based on the best available information at the publication date of this document. 19 DIABLO CANYON DIABLO CANYON OPERATIONS 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, 1996, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 79.7% and 81.7%, respectively. The table below outlines Diablo Canyon's refueling schedule for the next five years. In the past, Diablo Canyon refueling outages typically have occurred every 18 months. Beginning in 1996, PG&E schedules refueling outages every 21 months, and it intends to seek NRC licensing authority to schedule such outages once every 24 months beginning in 2001. The schedule below assumes that a refueling outage for a unit will last approximately six weeks, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages or changes in the length of the fuel cycle.
1997 1998 1999 2000 2001 ----- -------- -------- --------- ----- Unit 1 Refueling........................... April January September Startup............................. May March October Unit 2 Refueling........................... February October April Startup............................. March November June
DIABLO SETTLEMENT The Diablo Settlement adopted alternative ratemaking for Diablo Canyon by basing revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. Under the existing Diablo Settlement, revenues are based on a pre-established price per kWh of electricity generated by the plant. That price consists of a fixed component (3.15 cents per kWh) and a separate component that declines until 2000, at which point the variable component begins to escalate. The total price per kWh for the year 1996 was 10.50 cents. Under this "performance-based" approach, PG&E assumes a significant portion of the operating risk of the plant because the extent and timing of the recovery of actual operating costs, depreciation, and a return on the investment in the plant primarily depend on the amount of power produced and the level of costs incurred. PG&E's earnings are affected directly by plant performance and costs incurred. Currently, earnings relating to Diablo Canyon can fluctuate significantly as a result of refueling or other extended plant outages, plant expenses, and the effects of a peak-period pricing mechanism. As noted above, in connection with electric industry restructuring, PG&E has proposed to modify the existing Diablo Settlement. Under the modification proposal, PG&E would replace the existing Diablo Settlement price with a sunk cost revenue requirement and a performance-based Incremental Cost Incentive Price (ICIP). The sunk cost revenue requirement for Diablo Canyon would include recovery of the net investment in Diablo Canyon over a five-year period and a return on common equity of 90% of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52% in 1996. Under the ICIP, the plant's variable and other operating costs and future capital additions would be recovered under a pre-set price per kWh of plant output based on an initial expectation of such costs and output. Under PG&E's modification proposal, the termination date in the existing Diablo Settlement would be changed from 2016 to 2001. As proposed, closure cost recovery provisions would replace existing abandonment payment provisions. Under the cost recovery provisions, PG&E would be entitled to recover a percentage of its annual operating costs for a limited number of years following the plant's permanent closure. PG&E's continued recovery of the sunk cost revenue requirement would be subject to CPUC evaluation if Diablo Canyon is shut down for nine months or more before the end of the transition period. After such time, there would be no restrictions on Diablo Canyon's operations, to which customers it could sell and at what prices, terms, and 20 conditions; however, 50% of any after-tax earnings available for common equity after such time would be allocated to ratepayers. More information concerning the financial impact of the proposed Diablo Settlement modification is included in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Notes 2 and 4 of the "Notes to Consolidated Financial Statements" beginning on pages 29 and 32, respectively, of the 1996 Annual Report to Shareholders. On February 28, 1997, the assigned ALJ issued a proposed decision on PG&E's proposed modification to Diablo Canyon ratemaking. With significant exceptions, the proposed decision generally adopts the overall ratemaking structure proposed by PG&E, but would substantially alter the proposed ICIP mechanism and would exclude certain items from the sunk cost revenue requirement. Instead of adopting the fixed forecast of ICIP prices for the 1997-2001 period proposed by PG&E, the proposed decision adopts an alternative cost of service approach, which would establish an initial forecast of ICIP prices which will be adjusted annually through 2001 to reflect a new forecast incorporating Diablo Canyon's actual operating costs and capacity factor. With respect to sunk costs, the proposed decision adopts a "prudence" disallowance based on the finding that PG&E admitted in pre-1988 Diablo testimony that a design error cost $100 million. The disallowance would be equal to $100 million times the ratio of depreciated value of the original plant to undepreciated value of the original plant, which PG&E estimates would equal approximately $60-$70 million. The proposed decision also excludes several items totaling $160 million from the sunk cost revenue requirement, including out-of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The proposed decision requires that out-of-core fuel inventory and materials and supplies inventory be recovered in ICIP prices. The proposed decision requires an independent financial verification audit of Diablo Canyon sunk costs, to be completed within six months. Diablo Canyon sunk cost recovery would be adjusted to reflect the results of this audit. In addition, the proposed decision terminates, rather than modifies as proposed by PG&E, the Diablo Settlement on the date the proposed decision is adopted by the CPUC. PG&E intends to seek clarification from the CPUC that the termination of the Diablo Settlement would not affect Diablo Canyon's "must take" status during the transition period. Based on a very preliminary review and interpretation of the proposed decision and assuming that the modified rates are effective January 1, 1997, PG&E Corporation estimates that the impact on 1997 earnings could be approximately five cents per share negative compared to PG&E Corporation's 1997 budget. This estimate is subject to change, and the actual impact of the proposed decision on the Company's financial results will depend on several factors, including clarification of several ambiguities in the proposed decision. In addition, there could be a further negative impact compared to PG&E Corporation's 1997 budgeted results if the modified rates are effective on the date the CPUC adopts the final decision, given the timing of recovery of Diablo Canyon transition costs. The proposed decision is not a final decision of the CPUC, and is subject to change prior to a vote of the full CPUC. The proposed decision currently is scheduled for consideration by the full CPUC at its April 9, 1997 meeting. NUCLEAR FUEL SUPPLY AND DISPOSAL PG&E has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium; it has one contract for fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, the conversion of uranium to uranium hexaflouride, and the enrichment of the uranium hexaflouride to enriched uranium will be satisfied by a combination of existing contracts and inventories through 2000, 1999, and 2002, respectively. The fuel fabrication contract for the two units will supply their requirements for the next eight operating cycles of each unit. These contracts are intended to ensure long- term 21 fuel supply, but permit PG&E the flexibility to take advantage of short-term supply opportunities. In most cases, PG&E's nuclear fuel contracts are requirements-based, with PG&E's obligations linked to the continued operation of Diablo Canyon. Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, PG&E has signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from PG&E's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has officially acknowledged that it will not be able to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted by the DOE for interim or permanent storage before 2012, at the earliest. At the projected level of operation for Diablo Canyon, PG&E'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. PG&E 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 PG&E's plan to store radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the unit. The license amendment issued by the NRC allows storage of spent fuel rods at Humboldt until a federal repository is established. PG&E has agreed to remove all nuclear waste as soon as possible after the federal disposal site is available. INSURANCE PG&E has insurance coverage for property damage and business interruption losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). These companies, which are owned by utilities with nuclear generating facilities, provide 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 PG&E's policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, PG&E may be subject to maximum retrospective premium assessments of $29 million (property damage) and $8 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NML or NEIL. PG&E has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $8.7 billion of coverage is provided by secondary financial protection required by federal law and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, PG&E may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. DECOMMISSIONING The estimated total obligation for decommissioning PG&E's nuclear power facilities is comprised of the total cost (including labor, materials, and other costs) of decommissioning and dismantling plant systems and structures. In addition, a contingency amount for possible changes in regulatory requirements and increases in waste disposal costs is included in the estimated total obligation. The estimated total obligation for nuclear decommissioning costs, based on a 1994 site study, is approximately $1.2 billion in 1996 dollars (or $5.9 billion in future dollars). 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. 22 Decommissioning costs recovered in rates are placed in external trust funds. These funds, along with accumulated earnings, will be used exclusively for decommissioning. The trust funds maintain substantially all of their investments in debt and equity securities. All fund earnings are reinvested. Funds may not be released from the external trust funds until authorized by the CPUC. As of December 31, 1996, PG&E had accumulated external trust funds with an estimated fair value of $883 million, based on quoted market prices, to be used for the decommissioning of PG&E's nuclear facilities. In the past, the amount recovered in rates for decommissioning costs through an annual allowance has been reviewed by the CPUC as part of the GRC. The CPUC considers the trust's asset level, together with revised earnings and decommissioning cost assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trust. The funds 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, 1996, nuclear decommissioning costs recovered in rates were $33 million. In the future, AB 1890 provides that nuclear decommissioning costs, which are not transition costs, will be recovered through a nonbypassable charge until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. In its roadmap decision, the CPUC established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and establish the annual revenue requirement and attrition factors over three-year periods when and if GRCs are discontinued. OTHER ELECTRIC RESOURCES QF GENERATION AND OTHER POWER PURCHASE CONTRACTS Under the Public Utility Regulatory Policies Act of 1978, PG&E is required to purchase electric energy and capacity provided by QFs which are cogenerators and small power producers. The CPUC established a series of power purchase contracts with QFs and set the applicable terms, conditions, and price options. Under these contracts, PG&E is required to purchase electric energy and capacity; however, payments are only required when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. PG&E's contracts with QFs expire on various dates from 1997 to 2028. Energy payments to QFs are expected to decline in the years 1997 through 2000. Capacity payments are expected to remain at current levels. In 1996, 1995 and 1994, PG&E negotiated the early termination or suspension of certain QF contracts at discounted costs of $25 million, $142 million, and $155 million, respectively. Amounts to be paid for termination or suspension are payable through 1999. These amounts are expected to be recovered in rates. At December 31, 1996, the total discounted future payments remaining under QF early termination or suspension contracts was $68 million. QF deliveries in the aggregate account for approximately 19% of PG&E's 1996 electric energy requirements and no single contract accounted for more than 5% of PG&E's energy needs. PG&E also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, PG&E must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the provider's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the providers. These contracts expire on various dates from 2004 to 2031. The total cost of these payments is recoverable in rates. At December 31, 1996, the undiscounted future minimum payments under these contracts are $34 million for each of the years 1997 through 2001, and a total of $383 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 6% of PG&E's 1996 electric energy requirements, and no single contract accounted for more than 5% of PG&E's energy needs. 23 The amount of energy received and the total payments made (including termination and suspension payments) under QF contracts and other power purchase contracts were:
1996 1995 1994 ------ ------ ------ (IN MILLIONS) kWh received........................................ 26,056 26,468 23,903 QF energy payments.................................. $1,136 $1,140 $1,196 QF capacity payments................................ $ 521 $ 484 $ 518 Other power purchase payments....................... $ 52 $ 50 $ 49
As of December 31, 1996, PG&E had approximately 5,800 megawatts (MW) of QF capacity under CPUC-mandated power purchase agreements. Of the 5,800 MW, approximately 4,600 MW were operational. Development of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 5,800 MW of QF capacity consists of 2,900 MW from cogeneration projects, 1,700 MW from wind projects and 1,200 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. GEOTHERMAL GENERATION PG&E's geothermal units at The Geysers Power Plant (Geysers) are forecast to operate at reduced capacities because of declining geothermal steam supplies and curtailment of the Geysers due to the existence of more economic sources of electric generation. PG&E's agreements with several of its steam suppliers permit PG&E to curtail generation at the Geysers at PG&E's discretion. The consolidated Geysers capacity factor is forecast to be approximately 40% of installed capacity in 1997, which includes economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 42% in 1996. HELMS PUMPED STORAGE PLANT Helms is a three-unit hydroelectric combined generating and pumped storage facility, completion of which was delayed due to a water conduit rupture in September 1982 and various start-up problems related to the plant's generators. Helms became commercially operable in June 1984. As a result of the damage caused by the rupture and the delay in the operational date, PG&E incurred additional costs which were not initially included in rate base, and lost revenues during the period the plant was under repair. In September 1996, the CPUC approved a settlement resolving the treatment of remaining unrecovered Helms costs. As part of the 1996 GRC decision issued in December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of Helms. The CPUC indicated the study should consider changes in rate recovery for the plant including, among other things, the option of retirement with recovery of the investment without a return. The cost-effectiveness study submitted by PG&E in July 1996 concluded that the continued operation of Helms is cost effective. PG&E recommended that the CPUC take no action based on the study, but address Helms along with other generating plants in the context of electric industry restructuring. PG&E is currently unable to predict whether there will be a change in rate recovery resulting from the study. As with its other hydroelectric generating plants, PG&E expects to seek recovery of its net investment in Helms ($710 million at December 31, 1996) through the hydroelectric and geothermal PBR and CTC recovery. ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT At present, California's long-range electric resource planning is coordinated between the CEC and the CPUC. Applicable statutes require that, every two years, the CEC prepare an Electricity Report that includes load forecasts and resource assumptions for a 20-year period and the CPUC conduct a Biennial Resource Plan Update (BRPU) proceeding which is linked to a specific CEC Electricity Report. The purpose of the BRPU is to determine whether any cost-effective electric resources (either new generating resources or power purchases) should be added to the regulated utilities' electric systems based on a 12-year planning horizon. In making this 24 determination, the CPUC gives great weight to the load forecasts and resource assumptions included in the CEC's Electricity Report. However, in light of the restructuring of the electric utility industry, it is unclear what relevance, if any, the BRPU and the CEC's Electricity Report proceedings will have with regard to California utility resource planning and procurement in the future. The timetable for release of the draft 1996 Electricity Report has been delayed. The future of electric resource acquisition is being addressed as part of electric industry restructuring. Under the plan contemplated in the CPUC's restructuring decision issued in December 1995, utilities would retain the obligation to acquire resources for customers who continue to take bundled electric utility services, but this obligation would be met entirely through purchases from the PX during the transition period starting January 1, 1998. Beginning in 2002, PG&E could acquire power from sources other than the PX to satisfy the demands of its utility customers. PG&E's demand forecasts and resource procurement plans are subject to possibly significant changes depending on the ultimate outcome of electric industry restructuring. In 1997, PG&E does not anticipate adding any new MW of resources to its system. PG&E currently plans no new major construction projects for electric supply. ELECTRIC TRANSMISSION To transport energy to load centers, PG&E as of December 31, 1996, owned and operated approximately 18,516 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 32,892,000 kilovolt-amperes (kVa). Energy is distributed to customers through approximately 108,170 circuit miles of distribution system and distribution substations having a capacity of approximately 23,000,000 kVa. Traditionally, the transmission of electric energy in interstate commerce and the sale of electric energy for resale (wholesale sales) have been regulated by the FERC. In 1996, the FERC issued an order requiring utilities to provide wholesale open access to electric transmission systems on terms that are comparable to the way utilities use their own systems. PG&E's open access tariff, filed in July 1996, is now available for service to any eligible party interested in wholesale transmission service over PG&E's transmission system. The FERC also reaffirmed its intention to permit utilities to recover any legitimate, verifiable, and prudently incurred costs stranded as a result of customers taking advantage of wholesale open access orders to meet their power needs from other sources. Pursuant to the CPUC's electric industry restructuring decision, PG&E and the other two California investor owned electric utilities filed a joint ISO application with the FERC. The application requested authorization to transfer operational control (but not ownership) of certain transmission facilities to the ISO. The ISO will control the dispatch of generation and the operation of the transmission system and provide open access transmission service on a nondiscriminatory basis. In November 1996, the FERC issued an order approving the structure of the ISO and PX as proposed by the utilities, but requiring detailed tariffs and other required filings by March 31, 1997. Also in connection with electric industry restructuring, the FERC issued an order in December 1996 addressing market power issues. That decision relied on measures to mitigate and monitor market power rather than on continued studies to determine whether the utilities had market power. The FERC has also approved a proposal from PG&E and the other California utilities that distinguishes between local distribution facilities and transmission facilities. The order defines jurisdiction for the CPUC over local distribution and retail power customers. The FERC will have jurisdiction over the transmission facilities as defined in the order and over the transmission aspects of retail direct access. 25 GAS UTILITY OPERATIONS PG&E owns and operates an integrated gas transmission, storage, and distribution system in California. At December 31, 1996, PG&E's system, including the PG&E Expansion (Line 401), consisted of approximately 5,700 miles of transmission pipelines, three gas storage facilities, and approximately 36,200 miles of gas distribution lines. GAS OPERATIONS PG&E's peak day send-out of gas on its integrated system in California during the year ended December 31, 1996 was 3,407 million cubic feet (MMcf). The total volume of gas throughput during 1996 was approximately 826,000 MMcf, of which 264,000 MMcf was sold to direct end-use or resale customers, 134,000 MMcf was used by PG&E primarily for its fossil-fueled electric generating plants, and 428,000 MMcf was transported as customer owned gas. The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities as a result of a CPUC order. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years. The 1996 Report updates PG&E's annual gas requirements forecast (excluding bypass volumes) for the years 1996 through 2010, forecasting growth in gas thoughput served by PG&E of 2% per year. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing PG&E's system entirely. The 1996 Report forecasts a total bypass volume of 133,600 MMcf for 1996. 26 GAS OPERATING STATISTICS The following table shows PG&E's operating statistics (excluding subsidiaries except where indicated) for gas, including the classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31 ---------------------------------------------------------- 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- CUSTOMERS (AVERAGE FOR THE YEAR): Residential............ 3,455,086 3,417,556 3,372,768 3,339,859 3,311,881 Commercial............. 198,071 197,939 196,509 195,815 195,689 Industrial............. 1,500 1,500 1,400 1,265 1,185 Other gas utilities.... 2 2 2 4 4 ---------- ---------- ---------- ---------- ---------- Total............... 3,654,659 3,616,997 3,570,679 3,536,943 3,508,759 ========== ========== ========== ========== ========== GAS SUPPLY -- THOUSAND CUBIC FEET (MCF) (IN THOUSANDS): Purchased: From Canada........... 253,209 261,800 319,453 329,693 321,770 From California....... 28,130 31,158 31,757 32,096 50,953 From other states..... 110,604 117,538 249,733 243,058 327,272 ---------- ---------- ---------- ---------- ---------- Total purchased..... 391,943 410,496 600,943 604,847 699,995 Net from storage (to storage).............. 6,871 (10,921) 3,591 (12,234) 10,135 ---------- ---------- ---------- ---------- ---------- Total............... 398,814 399,575 604,534 592,613 710,130 PG&E use, losses, etc.(1)............... 134,375 129,671 297,604 161,895 281,021 ---------- ---------- ---------- ---------- ---------- Net gas for sales... 264,439 269,904 306,930 430,718 429,109 ========== ========== ========== ========== ========== BUNDLED GAS SALES AND TRANSPORTATION SERVICE -- MCF (IN THOUSANDS): Residential............ 190,246 191,724 214,358 206,053 190,176 Commercial............. 62,178 64,135 72,183 82,048 79,983 Industrial............. 12,015 14,045 19,495 133,178 145,356 Other gas utilities.... 0 0 894 9,439 13,594 ---------- ---------- ---------- ---------- ---------- Total(2)............ 264,439 269,904 306,930 430,718 429,109 ========== ========== ========== ========== ========== TRANSPORTATION SERVICE ONLY -- MCF (IN THOUSANDS): Vintage system (Substantially all Industrial)(3)........ 189,695 143,921 142,393 101,888 103,186 PG&E Expansion (Line 401).................. 237,776 240,506 200,755 20,513 -- ---------- ---------- ---------- ---------- ---------- Total............... 427,471 384,427 343,148 122,401 103,186 ========== ========== ========== ========== ========== REVENUES (IN THOUSANDS): Bundled gas sales and transportation service: Residential........... $1,109,463 $1,205,223 $1,268,966 $1,152,494 $1,092,324 Commercial............ 362,819 421,397 444,805 467,962 479,599 Industrial............ 42,520 42,106 57,297 367,221 425,467 Other gas utilities... 510 0 2,371 25,654 38,504 ---------- ---------- ---------- ---------- ---------- Bundled gas revenues........... 1,515,312 1,668,726 1,773,439 2,013,331 2,035,894 Transportation only revenue: Vintage system (Substantially all Industrial).......... 180,197 167,325 132,509 56,733 75,606 PG&E Expansion (Line 401)................. 85,144 82,904 58,442 8,097 -- ---------- ---------- ---------- ---------- ---------- Transportation service only revenue............ 265,341 250,229 190,951 64,830 75,606 Miscellaneous.......... (9,271) (18,018) 40,427 (16,692) 21,022 Regulatory balancing accounts.............. 57,864 (43,771) (101,443) 95,339 40,199 Subsidiaries(4)........ 210,556 201,951 177,688 264,925 173,587 ---------- ---------- ---------- ---------- ---------- Operating revenues.. $2,039,802 $2,059,117 $2,081,062 $2,421,733 $2,346,308 ========== ========== ========== ========== ==========
- -------- (1) Includes use by business units other than the Gas Supply business unit, principally as fuel for fossil-fueled generating plants. (2) In August 1991, PG&E implemented its customer identified gas (CIG) program. Sales included approximately 105,000 MMcf and 130,000 MMcf in 1993 and 1992, respectively, of gas procured by PG&E for CIG customers at prices negotiated directly between those customers and suppliers. The CIG Program was terminated on October 31, 1993 upon full implementation of the CPUC's capacity brokering program. (3) Does not include on-system transportation volumes transported on the PG&E Expansion of 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and 7,205 MMcf for 1996, 1995, 1994, and 1993, respectively. (4) Includes gas transportation revenues from PGT. 27
YEARS ENDED DECEMBER 31 ------------------------------------------------- 1996 1995 1994 1993 1992 --------- --------- --------- --------- --------- SELECTED STATISTICS: Total customers (at year- end)....................... 3,700,000 3,600,000 3,500,000 3,600,000 3,500,000 Average annual residential usage (Mcf)................ 55 56 64 62 57 Heating temperature -- % of normal(1).................. 75.7 75.3 104.4 89.9 76.0 Average billed bundled gas sales revenues per Mcf: Residential................. $5.83 $6.29 $5.92 $5.59 $5.74 Commercial.................. 5.84 6.57 6.16 5.70 6.00 Industrial.................. 3.54 3.00 2.94 2.76 2.93 Average billed transportation only revenue per Mcf: Vintage system.............. 0.67 0.69 0.60 0.52 0.73 PG&E Expansion (Line 401)... 0.36 0.34 0.29 0.39 -- Net plant investment per customer................... $1,378 $1,315 $1,340 $1,339 $1,170
- -------- (1) Over 100% indicates colder than normal. NATURAL GAS SUPPLIES The objective of PG&E's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs, and fosters competition among suppliers. Under current CPUC regulations, PG&E purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 1996, approximately 65% of PG&E's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by Canadian pipeline companies and PGT; approximately 7% was purchased from various California producers; and approximately 28% was purchased from other states (substantially all U.S. Southwest sources and transported by El Paso or Transwestern). The following table shows the volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by PG&E from these sources during each of the last five years.
YEARS ENDED DECEMBER 31 -------------------------------------------------------------------------------------------------- 1996 1995 1994 1993 1992 ------------------ ----------------- ----------------- ------------------ ------------------ 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............ 253,209 $1.57 261,800 $1.34 319,453 $1.94 329,693 $2.26 321,770 $2.14 California........ 28,130 $1.90 31,158 $1.32 31,757 1.55 32,096 1.65 50,953 1.73 Other states (substantially all U.S. Southwest)....... 110,604 $3.72 117,538 $2.64 249,733 2.41 243,058 2.84 327,272 2.51 ------- ------- ------- ------- ------- Total/Weighted Average.......... 391,943 $2.21 410,496 $1.71 600,943 $2.12 604,847 $2.46 699,995 $2.28 ======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- -------- (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. The average prices for California gas include only commodity gas prices delivered to PG&E's gas system. GAS REGULATORY FRAMEWORK The current regulatory framework for natural gas service in California (i) segments customers into core and noncore classes; (ii) unbundles utilities' gas transportation and procurement services; (iii) allows customers to purchase gas directly from producers, aggregators, or marketers, and to separately purchase gas transportation from their utilities; and (iv) places the utilities at risk for collecting a portion of the transportation revenues associated with their noncore markets. 28 Under this regulatory framework, noncore customers have the option of buying gas directly from the supplier of their choice and purchasing from PG&E transmission and distribution services only. Certain customers can also use alternative transportation services provided by competing pipeline companies. However, core customers continue to have more limited opportunities in choosing their gas suppliers, with substantially all core customers receiving bundled services from PG&E. In an effort to promote competition and increase options for all customers, as well as to position itself in the competitive marketplace, PG&E has submitted to the CPUC for its approval a Gas Accord, which would restructure PG&E's gas services and its role in the gas market. As discussed above (see "Competition and the Changing Regulatory Environment--Gas Industry"), the Gas Accord consists of three broad initiatives: (1) unbundling of PG&E's gas transmission and storage services from its distribution services; (2) reduction of PG&E's role in procuring gas supplies for core customers in order to increase opportunities for such customers to purchase gas from their supplier of choice; and (3) resolution of major outstanding regulatory issues. Also as part of the Gas Accord, PG&E has proposed that traditional reasonableness reviews of its core gas procurement costs be replaced with a CPIM, under which PG&E would be able to recover its gas commodity and interstate transportation costs and receive benefits or be penalized depending on whether its actual core procurement costs were within, below, or above a "tolerance band" constructed around market benchmarks. The Gas Accord must be approved by the CPUC before it can be implemented. TRANSPORTATION COMMITMENTS PG&E 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 PG&E will pay each year may change due to changes in tariff rates. The total demand and transportation charges paid by PG&E under these agreement (excluding agreements with PGT) was approximately $212 million in 1996. As a result of regulatory changes, PG&E no longer procures gas for its noncore customers, resulting in a decrease in PG&E's need for firm transportation capacity for its gas purchases. PG&E continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers). PG&E is continuing its efforts to broker or assign any remaining unused capacity, including unused capacity held for its core and core subscription customers. Due to relatively low demand for Southwest pipeline capacity, PG&E cannot predict the volume or price of the capacity on El Paso and Transwestern that will be brokered or assigned. In general, demand charges incurred by PG&E for pipeline capacity are eligible for rate recovery, subject to a reasonableness review. The demand charges include the cost of capacity that was formerly used to serve noncore customers but which at present cannot be brokered or which is brokered at a discount. However, certain groups, including the ORA and intervenors, have challenged the recovery of these unrecovered demand charges in the proceeding relating to ITCS recovery (see "El Paso and PGT Capacity" below). In addition, the CPUC has issued an unfavorable decision addressing recovery of Transwestern charges (see "Transwestern Capacity" below). EL PASO AND PGT CAPACITY PG&E's firm transportation agreement with PGT for 1,066 million cubic feet per day (MMcf/d) runs through October 31, 2005. PG&E's firm transportation agreement with El Paso for 1,140 MMcf/d runs through December 31, 1997. The firm transportation reservation charges associated with PG&E's firm capacity on PGT and El Paso are approximately $57 million and $163 million per year, respectively. Pursuant to FERC rules on capacity relinquishment and release and the CPUC's capacity brokering program, PG&E currently retains approximately 600 MMcf/d on each of the PGT and El Paso systems to support its core and core subscription customers. PG&E made capacity not needed to support such customers available 29 for release and brokering to other potential shippers beginning in 1993. PG&E has assigned substantially all of its unused capacity on PGT. Due to lower demand for Southwest pipeline capacity, PG&E cannot predict the volume or price of the capacity on El Paso that will be brokered or assigned. To the extent PG&E is unable to broker its firm interstate capacity above core and core subscription reservations at the full as-billed rate, PG&E has been authorized to accumulate unrecovered demand charges for El Paso and PGT in the ITCS account pending CPUC reasonableness review of those amounts in the ITCS proceeding. As noted above, in the ITCS proceeding, certain intervenors have challenged PG&E's recovery of amounts in the ITCS account, and suggested disallowances and/or a reallocation among customers of between $40 and $101 million. Pending a final decision in the ITCS proceeding, the CPUC has approved collection in rates (subject to refund) of approximately 50% of the demand charges for unbrokered or discounted El Paso and PGT capacity formerly used to serve PG&E's noncore customers. In the meantime, PG&E has proposed a resolution of this matter as part of the Gas Accord. Under the Gas Accord, PG&E would forgo recovery of 100% and 50% of the ITCS amounts allocated to its core and noncore customers, respectively. TRANSWESTERN CAPACITY In April 1992, PG&E executed firm transportation agreements with Transwestern to transport approximately 200 MMcf/d of San Juan basin gas supplies into PG&E's southern gas system, of which approximately 150 MMcf/d is to be used to meet PG&E's core gas sales demands and approximately 50 MMcf/d is for use by PG&E's electric department. The agreements with Transwestern expire in 2007. The demand charges associated with the entire Transwestern capacity are currently approximately $29 million per year. Currently, PG&E is not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account. PG&E is authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings. In December 1995, the CPUC issued a decision on the reasonableness of PG&E's 1992 gas operations, which concluded that it was unreasonable for PG&E to commit to transportation capacity with Transwestern. The decision orders that costs for the capacity in subsequent years of the contract, which expires in 2007, be disallowed each year unless PG&E can demonstrate that the benefits of the commitment outweight the costs in that year. PG&E has also addressed the Transwestern issue in its Gas Accord proposal. The Gas Accord provides that PG&E would not recover costs through 1997 associated with Transwestern capacity originally subscribed to in order to serve core customers and would have limited recovery during the period 1998 through 2002. PG&E has recorded reserves relating to its gas capacity commitments and the issues addressed by the Gas Accord. More information concerning the financial impact of these matters is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 1996 Annual Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 31 of the 1996 Annual Report to Shareholders. GAS REASONABLENESS PROCEEDINGS Recovery of gas costs through PG&E's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were incurred reasonably. Under the current regulatory framework, annual reasonableness proceedings are conducted by the CPUC on a historic calendar year basis. 1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES In March 1994, the CPUC issued a final decision on PG&E's Canadian gas procurement activities during 1988 through 1990. The CPUC found that PG&E could have saved its customers money if it had bargained more 30 aggressively with its existing Canadian suppliers or bought less expensive gas from other Canadian sources. The decision ordered a disallowance of $90 million of gas costs, plus accrued interest estimated at approximately $25 million through December 31, 1993. In December 1994, PG&E filed a complaint against the CPUC in the U.S. District Court for the Northern District of California challenging this decision by the CPUC. The complaint alleges that the CPUC disallowance order purports to regulate the foreign and interstate purchase and transportation of natural gas, matters within the exclusive jurisdiction of United States and Canadian regulatory authorities. Accordingly, the complaint alleges, such order is preempted by federal law and violates PG&E's rights under the United States Constitution. The complaint seeks injunctive and declaratory relief. PG&E's lawsuit is still pending in federal court. However, as part of the Gas Accord, PG&E would agree to forgo recovery of the $90 million disallowance ordered in the 1988-1990 reasonableness proceeding, irrespective of the outcome of the lawsuit challenging the disallowance. GAS SETTLEMENT AGREEMENT In December 1996, the CPUC approved a settlement agreement resolving various issues related to PG&E's gas procurement practices and supply operations for periods from 1988 through May 1994. Pursuant to the settlement agreement, PG&E will return approximately $75 million (including interest) to ratepayers. PGT/PG&E PIPELINE EXPANSION In November 1993, PGT and PG&E placed in service the Pipeline Expansion, an expansion of their interconnected natural gas transmission systems from the Canadian border into California. The 840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern and Southern California. CPUC RATEMAKING The conditions of the CPUC's approval of the construction of the PG&E Expansion place PG&E at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross-over" ban under which volumes delivered from the incremental PGT portion (PGT Expansion) of the Pipeline Expansion must be transported at an incremental PG&E Expansion rate. The costs of PG&E Expansion operations are recovered only from PG&E Expansion customers, through rates established in separate PG&E Expansion rate proceedings. To date, shippers have executed long-term firm transportation contracts for approximately 40% of capacity on the PG&E Expansion. However, one of those shippers, which holds a substantial portion of the capacity held under long- term firm contracts, has an option to buy out its contract. The option is exercisable on or before May 1, 1997. PG&E will continue to market available capacity on the PG&E Expansion on both firm and as-available bases. Revenues are being collected on the basis of an interim revenue requirement, pending a final decision in the Pipeline Expansion Project Reasonableness case (PEPR). In 1994, PG&E filed its application in the PEPR requesting that the CPUC find reasonable the full capital costs of the PG&E Expansion (estimated to be $810 million). In that proceeding, the ORA recommended a minimum of $100 million in capital costs be disallowed, while two intervenors jointly recommended a $237 million disallowance or reallocation of costs among customers. In addition, in 1996, a CPUC ALJ ordered consolidation of the market impact phase of the PEPR and the ITCS proceeding described above. An ALJ also ordered reopening of the 1993 PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding the decision to construct the PG&E Expansion. Were the CPUC to reverse its previous decision, which found that PG&E was reasonable in constructing the PG&E Expansion, the ultimate outcome could have an adverse impact on PG&E's ability to recover its cost for unused capacity on other pipelines as well as on its own intrastate facilities. Decisions in these proceedings are expected in 1997, if the matters are not otherwise resolved 31 as part of the Gas Accord. Under the Gas Accord, PG&E would agree to set rates for the PG&E Expansion based on total capital costs of $736 million. The CPUC's decision in the 1997 Cost of Capital proceeding authorized a 1997 return on equity for PG&E Expansion operations of 11.6%, resulting in an overall rate of return of 8.99%. Authorized long-term debt levels for the PG&E Expansion will be reduced from their current 67% to 64% for 1997. FERC RATEMAKING In September 1996, the FERC approved a settlement of PGT's 1994 rate case. The major issue in this proceeding was whether PGT's mainline transportation rates should be equalized through the use of rolled-in cost allocations, or whether they should continue to reflect the use of incremental cost allocation to determine the rates to be paid by firm shippers. (Under incremental rates, a pipeline would generally charge higher rates to shippers contracting for capacity on newly-added expansion facilities as compared to shippers using depreciated pre-expansion facilities.) The settlement provides for rolled-in rates effective November 1996. To mitigate the impact of the higher rolled-in rates on shippers who were paying lower rates under contracts executed prior to construction of the PGT Expansion, most of the firm shippers who took service prior to such time receive a reduction from the rolled-in rate for a six-year period, while PGT Expansion firm shippers pay a surcharge in addition to the rolled-in rates to offset the effect of the mitigation. The settlement also provides for rates based on a return on equity of 12.2%. Several parties are seeking rehearing of the FERC order approving the settlement, but PGT currently expects the settlement to be upheld. DIVERSIFIED OPERATIONS In 1996, diversified operations primarily consisted of Enterprises. Enterprises participates in multiple domestic and international energy businesses. Enterprises, through its wholly owned subsidiary, PG&E Generating Company, has made the majority of its investments in nonregulated energy projects through U.S. Generating Company (USGen), in partnership with Bechtel Enterprises, Inc. (Bechtel). USGen, a California partnership, manages the development, construction, and operation of non-utility electric generation facilities that compete in the United States power generation market. Enterprises' average overall ownership in all the projects in which USGen participates is approximately 42 percent. As of December 31, 1996, USGen's partners had ownership interests in 17 operating plants. The total generating capacity of these 17 plants is 3,375 MW, of which Enterprises' share is 1,424 MW. The projects were largely financed with a combination of equity or equity commitments from the project sponsors and non-recourse debt. USGen, through its affiliate, U.S. Operating Services Company (USOSC), provides contract operations and maintenance services to many of these facilities. USGen, through its affiliate, USGen Power Services, L.P., is also an active power marketer. USGen also manages approximately 5.6 million tons per year of coal deliveries to its plants and approximately 875 MMcf/d of Canadian and U.S. natural gas supplies for deliveries to its plants and to local gas distribution companies in the Northeast. Enterprises' entry into the international market was also made in partnership with Bechtel. Enterprises and Bechtel formed International Generating Company, Ltd. (InterGen), which develops, owns, and operates international electric generation projects. However, in November 1996, Enterprises and Bechtel reached an agreement for Bechtel to acquire Enterprises' interest in InterGen. The Company expects to complete the sale in the first quarter of 1997 and to realize an after-tax gain. Enterprises has refined its international strategy to focus on select countries and to concentrate on end-use energy customers. In 1995, Enterprises formed Vantus, a retail energy services provider, to assist customers in locating the most cost-effective electric and gas products and services. Vantus' energy services include power marketing for industrial and large commercial businesses nationwide. In 1996, Vantus opened new offices in the western United States to establish a presence and market its services in emerging energy markets. 32 PG&E ENVIRONMENTAL MATTERS ENVIRONMENTAL MATTERS The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection and the possible future impact of environmental compliance. This information reflects PG&E's current estimates which are periodically evaluated and revised. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of PG&E's responsibility, and the availability of recoveries or contributions from third parties. Future estimates and actual results may differ materially from those indicated below. PG&E and its affiliates are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. PG&E has undertaken major compliance efforts with specific emphasis on its purchase, use, and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of PG&E's bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations have generally been recovered in rates. ENVIRONMENTAL PROTECTION MEASURES PG&E's estimated expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. PG&E's capital expenditures for environmental protection are currently estimated to be approximately $36 million, $50 million, and $72 million for 1997, 1998 and 1999, respectively, and are included in PG&E's three-year estimate of capital requirements shown above in "General--Capital Requirements and Financing Programs." Expenditures during these years will be primarily for oxides of nitrogen (NOx) emission reduction projects at PG&E's fossil-fueled generating plants and natural gas compressor stations as described below, which currently are expected to decline in the later years as the NOx reduction projects are completed. Air Quality PG&E's existing 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, the three local air districts in which PG&E operates fossil-fueled generating plants 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 first major retrofits began in 1995. Certain retrofits will not be required if the smaller generating units are operated for emergency purposes only after 2000. PG&E currently estimates that compliance with these NOx rules could require capital expenditures of up to $360 million over 10 years. This estimate assumes that most of the 170 MW and smaller boilers will be retired before the retrofits are required. Ongoing business and engineering studies could change this estimate. Other air districts have adopted NOx rules for PG&E's natural gas compressor stations in California, and these rules continue to be modified. Eventually the rules are likely to require NOx reductions of up to 80% for many of PG&E's natural gas compressor stations. PG&E currently estimates that the total cost of complying with these rules will be up to $58 million over five years. In PG&E's 1996 GRC, the CPUC included $11.5 million in 1996 rate base for the estimated $60 million cost of gas and electric NOx retrofit projects to be installed in 1996. In the future, PG&E's electric NOx costs may be recoverable as CTCs or through PBR, market pricing, or other means established as part of electric industry restructuring. Under AB 1890, NOx costs would be eligible for recovery as CTCs but only to the extent that those costs are found by the CPUC to be both reasonable and necessary to maintain the unit in operation 33 through 2001. With respect to gas NOx costs, under the proposed Gas Accord $42 million would be included in rates for gas NOx retrofit projects through 2002. Water Quality PG&E's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. PG&E's fossil-fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast Regional Water Quality Control Board (Central Coast Board). The Central Coast Board did not make a final decision on the report and requested that PG&E continue its thermal effects monitoring program. In 1995, the Central Coast Board requested that PG&E prepare an updated comprehensive assessment of Diablo Canyon's thermal effects and approved a reduced environmental monitoring program. The new comprehensive assessment is scheduled for completion in the fourth quarter of 1997. In the unlikely event that the Central Coast Board finds that Diablo Canyon's existing thermal limits are not protective of beneficial uses of the marine waters and that major modifications are required (e.g., cooling towers), significant additional construction expenses could be required. Pursuant to the federal Clean Water Act, PG&E is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. PG&E has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. PG&E is currently preparing a new study for Diablo Canyon. The study is scheduled to be submitted to the Central Coast Board for review in 1999. In the event that the Central Coast Board finds that Diablo Canyon's cooling water intake structure does not meet the BTA requirements, significant additional expenses for construction or mitigation could be required. In addition, the promulgation or modification of federal, state, and regional water quality control plans may impose increasingly stringent cooling water discharge requirements on PG&E power plants in the future. Costs to comply with renewed permit conditions required to meet any more stringent requirements that might be imposed cannot be estimated at the present time. Several fish species listed or proposed for listing as endangered species may be found in the waters near certain of PG&E's power plants. There are severe restrictions on the "taking" (e.g., harassing, wounding, or killing) of such species. Therefore, significant modifications could be required to plant operations (e.g., cooling towers) if a plant intake structure or thermal discharge is found to "take" an endangered species. HAZARDOUS WASTE COMPLIANCE AND REMEDIATION PG&E assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. At present, these compliance and remediation costs (other than certain costs directly attributable to generation facilities) would generally be recovered through the GRC process or through a separate mechanism established by the CPUC in 1994 for recovery of certain hazardous waste remediation costs. At present, environmental remediation costs attributable to the decommissioning of generation facilities are included in rates as part of decommissioning costs. Under electric industry restructuring, remediation costs for generation facilities can be included as eligible CTCs that may be recovered during the transition period. It is not clear at this time what specific ratemaking mechanisms may be available for recovery of hazardous waste compliance and remediation costs after the transition period. PG&E has a comprehensive program to comply with the many hazardous waste storage, handling, and disposal requirements promulgated by the United States Environmental Protection Agency (EPA) under the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with California's hazardous waste laws and other environmental requirements. 34 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 PG&E, 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), PG&E's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. PG&E has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which operated in PG&E's service territory. PG&E owns all or a portion of 29 of these manufactured gas plant sites. PG&E has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which PG&E owns. PG&E currently estimates that this program may result in expenditures of approximately $8 million to $10 million over the period 1997 through 1998. 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 PG&E is found to be responsible for cleanup at sites it does not currently own. Manufactured gas plant sites at which PG&E has been designated as a potentially responsible party (PRP) under the California Hazardous Substance Account Act (California Superfund) include the Martin Service Center site and Midway/Bayshore sites in Daly City, California, the San Rafael site, and the Sacramento site. In addition to the manufactured gas plant sites, PG&E 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. PG&E has been designated as a PRP under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales site is a former used oil recycling facility at which PG&E is one of nine PRPs named in an EPA order requiring groundwater remediation at the site. PG&E has also entered into an Administrative Order with the EPA to address soil contamination at the site. PG&E has accrued a $4.5 million liability as of December 31, 1996, for the Purity Oil Sales site. With respect to the Casmalia site near Santa Maria, California, PG&E and several other generators of waste sent to the site have entered into an 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. Court approval of the agreement is being sought. PG&E has accrued a $3.2 million liability as of December 31, 1996, for the Casmalia site. Although PG&E has not been formally designated a PRP with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed PG&E and other parties to initiate measures with respect to the study and remediation of that site. PG&E has accrued a liability of $12.5 million as of December 31, 1996, for the Geothermal Incorporated site. In addition to the sites discussed above, PG&E has also been identified as a PRP at certain disposal sites under the California Superfund. These sites include the Emeryville Service Center site in Emeryville, California, and the GBF Landfill at Pittsburg, California. PG&E has also been sued for reimbursement of cleanup costs incurred by the State of California at PG&E's former Jibboom Street Station B power plant in Sacramento, California. In addition, PG&E has been named as a defendant in several civil lawsuits in which plaintiffs allege that PG&E is responsible for performing or paying for remedial action at sites PG&E no longer owns or never owned. The cost of hazardous substance remediation ultimately undertaken by the Company is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Company had an accrued liability at December 31, 1996, of $170 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $400 million if, among other things, other PRPs are not 35 financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to the Company among a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. POTENTIAL RECOVERY OF HAZARDOUS WASTE COMPLIANCE AND REMEDIATION COSTS In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs. That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. However, under the proposed mechanism, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. Under the mechanism, 70% of the ratepayer portion of PG&E's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. PG&E can seek to recover hazardous substance cleanup costs under the new mechanism in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, PG&E has proposed that any hazardous waste cleanup costs related to electric generation facilities be removed from this mechanism and included in CTCs. In addition, PG&E has proposed that this mechanism no longer be used for electric generation-related cleanup costs after January 1, 1998. PG&E expects to seek recovery of prudently incurred hazardous substance remediation costs through ratemaking procedures approved by the CPUC. The Company has recorded a regulatory asset at December 31, 1996, of $146 million for recovery of these costs in future rates. Additionally, PG&E will seek recovery of costs from insurance carriers and from other third parties. In 1992, PG&E 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. PG&E had previously notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In the main, PG&E's carriers neither admitted nor denied coverage, but requested additional information from PG&E. Although PG&E has received some amounts in settlements with certain of its insurers, the ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time. COMPRESSOR STATION LITIGATION In 1996, litigation brought against PG&E relating to alleged chromium contamination near PG&E's Hinkley Compressor Station was settled for the aggregate sum of $333 million. The Hinkley Compressor Station is located along PG&E's gas transmission system in San Bernardino County, California. The plaintiffs had contended that between 1951 and 1966, PG&E discharged chromium- contaminated wastewater into unlined ponds, which led to chromium percolating into the groundwater of surrounding property. Several other cases have been brought against PG&E seeking damages from alleged chromium contamination at PG&E's Hinkley, Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings--Compressor Station Chromium Litigation" for a description of the pending litigation. ELECTRIC AND MAGNETIC FIELDS In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks which may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled which raises the question of whether adverse health impacts might exist. 36 In November 1993, the CPUC adopted an interim EMF policy for California energy utilities which, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services. As part of its effort to educate the public about EMF, PG&E provides interested customers with information regarding the EMF exposure issue. PG&E also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings. PG&E and other utilities are involved in litigation concerning EMF. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. PG&E is named as a defendant in one pending civil appeal in which plaintiffs allege personal injury resulting from exposure to EMF. In the event that the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility- related EMF exposures can be isolated from other exposures, PG&E may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant depending on the particular mitigation measures undertaken, especially if relocation of existing power lines is ultimately required. LOW EMISSION VEHICLE PROGRAMS In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding which approved approximately $36 million in funding for PG&E's LEV program for the six-year period beginning in 1996. The CPUC's decision on electric industry restructuring finds that the costs of utility LEV programs should continue to be collected by the utility for the duration of the six-year period. 37 FORMATION OF PG&E CORPORATION As previously noted, effective January 1, 1997, PG&E Corporation became the parent holding company of PG&E. PG&E's ownership interest in PGT and Enterprises was transferred to PG&E Corporation. The following financial information summarizes certain pro forma financial effects of the restructuring of PG&E. The restructuring resulted in PG&E becoming a separate subsidiary of PG&E Corporation with the present holders of PG&E common stock becoming holders of PG&E Corporation common stock. The pro forma balance sheet is as of December 31, 1996, and the pro forma income statement is for the twelve months ended December 31, 1996, as if the restructuring occurred December 31, 1996, and January 1, 1996, respectively. The restructuring was accounted for as an as-if pooling of interests.
PRO FORMA (UNAUDITED) ---------------------------- PG&E PG&E CONSOLIDATED PRO FORMA PG&E CORPORATION HISTORICAL ADJUSTMENTS(1) CONSOLIDATED(1) CONSOLIDATED ------------ -------------- --------------- ------------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) BALANCE SHEETS--AS OF DECEMBER 31, 1996 ASSETS Net plant in service... $18,594 $(1,176) $17,418 $18,594 Investments and other noncurrent assets..... 2,249 (853) 1,396 2,249 Current assets......... 2,671 (574) 2,097 2,671 Deferred charges....... 2,616 (91) 2,525 2,616 ------- ------- ------- ------- TOTAL ASSETS............ $26,130 $(2,694) $23,436 $26,130 ======= ======= ======= ======= CAPITALIZATION AND LIA- BILITIES CAPITALIZATION Common stock equity... $ 8,363 $(1,142) $ 7,221 $ 8,363 Preferred stock and preferred securities. 840 -- 840 840 Long-term debt........ 7,770 (701) 7,069 7,770 ------- ------- ------- ------- TOTAL CAPITALIZATION... 16,973 (1,843) 15,130 16,973 Current liabilities.... 3,240 (343) 2,897 3,240 Deferred credits and other noncurrent lia- bilities.............. 5,917 (508) 5,409 5,917 ------- ------- ------- ------- TOTAL CAPITALIZATION AND LIABILITIES............ $26,130 $(2,694) $23,436 $26,130 ======= ======= ======= ======= BOOK VALUE PER COMMON SHARE.................. 20.73 20.73 ======= ======= STATEMENTS OF INCOME-- YEAR ENDED DECEMBER 31, 1996 Operating Revenues...... $ 9,610 $ (620) $ 8,990 $ 9,610 Operating Expenses...... 7,714 (537) 7,177 7,714 ------- ------- ------- ------- Operating Income........ 1,896 (83) 1,813 1,896 Interest Income......... 73 (3) 70 73 Interest Expense........ (640) 32 (608) (640) Other Income and (Ex- pense)................. (19) 10 (9) (19) Preferred Dividend Re- quirements of PG&E..... -- -- -- 33(2) ------- ------- ------- ------- Pretax Income........... 1,310 (44) 1,266 1,277 Income Taxes............ 555 (29) 526 555 ------- ------- ------- ------- Net Income.............. 755 (15) 740 722 ======= ======= Preferred Dividend Re- quirements............. 33 33(2) -- ------- ======= ------- Earnings Available for Common Shares.......... $ 722 $ 722 ======= ======= Earnings per Common Share.................. $ 1.75 $ 1.75 ======= =======
- -------- (1) Reflects transfer of PGT and Enterprises from PG&E to PG&E Corporation in connection with restructuring. (2) Reflects dividends associated with PG&E Preferred Stock as a charge against retained earnings for PG&E and as a charge against net income for PG&E Corporation. 38 ITEM 2. PROPERTIES. Information concerning PG&E's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of PG&E are subject to the lien of an indenture which provides security to the holders of PG&E's First and Refunding Mortgage Bonds. 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 is subject to routine litigation incidental to its business. ANTITRUST LITIGATION On December 3, 1993, the County of Stanislaus and Mary Grogan, a residential customer of PG&E, filed a complaint in the U.S. District Court, Eastern District of California, against PG&E and PGT, on behalf of themselves and purportedly as a class action on behalf of all natural gas customers of PG&E during the period of February 1988 through October 1993. The complaint alleged that the purchase of natural gas in Canada was accomplished in violation of various antitrust laws and sought damages of as much as $950 million, before trebling. In August 1994, the District Court dismissed plaintiffs' antitrust claims, and in September 1994, the plaintiffs filed an amended complaint which added Alberta and Southern Gas Co. Ltd., PG&E's gas purchasing subsidiary, as a defendant. The amended complaint reiterated price fixing claims and also alleged that the defendants, through anticompetitive practices, foreclosed access over the PGT pipeline to alternative sources of gas in Canada. On December 18, 1995, the District Court dismissed the plaintiffs' amended complaint with prejudice. In dismissing the lawsuit, the District Court determined that plaintiffs were barred from making price fixing allegations because gas rates had been reviewed by various federal authorities and the CPUC. The District Court also found that plaintiffs were barred from making foreclosure of access claims because the volume of imports of gas had been reviewed by federal authorities, and the CPUC had actively overseen the allocation of pipeline capacity. Plaintiffs have filed an appeal with the Court of Appeals. The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position. COUNTIES FRANCHISE FEES LITIGATION On March 31, 1994, the Counties of Alameda and Santa Clara filed a complaint in Santa Clara County Superior Court against PG&E on behalf of themselves and purportedly as a class action on behalf of 47 counties with which PG&E has gas or electric franchise contracts. Franchise contracts require PG&E to pay fees on an annual basis to cities and counties for the right to use or occupy public streets and roads. The complaint alleges that, since at least 1987, PG&E has intentionally underpaid its franchise fees to the counties in an unspecified amount. The complaint cites two reasons for the alleged underpayment of fees. Based on their interpretation of certain legislation, the plaintiffs allege that PG&E has been using the wrong methodology to compute the franchise fees payable to the plaintiff counties. The plaintiffs also allege that fees have been underpaid due to incorrect calculations under the methodology used by PG&E. The parties agreed to stipulate to this case proceeding as a class action lawsuit regarding the issue of the correct payment methodology to be applied in calculating the franchise fees due to the plaintiffs. On March 14, 1995, the Superior Court granted PG&E's motion for summary judgment in the class action lawsuit. The plaintiffs appealed that ruling and on January 14, 1997, the Court of Appeal upheld the summary judgment 39 in PG&E's favor. The plaintiffs did not seek review of the Court of Appeal's ruling, and accordingly the summary judgment has become final, resolving the issue regarding the payment methodology. Consistent with the agreement between the parties noted above, the plaintiffs refiled a separate action covering just the issue of whether PG&E properly computed its franchise payments, assuming that PG&E has been using the correct methodology. Plaintiffs may now reactivate this case, which had been stayed pending resolution of the challenge to the payment formula. Plaintiffs have not indicated damages to be sought in that separate action, but they are not anticipated to be material. CITIES FRANCHISE FEES LITIGATION On May 13, 1994, the City of Santa Cruz filed a complaint in Santa Cruz County Superior Court against PG&E on behalf of itself and purportedly as a class action on behalf of 107 cities with which PG&E has certain electric franchise contracts. The complaint alleges that, since at least 1987, PG&E has intentionally underpaid its franchise fees to the cities in an unspecified amount. The complaint alleges that PG&E has asked for and accepted electric franchises from the cities included in the purported class, which provide for lower franchise payments than required by franchises granted by other cities in PG&E's service territory. Plaintiff asserts that this was done in an unlawfully discriminatory manner based solely on location. The plaintiff also alleges that the transfer of these franchises to PG&E by its predecessor companies was not approved by the CPUC as required, and, therefore, all such franchise contracts are void. The Court has certified the class of 107 cities in this action, and approved the City of Santa Cruz as the class representative. On September 1, 1995, the Court denied PG&E's motions for summary judgment and class decertification in this case. The Court did bifurcate the issues in the case for trial such that the issue concerning whether PG&E engaged in unlawful discrimination in accepting certain franchise contracts with differing payment formulas would be tried first, to be followed by the issue relating to the validity of PG&E's current franchise contracts with the plaintiff cities. On January 22, 1996, the Court granted PG&E's motion for summary judgment against five class member cities with respect to the cities' claims that the different franchise payment formulas in the 1937 Franchise Act constitute unlawful discrimination. On March 19, 1996, the Court granted PG&E's motion for judgment against the 31 charter cities who are members of the plaintiff class, including the class representative (the City of Santa Cruz). The Court determined that those cities had no basis for their claims against PG&E since their franchise fee structure was of their own choosing as a matter of "home rule" under the California Constitution. At present, 71 general law cities remain as members of the plaintiff class. Given the Court's prior rulings, the only remaining triable issue relates to the validity of PG&E's current franchise contracts with the remaining plaintiffs. Trial has been postponed indefinitely pending plaintiffs' appeal of the rulings against them. Should the cities prevail on the issue of franchise fee calculation methodology, PG&E's annual system-wide city electric franchise fees could increase by approximately $14 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $145 million (exclusive of interest). If the Court's rulings effectively eliminating certain cities' claims become final, PG&E's potential damages and increased fees would be significantly reduced. In that event, should the remaining plaintiffs prevail, PG&E's annual systemwide city electric franchise fees could increase by approximately $4 million and damages for the remaining plaintiffs for alleged underpayments could be as much as $39 million (exclusive of interest). The ultimate damages and/or increase in fees in any case might vary depending on the Court's interpretation of the plaintiffs' claims. 40 The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. NORCEN LITIGATION In March 1994, Norcen Energy Resources Limited (Norcen Energy) and Norcen Marketing Incorporated (Norcen Marketing) filed a complaint in the U.S. District Court, Northern District of California, against PG&E and PGT. Norcen Marketing has a 30-year gas transportation contract with PGT, which is guaranteed by Norcen Energy. The complaint alleged that PGT and PG&E wrongfully induced Norcen Energy and Norcen Marketing to enter into the 30- year contract by concealing legal action taken by PG&E before the CPUC (requesting clarification that gas shipped on the PGT portion of the Pipeline Expansion should pay PG&E's incremental Expansion rates for in-state service) two days before Norcen Marketing's contract became binding. The complaint also alleged breach of representations to plaintiffs that PG&E would not "unreasonably" build its Pipeline Expansion with less than "sufficient" firm subscription and a breach of an agreement between PGT and a Norcen predecessor relating to the installation of additional capacity. In addition to state law contract claims, the complaint also alleged a series of federal and state antitrust claims related to the construction of the Pipeline Expansion and PG&E's alleged refusals to allow access to the original PGT and California transmission systems. In September 1994, the District Court granted PGT's and PG&E's motion to dismiss all federal antitrust claims in the complaint originally filed in this case, and dismissed the remaining state law claims for lack of jurisdiction. In October 1994, plaintiffs filed an amended complaint. The amended complaint reasserted part of the original complaint's antitrust claims, asserted new antitrust claims based on the same facts, and specifically alleged diversity jurisdiction for the state law contract claims. In July 1995, the District Court issued an order on PG&E's motion to dismiss the amended complaint. The order dismisses all of plaintiffs' federal and state antitrust claims, but does not dismiss various state law contract claims, including claims based on fraudulent inducement and breach of contract. Plaintiffs have the right to appeal the dismissal of the antitrust claims to the Court of Appeals. Plaintiffs still seek rescission of their gas transportation contracts and compensatory and punitive damages in connection with their remaining state law claims. The Company believes plaintiffs in this action might seek contract damages of approximately $100 million in this matter. The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. CALIFORNIA ATTORNEY GENERAL INVESTIGATION In February 1995, the California Attorney General (AG) initiated an investigation to determine whether PG&E and its consultant, Tenera, Inc. (Tenera), violated the Federal Clean Water Act and the California Water Code in connection with a 1988 study of the cooling water intake system at Diablo Canyon (1988 Study). The United States Department of Justice (DOJ) has since joined the AG's investigation. PG&E has been in discussions with the AG and the DOJ concerning the disposition of this matter and related litigation with the League For Coastal Protection and John W. Carter (collectively, the Diablo Canyon Environmental Litigation). See "Diablo Canyon Environmental Litigation" below. In those discussions, the AG and DOJ have indicated their belief that PG&E violated the Federal Clean Water Act, the California Water Code, and other provisions of California law in connection with the 1988 Study. The AG and DOJ have proposed a resolution of these matters that involves the payment by PG&E of civil penalties and mitigation project costs. The Company believes that the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. 41 DIABLO CANYON ENVIRONMENTAL LITIGATION On October 13, 1995, the League for Coastal Protection (Coastal League) filed a lawsuit in San Francisco County Superior Court against PG&E and its consultant, Tenera, alleging violations of the California Business and Professions Code in connection with the 1988 Study. The 1988 Study is also the subject of an investigation by the AG and DOJ, as described above. The Coastal League alleges that PG&E and its consultant violated the law by making misrepresentations in connection with the 1988 Study. The Coastal League seeks an unspecified amount of damages related to restitution or disgorgement of improper or excessive profits, punitive damages, injunctive relief, and attorneys' fees. On April 16, 1996, the Coastal League filed another lawsuit in the United States District Court, Northern District of California, against PG&E and Tenera, alleging violations of the federal Clean Water Act in connection with the 1988 Study. The Coastal League alleges that PG&E and Tenera withheld data from the 1988 Study and submitted misleading information to the state and federal agencies. The Coastal League seeks a judgment that PG&E has violated its discharge permit for Diablo Canyon, revocation of the permit, an order requiring restoration of the marine environment, an unspecified amount of civil penalties, and recovery of its litigation and attorneys' fees. Also on April 16, 1996, PG&E received a copy of a complaint filed in a third case involving the 1988 Study. In this case, John W. Carter (Carter) alleges on behalf of himself and the United States and the State of California that PG&E, Tenera, and certain of their employees violated the federal and state False Claims Acts by filing an incomplete report in 1988 (i.e., the 1988 Study) and failing to correct it. The United States and the State of California have declined to prosecute this action, and it is maintained by Carter, who is represented by the same attorneys representing the Coastal League. The plaintiffs seek civil penalties, treble damages, a separate payment to Carter under the False Claims Acts, and attorneys' fees. See "California Attorney General Investigation" above for a discussion of a possible resolution of this litigation. The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. COMPRESSOR STATION CHROMIUM LITIGATION PG&E has been named as a defendant in several civil actions filed in Southern California courts on behalf of more than 1,500 plaintiffs. These cases are Aguayo v. PG&E, filed March 15, 1995, in Los Angeles County Superior Court; Aguilar v. PG&E, filed October 4, 1996, in Los Angeles County Superior Court; Tate v. PG&E, filed October 29, 1996, in San Bernardino County Superior Court; and Adams v. Betz, filed September 21, 1994, in Los Angeles County Superior Court. In the Adams case, the claims remaining against PG&E arise from a cross-claim filed by Betz Chemical Company (Betz), the supplier of water treatment products containing chromium which are used at the gas compressor stations. All of these cases will be referred to collectively as the "Aguayo Litigation." Each of the complaints in the Aguayo Litigation allege personal injuries and seek compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of PG&E's gas compressor stations at Kettleman, Hinkley, and Topock, California. Betz also is named as a defendant in the Aguayo Litigation. The plaintiffs in the Aguayo Litigation include PG&E employees, former PG&E employees, relatives of PG&E employees or former employees, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations, alleging exposure to chromium at or near the compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim only loss of consortium or injury through the alleged exposure of their parents. PG&E is responding to the complaints and asserting affirmative defenses. PG&E 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. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged, and PG&E 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. 42 The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. 43 EXECUTIVE OFFICERS OF THE REGISTRANT "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 1996 POSITION ---- ------------ -------- S. T. Skinner........ 59 Chairman of the Board and Chief Executive Officer R. D. Glynn, Jr. .... 54 President and Chief Operating Officer J. D. Shiffer**...... 58 Executive Vice President (PG&E) R. J. Haywood........ 52 Senior Vice President and General Manager, Customer Energy Services (PG&E) T. W. High........... 49 Senior Vice President--Corporate Services (PG&E) J. F. Jenkins-Stark.. 45 Senior Vice President and General Manager, Gas Supply Business Unit (PG&E) G. R. Smith.......... 48 Chief Financial Officer B. R. Worthington.... 47 General Counsel J. Pfannenstiel...... 49 Vice President--Corporate Planning (PG&E) *All positions are with PG&E Corporation, unless otherwise noted. **Mr. Shiffer will retire effective April 1, 1997. "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 are as follows*: AGE AT DECEMBER 31, NAME 1996 POSITION ---- ------------ -------- S. T. Skinner........ 59 Chairman of the Board and Chief Executive Officer R. D. Glynn, Jr. .... 54 President and Chief Operating Officer J. D. Shiffer**...... 58 Executive Vice President R. J. Haywood........ 52 Senior Vice President and General Manager, Customer Energy Services T. W. High........... 49 Senior Vice President--Corporate Services J. F. Jenkins-Stark.. 45 Senior Vice President and General Manager, Gas Supply Business Unit G. R. Smith.......... 48 Senior Vice President and Chief Financial Officer B. R. Worthington.... 47 Senior Vice President and General Counsel J. Pfannenstiel...... 49 Vice President--Corporate Planning
*All positions are with PG&E. **Mr. Shiffer will retire effective April 1, 1997. All officers of PG&E Corporation and PG&E serve at the pleasure of the relevant Board of Directors. All executive officers of both companies have been employees of PG&E for the past five years. During that period, the executive officers had the following business experience as PG&E employees and/or officers, and/or PG&E Corporation officers*:
NAME POSITION PERIOD HELD OFFICE ---- -------- ------------------ S.T. Skinner......... Chairman of the Board December 18, 1996 to current and Chief Executive Officer (PG&E Corporation) Chairman of the Board June 1, 1995 to current and Chief Executive Officer President and Chief July 1, 1994 to May 31, 1995 Executive Officer President and Chief November 1, 1991 to June 30, 1994 Operating Officer R.D. Glynn, Jr....... President and Chief December 18, 1996 to current Operating Officer (PG&E Corporation) President and Chief June 1, 1995 to current Operating Officer Executive Vice President July 1, 1994 to May 31, 1995 Senior Vice President January 1, 1994 to June 30, 1994 and General Manager, Customer Energy Services Business Unit Senior Vice President November 1, 1991 to December 31, 1993 and General Manager, Electric Supply Business Unit J.D. Shiffer......... Executive Vice President November 1, 1991 to current
44
NAME POSITION PERIOD HELD OFFICE ---- -------- ------------------ R.J. Haywood......... Senior Vice President December 21, 1994 to current and General Manager, Customer Energy Services Business Unit Vice President of Power February 22, 1993 to December 20, 1994 System Vice President-Power April 20, 1988 to February 21, 1993 Planning and Contracts T.W. High............ Senior Vice President- June 1, 1995 to current Corporate Services Vice President and July 1, 1994 to May 31, 1995 Assistant to the Chief Executive Officer Vice President and November 1, 1991 to June 30, 1994 Assistant to the Chairman of the Board J.F. Jenkins-Stark... Senior Vice President August 1, 1993 to current and General Manager, Gas Supply Business Unit Vice President and January 15, 1992 to July 31, 1993 Treasurer G.R. Smith........... Chief Financial Officer December 18, 1996 to current (PG&E Corporation) Senior Vice President June 1, 1995 to current and Chief Financial Officer Vice President and Chief November 1, 1991 to May 31, 1995 Financial Officer B.R. Worthington..... General Counsel (PG&E December 18, 1996 to current Corporation) Senior Vice President June 1, 1995 to current and General Counsel Vice President and December 21, 1994 to May 31, 1995 General Counsel Chief Counsel-Corporate January 10, 1991 to December 20, 1994
*All positions are with PG&E, unless otherwise noted. 45 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. Information responding to part of Item 5 is set forth on page 42 under the heading "Quarterly Consolidated Financial Data" in the 1996 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. PG&E has made no sales of unregistered equity securities in the last three years. PG&E Corporation has made the following sales of unregistered equity securities during such period: On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common stock. The shares were issued to nine former shareholders of Teco in connection with the acquisition by PG&E Corporation of Teco. PG&E Corporation owns all the outstanding shares of Teco as a result of the acquisition. The shares were issued in reliance upon the exemption from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the former shareholders of Teco represented that they were "accredited investors" as defined in Rule 501(a) under the Securities Act of 1933 and made other representations establishing the basis for the exemption. A legend as provided for by Rule 501 (d)(3) was placed on each of the stock certificates representing the shares of PG&E Corporation common stock received by the former shareholders of Teco. ITEM 6. SELECTED FINANCIAL DATA. A summary of selected financial information for the Company for each of the last five fiscal years is set forth on page 8 under the heading "Selected Financial Data" in the 1996 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. A discussion of the Company's financial condition, changes in financial condition and results of operations is set forth on pages 9 through 19 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Information responding to Item 8 is contained in the 1996 Annual Report to Shareholders on pages 20 through 43 under the headings "Statement of Consolidated Income," "Statement of Consolidated Cash Flows," "Consolidated Balance Sheet," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Statement of Consolidated Capitalization," "Statement of Consolidated Segment Information," "Notes to Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," and "Report of Independent Public Accountants," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Information regarding executive officers of PG&E is included in a separate item captioned "Executive Officers of the Registrant" contained on pages 44 through 45 in Part I of this report. Other information responding to Item 10 is included on pages 2 through 5 under the heading "Election of Directors of PG&E Corporation and PG&E" and page 29 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference. 46 ITEM 11. EXECUTIVE COMPENSATION. Information responding to Item 11 is included on page 8 under the heading "Compensation of Directors" and on pages 19 through 27 under the heading "Executive Compensation" (excluding the sections thereunder entitled "Nominating and Compensation Committee Report on Compensation" and "Comparison of Five-Year Cumulative Total Shareholder Return") in the 1997 Joint Proxy Statement relating to the 1997 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 is included on pages 10 and 28 under the headings "Security Ownership of Management" and "Principal Shareholders" in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information responding to Item 13 is included on page 9 under the heading "Certain Relationships and Related Transactions" in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT: 1. The following consolidated financial statements, schedules of consolidated segment information, supplemental information, and report of independent public accountants contained in the 1996 Annual Report to Shareholders, are incorporated by reference in this report: Statement of Consolidated Income for the Years Ended December 31, 1996, 1995, and 1994. Statement of Consolidated Cash Flows for the Years Ended December 31, 1996, 1995, and 1994. Consolidated Balance Sheet at December 31, 1996, and 1995. Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities for the Years Ended December 31, 1996, 1995, and 1994. Statement of Consolidated Capitalization at December 31, 1996, and 1995. Schedule of Consolidated Segment Information for the Years Ended December 31, 1996, 1995, and 1994. Notes to Consolidated Financial Statements. Quarterly Consolidated Financial Data (Unaudited). Report of Independent Public Accountants. 2. Report of Independent Public Accountants included at page 53 of this Form 10-K. 3. Consolidated financial statement schedules: II -- Consolidated Valuation and Qualifying Accounts for the Years Ended December 31, 1996, 1995 and 1994. 47 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto. 4. Exhibits required to be filed by Item 601 of Regulation S-K: 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1- 12609), Exhibit 3.1). 3.2 By-Laws of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.2). 3.3 Agreement of Merger (PG&E Corporation's Form 8-B (File No. 1- 12609), Exhibit 1). 3.4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of July 26, 1994 (PG&E's Form 10-Q, for quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1). 3.5 By-Laws of Pacific Gas and Electric Company as of January 1, 1997. 4. First and Refunding Mortgage of PG&E dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2- 1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B- 22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; PG&E's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). 10.1 Firm Transportation Service Agreement between PG&E and Pacific Gas Transmission Company dated October 26, 1993 (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and general terms and conditions. 10.2 Transportation Service Agreement as Amended and Restated between PG&E and El Paso Natural Gas Company dated November 1, 1993 (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate schedule FT-1, and general terms and conditions. (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348, Exhibit 10.2). 10.3 Diablo Canyon Settlement Agreement (Diablo Settlement) dated June 24, 1988 (PG&E's Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1), Implementing Agreement dated July 15, 1988 (PG&E's Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1), portions of the California Public Utilities Commission Decision No. 88-12-083, dated December 19, 1988, interpreting the Diablo Settlement (PG&E's Form 10-K for fiscal year 1988 (File No. 1-2348), Exhibit 10.4) and Settlement Agreement dated December 14, 1994, modifying the Diablo Settlement (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.3). *10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (PG&E's Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5). *10.5 PG&E Corporation Deferred Compensation Plan for Directors. (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.5)
- -------- * 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. 48 *10.6 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6). *10.7 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to non-union employees, as amended and restated effective as of January 1, 1997 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.7). *10.8 Short-Term Incentive Plan for Officers of Pacific Gas and Electric Company, effective January 1, 1996 (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.7). *10.9 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended October 18, 1995, effective January 1, 1996 (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.8). *10.10 Pacific Gas and Electric Company Supplemental Executive Retirement Plan, as amended through October 16, 1991 (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11). *10.11 Pacific Gas and Electric Company Relocation Assistance Program for Officers (PG&E's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.12 Pacific Gas and Electric Company Executive Flexible Perquisites Program (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16). *10.13 PG&E Postretirement Life Insurance Plan (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). *10.14 PG&E Corporation Retirement Plan for Non-Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.14). *10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.15). *10.16 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19). *10.17 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of January 1, 1997, including the PG&E Corporation Stock Option Plan, Performance Unit Plan and Restricted Stock Plan for Non-Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.17). 11. Computation of Earnings Per Common Share. 12.1 Computation of Ratios of Earnings to Fixed Charges. 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
- -------- * 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. 49 13. 1996 Annual Report to Shareholders (portions of the 1996 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data," included only) (except for those portions which are expressly incorporated herein by reference, such 1996 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein). 21. Subsidiaries of the Registrants. 23. Consent of Arthur Andersen LLP. 24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K. 24.2 Powers of Attorney. 27. Financial Data Schedule.
The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission as indicated and are hereby incorporated by reference. Exhibits will be furnished to security holders of the Company upon written request and payment of a fee of $0.30 per page, which fee covers only the Company's reasonable expenses in furnishing such exhibits. The Company agrees 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 during the quarter ended December 31, 1996 and through the date hereof: 1. October 16, 1996(1) Item 5. Other Events -- Performance Incentive Plan -- Year-to-Date Financial Results -- Common Stock Dividend Reduction 2. November 22, 1996(1) Item 5. Other Events -- Acquisitions and Dispositions 3.December 20, 1996(1) Item 5. Other Events -- Performance Incentive Plan -- 1997 Target 4. January 2, 1997(1)(2) Item 5. Other Events -- Holding Company Formation 5. January 7, 1997(1)(2) Item 5. Other Events -- Electric Industry Restructuring -- 1997 ECAC 6.January 16, 1997(1)(2) Item 5. Other Events --Performance Incentive Plan -- Year-to-Date Financial Results --1996 Consolidated Earnings (unaudited) 50 7.January 31, 1997(1)(2) Item 5. Other Events --Acquisition of Valero Energy Corporation --Acquisition of Teco Pipeline Company --Electric Industry Restructuring Cost Recovery Plan 8.February 19, 1997(1)(2) Item 7. Financial Statements, Pro Forma Financial Information and Exhibits --1996 Financial Statements 9.March 3, 1997(1)(2) Item 5. Other Events --Proposed Decision on Diablo Canyon Ratemaking Proposal - -------- (1)Filed under Commission File Number 1-2348 (PG&E) (2)Filed under Commission File Number 1-12609 (PG&E Corporation) 51 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 4TH DAY OF MARCH, 1997. PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant) GARY P. ENCINAS 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 REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE --------- ----- ---- A. PRINCIPAL EXECUTIVE OFFICER OR OFFICERS *STANLEY T. SKINNER Chairman of the Board, March 4, 1997 Chief Executive Officer, and Director (PG&E Corporation) Chairman of the Board, Chief Executive Officer, and Director (Pacific Gas and Electric Company) B. PRINCIPAL FINANCIAL OFFICER *GORDON R. SMITH Chief Financial Officer March 4, 1997 (PG&E Corporation) Senior Vice President and Chief Financial Officer (Pacific Gas and Electric Company) C. PRINCIPAL ACCOUNTING OFFICER *CHRISTOPHER P. JOHNS Controller (PG&E Corporation) March 4, 1997 Vice President and Controller (Pacific Gas and Electric Company) D. DIRECTORS *RICHARD A. CLARKE *H. M. CONGER *C. LEE COX *ROBERT D. GLYNN, JR. *DAVID M. LAWRENCE *RICHARD B. MADDEN Directors (PG&E Corporation and March 4, 1997 *MARY S. METZ Pacific Gas and Electric *REBECCA Q. MORGAN Company) *SAMUEL T. REEVES *CARL E. REICHARDT *JOHN C. SAWHILL *ALAN SEELENFREUND *BARRY LAWSON WILLIAMS
GARY P. ENCINAS *By ________________________________ (Gary P. Encinas, Attorney-in- Fact) 52 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and the Board of Directors of PG&E Corporation: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in the PG&E Corporation Annual Report to Shareholders incorporated by reference in this Annual Report on Form 10-K, and have issued our report thereon dated February 10, 1997. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed in Part IV, Item 14. (a)(3) of this Annual Report on Form 10-K is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. The schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states 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 ARTHUR ANDERSEN LLP San Francisco, California February 10, 1997 53 SCHEDULE II PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS ----------------- BALANCE CHARGED BALANCE AT TO COSTS CHARGED AT END BEGINNING AND TO OTHER OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ----------- --------- -------- -------- ---------- -------- (IN THOUSANDS) VALUATION AND QUALIFYING ACCOUNTS DEDUCTED FROM ASSETS: 1996: Reserve for deferred project costs............ $ 5,710 $ -- $ -- $ 5,710(1) $ 0 ======= ======= ====== ======= ======= Allowance for uncollectible accounts... $35,520 $55,566 $1,836 $35,018(2) $57,904 ======= ======= ====== ======= ======= Reserve for land costs.... $ 4,444 $ -- $ -- $ 4,444(1) $ 0 ======= ======= ====== ======= ======= 1995: Reserve for impairment of oil and gas properties... $ 4,341 $ -- $ -- $ 4,341(3) $ 0 ======= ======= ====== ======= ======= Reserve for deferred project costs............ $25,800 $ -- $ -- $20,090(1) $ 5,710 ======= ======= ====== ======= ======= Allowance for uncollectible accounts... $29,769 $50,327 $ -- $44,576(2) $35,520 ======= ======= ====== ======= ======= Reserve for land costs.... $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444 ======= ======= ====== ======= ======= 1994: Reserve for impairment of oil and gas properties... $ 7,924 $ 4,565 $ -- $ 8,148(3) $ 4,341 ======= ======= ====== ======= ======= Reserve for deferred project costs............ $18,689 $ 7,111 $ -- $ -- $25,800 ======= ======= ====== ======= ======= Allowance for uncollectible accounts... $23,647 $44,415 $ -- $38,293(2) $29,769 ======= ======= ====== ======= ======= Reserve for land costs.... $ 6,154 $ -- $ -- $ 194(1) $ 5,960 ======= ======= ====== ======= =======
- -------- (1) Deductions consist principally of write-offs. Reserve for deferred project costs is classified on the balance sheet in other deferred charges. Reserve for land costs is classified on the balance sheet in investment in nonregulated projects. (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. (3) Deductions consist principally of write-offs of expired leaseholds on reserved property. Deduction in 1995 results from sale of oil and gas properties. 54 INDEX TO EXHIBITS EXHIBIT DESCRIPTION OF EXHIBITS NUMBER ----------------------- ------- 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.1). 3.2 By-Laws of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.2). 3.3 Agreement of Merger (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 1). 3.4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of July 26, 1994 (PG&E's Form 10-Q, for quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1). 3.5 By-Laws of Pacific Gas and Electric Company as of January 1, 1997. 4. First and Refunding Mortgage of PG&E dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2- 10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; PG&E's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). 10.1 Firm Transportation Service Agreement between PG&E and Pacific Gas Transmission Company dated October 26, 1993 (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and general terms and conditions. 10.2 Transportation Service Agreement as Amended and Restated between PG&E and El Paso Natural Gas Company dated November 1, 1993 (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate schedule FT-1, and general terms and conditions. (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348, Exhibit 10.2). 10.3 Diablo Canyon Settlement Agreement (Diablo Settlement) dated June 24, 1988 (PG&E's Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1), Implementing Agreement dated July 15, 1988 (PG&E's Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1), portions of the California Public Utilities Commission Decision No. 88-12-083, dated December 19, 1988, interpreting the Diablo Settlement (PG&E's Form 10-K for fiscal year 1988 (File No. 1-2348), Exhibit 10.4) and Settlement Agreement dated December 14, 1994, modifying the Diablo Settlement (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.3). *10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (PG&E's Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5). *10.5 PG&E Corporation Deferred Compensation Plan for Directors. (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.5). *10.6 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6). *10.7 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to non-union employees, as amended and restated effective as of January 1, 1997 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.7). *10.8 Short-Term Incentive Plan for Officers of Pacific Gas and Electric Company, effective January 1, 1996 (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.7).
- -------- * 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. EXHIBIT DESCRIPTION OF EXHIBITS NUMBER ----------------------- ------- *10.9 The Pacific Gas and Electric Company Retirement Plan applicable to non- union employees, as amended October 18, 1995, effective January 1, 1996 (PG&E's Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.8). *10.10 Pacific Gas and Electric Company Supplemental Executive Retirement Plan, as amended through October 16, 1991 (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11). *10.11 Pacific Gas and Electric Company Relocation Assistance Program for Officers (PG&E's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.12 Pacific Gas and Electric Company Executive Flexible Perquisites Program (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16). *10.13 PG&E Postretirement Life Insurance Plan (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). *10.14 PG&E Corporation Retirement Plan for Non-Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.14). *10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.15). *10.16 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non- Employee Directors (PG&E's Form 10-K for fiscal year 1991 (File No. 1- 2348), Exhibit 10.19). *10.17 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of January 1, 1997, including the PG&E Corporation Stock Option Plan, Performance Unit Plan and Restricted Stock Plan for Non- Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.17). 11. Computation of Earnings Per Common Share. 12.1 Computation of Ratios of Earnings to Fixed Charges. 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends. 13. 1996 Annual Report to Shareholders (portions of the 1996 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data," included only) (except for those portions which are expressly incorporated herein by reference, such 1996 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein). 21. Subsidiaries of the Registrants. 23. Consent of Arthur Andersen LLP. 24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K. 24.2 Powers of Attorney. 27. Financial Data Schedule.
- -------- * 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. EX-3.5 2 BYLAWS OF PG&E AS AMENDED 1/1/97 EXHIBIT 3.5 BYLAWS OF PACIFIC GAS AND ELECTRIC COMPANY AS AMENDED AS OF JANUARY 1, 1997 -------------------------------- ARTICLE I. SHAREHOLDERS. 1. PLACE OF MEETING. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place within the State of California as may be designated by the Board of Directors. 2. ANNUAL MEETINGS. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. 3. SPECIAL MEETINGS. Special meetings of the shareholders shall be called by the Secretary or an Assistant Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Secretary or an Assistant Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President or the Secretary. 1 A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. 4. ATTENDANCE AT MEETINGS. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Secretary of the Corporation prior to the commencement of the meeting. 5. NO CUMULATIVE VOTING. No shareholder of the Corporation shall be entitled to cumulate his or her voting power. ARTICLE II. DIRECTORS. 1. NUMBER. The Board of Directors shall consist of sixteen (16) directors. 2. POWERS. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. EXECUTIVE COMMITTEE. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 4. TIME AND PLACE OF DIRECTORS' MEETINGS. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 2 5. SPECIAL MEETINGS. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first- class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. QUORUM. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. 7. ACTION BY CONSENT. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. MEETINGS BY CONFERENCE TELEPHONE. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. ARTICLE III. OFFICERS. 1. OFFICERS. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, one or more Vice Presidents, a Secretary and one or more Assistant Secretaries, a Treasurer and one or more Assistant Treasurers, a General Counsel, a General Attorney (whenever the Board of Directors in its discretion fills this office), and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. CHAIRMAN OF THE BOARD. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the President, shall exercise his duties and responsibilities. 3. VICE CHAIRMAN OF THE BOARD. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of 3 the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. CHAIRMAN OF THE EXECUTIVE COMMITTEE. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. PRESIDENT. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. VICE PRESIDENTS. Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 7. SECRETARY. The Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Secretary. In the absence or disability of the Secretary, his duties shall be performed by an Assistant Secretary. 8. TREASURER. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. 4 The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 9. GENERAL COUNSEL. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 10. CONTROLLER. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. He shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors. ARTICLE IV. MISCELLANEOUS. 1. RECORD DATE. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 5 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. 6 EX-10.1 3 PGT RATE SCHED. FTS AND GENERAL CONDITIONS Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 12 First Revised Volume No. 1-A Superseding First Revised Sheet No. 12 ________________________________________________________________________________ EXHIBIT 10.1 RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE 1. AVAILABILITY This rate schedule is available to any party (hereinafter called "Shipper") qualifying for service pursuant to the Commission's Regulations contained in 18 CFR Part 284, and who has executed a Firm Transportation Service Agreement with PGT in the form contained in this FERC Gas Tariff First Revised Volume No. 1-A. 2. APPLICABILITY AND CHARACTER OF SERVICE This rate schedule shall apply to firm gas transportation services performed by PGT for Shipper pursuant to the executed Firm Transportation Service Agreement between PGT and Shipper. PGT shall receive from Shipper such daily quantities of gas up to the Shipper's Maximum Daily Quantity as specified in the executed Firm Transportation Service Agreement between PGT and Shipper plus the required quantity of gas for fuel and line loss associated with service under this Rate Schedule FTS-1 and redeliver an amount equal to the quantity received less the required quantity of gas for fuel and line loss. This transportation service shall be firm and not subject to curtailment or interruption except as provided in the Transportation General Terms and Conditions. Firm transportation service shall be subject to all provisions of the executed Firm Transportation Service Agreement between PGT and Shipper and the applicable Transportation General Terms and Conditions. 3. RATES Shipper shall pay PGT each month the sum of the Reservation Charge, the Delivery Charge, plus any applicable Extension Charge, Overrun Charge and applicable surcharges for the quantities of natural gas delivered. The rate(s) set forth in PGT's current Statement of Effective Rates and Charges for Transportation of Natural Gas in this FERC Gas Tariff First Revised Volume No. 1-A are applied to transportation service rendered under this rate schedule. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 13 First Revised Volume No. 1-A Superseding First Revised Sheet No. 13 ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3.RATES (Continued) 3.1 Reservation Charge The Reservation Charge shall be the sum of the Mileage and the Non- Mileage Component: (a) Mileage Component The Mileage Component shall be the product of the currently effective Mileage Rate as set forth on Effective Tariff Sheet No. 4, the distance, in pipeline miles, from the Primary Point(s) of receipt to the Primary Point(s) of Delivery on Mainline Facilities as set forth in Shipper's Contract, and the Shipper's Maximum Daily Quantity at such Point(s). (b) Non-Mileage Component The Non-Mileage Component shall be the product of the currently effective Non-Mileage Rate as set forth on Effective Tariff Sheet No. 4 and the Shipper's Maximum Daily Quantity at Primary Point(s) of Delivery on Mainline Facilities. (c) Mitigation Revenue Recovery Surcharge If Shipper is a Subject Shipper, the Mitigation Revenue Recovery Surcharge for the Mileage and Non-Mileage Components as set forth on Effective Tariff Sheet No. 4 shall be included in, and become a part of, the maximum Mileage and Non-Mileage Base Reservation Rates used for computing the Mileage and Non-Mileage Components of the Reservation Charge. The Mileage Component shall be designed to recover, on the basis of the mileage billing determinants of the Subject Shippers underlying PGT's currently effective rates, mileage mitigation revenues not recovered from other shippers in accordance with Article IV, Section 1(b) of the Stipulation and Agreement in Docket No. RP94-149-000, et al., and the Non-Mileage Component shall be designed to recover, on the basis of the Non-Mileage billing determinants of the Subject Shippers underlying PGT's currently effective rates, Non-Mileage mitigation revenues not recovered from other shippers in accordance with Article IV, Section 1(b) of the Stipulation and Agreement in Docket No. RP94-149-000, et al. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 13A First Revised Volume No. 1-A ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3.RATES (Continued) 3.1 Reservation Charge (Continued) (d) Shipper's obligation to pay the Reservation Charge and applicable Reservation Surcharge is independent of Shipper's ability to obtain export authorization from the National Energy Board of Canada, Canadian provincial removal authority, and/or import authorization from the United States Department of Energy, and shall begin with the execution of the Firm Transportation Service Agreement by both parties. The Reservation Charge and Reservation Surcharge due and payable shall be computed beginning in the month in which service is first available (prorated if beginning in the month in which service is available on a date other than the first day of the month). Thereafter, the monthly Reservation Charge and Reservation Surcharge shall be due and payable each month during the Initial (and Subsequent) Term(s) of the Shipper's executed Firm Transportation Service Agreement and is unaffected by the quantity of gas transported by PGT to Shipper's delivery point(s) in any month except as provided for in Paragraphs 3.10 and 3.11 of this rate schedule. 3.2 Delivery Charge The Delivery Charge shall be the product of the Delivery Rate as set forth on Effective Tariff Sheet No. 4, the quantities of gas delivered in the month (in MMBtu) (excluding Authorized Overrun) at point(s) of delivery on Mainline Facilities, and the distance, in pipeline miles, from the point(s) of receipt to point(s) of delivery on Mainline Facilities. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 14 First Revised Volume No. 1-A Superseding First Revised Sheet No. 14 ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.3 Extension Charge If Shipper designates a Primary Point of delivery on an Extension Facility, then in addition to all other charges that are applicable, Shipper shall pay the Extension Charge, which shall consist of a reservation and delivery component. (a) The reservation component of the Extension Charge shall be the product of Shipper's Maximum Daily Quantity at the Primary Point(s) of delivery on the Extension Facility, the applicable Extension reservation rate as set forth on Effective Tariff Sheet No. 4, and the distance, in pipeline miles, from the Receipt Point(s) on the Extension Facility to the Primary Point(s) of delivery. (b) The delivery component of the Extension Surcharge shall be the product of the quantities delivered at the point(s) of delivery on the Extension Facility, the applicable Extension delivery rate as set forth on Effective Tariff Sheet No. 4, and the distance, in pipeline miles, from the Receipt Point(s) on the Extension Facility to the point(s) of delivery. 3.4 Authorized Overrun Charge Quantities in excess of Shipper's MDQ shall be transported when capacity is available on the PGT system and when the provision of such Authorized Overruns shall not effect any Shipper's rights on the PGT System. Authorized Overruns are interruptible in nature. The rate charged shall be the same as the rates and charges for interruptible transportation under Rate Schedule ITS-1 as set forth on effective tariff Sheet No. 4, and such Authorized Overruns shall be subject to the priority of service provisions of Paragraph 19 of the Transportation General Terms and Conditions. 3.5 Applicability of Surcharges Shipper shall pay all reservation and usage surcharges applicable to the service provided to such Shipper as set forth in PGT's FERC Gas Tariff, First Revised Volume No. 1-A. Such surcharges shall be deemed to be part of Shipper's Reservation and Delivery Charges. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 14A First Revised Volume No. 1-A ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.6 Shipper shall pay the Reservation Charge, and the Maximum Delivery Charge for service under this Rate Schedule unless PGT offers to discount the Mileage Rate components or the Non-Mileage Rate components of the Reservation Rate or the Delivery Rate or the GRI surcharge under this rate schedule. If PGT elects to discount any such rate, PGT shall, up to forty-eight (48) hours prior to such discount, by written notice, advise Shipper of the effective date of such charges and the quantity of gas so affected; provided, however, such discount shall not be anticompetitive or unduly discriminatory between individual shippers. The rates for service under this rate schedule shall not be discounted below the Minimum Reservation Charge, the Minimum Delivery Rate, and applicable GSR and ACA Surcharges. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 15 First Revised Volume No. 1-A Superseding Original Sheet No. 15 ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.7 Gas Supply Restructuring (GSR) Transition Cost Surcharge Shipper shall pay a GSR Transition Cost Surcharge for PGT's approved GSR costs as defined in Paragraph 30 of the Transportation General Terms and Conditions. This surcharge is stated on the Statement of Effective Rates and Charges and is defined in Paragraph 30 of the Transportation General Terms and Conditions. The surcharge shall be the product of the surcharge rate, the quantities of gas delivered during the month and the distance in pipeline miles from the point(s) of receipt to the point(s) of delivery. 3.8 Backhauls or upstream deliveries shall be subject to the same charges as forward haul or downstream transportation arrangements except that no gas shall be retained by PGT for compressor station fuel, line loss and other unaccounted-for gas. 3.9 Direct Bills PG&E shall pay a Direct Bill for 100% of the costs allocated to the Direct Bill portion of Approved Gas Supply Restructuring (GSR) Costs excluding the amount to be collected from the Northwest Shippers as defined in Paragraph 30 of the Transportation General Terms and Conditions and credited against the Direct Bill portion of Approved GSR Costs as defined in Paragraph 30 of the Transportation General Terms and Conditions. In accordance with Paragraph 30.5(b) of the Transportation General Terms and Conditions, PG&E may elect to pay its Direct Bill in a lump sum or select one of three payment plans as shown on the Statement of Rates and Charges for Transportation of Natural Gas. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 16 First Revised Volume No. 1-A Superseding Original Sheet No. 16 ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.10 Capacity Release (a) Releasing Shippers: Shipper shall have the option to release capacity pursuant to the provisions of PGT's capacity release program as specified in the Transportation General Terms and Conditions. Shipper may release its capacity, up to Shipper's Maximum Daily Quantity under this rate schedule, in accordance with the provisions of Paragraph 28 of PGT's Transportation General Terms and Conditions of this FERC Gas Tariff, First Revised Volume No. 1- A. Shipper shall pay a fee associated with the marketing of capacity by PGT (if applicable) in accordance with Paragraph 28 of the Transportation General Terms and Conditions. This fee shall be negotiated between PGT and the Releasing Shipper. (b) Replacement Shippers: Shipper may receive released capacity service under this rate schedule pursuant to Paragraph 28 of the Transportation General Terms and Conditions and is required to execute a service agreement in the form contained for capacity release under Rate Schedule FTS-1 in this First Revised Volume No. 1-A. Shipper shall pay PGT each month for transportation service under this rate schedule and as set forth in PGT's current Statement of Effective Rates and Charges in this First Revised Volume No. 1-A. Charges to be paid shall be the sum of the Reservation Charge, Delivery Charge, and other applicable surcharges or penalties. The rates paid by Shipper receiving capacity release transportation service shall be adjusted as provided on Exhibit R in the executed Transportation Service Agreement For Capacity Release between PGT and Shipper. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 16A First Revised Volume No. 1-A Superseding First Revised Sheet No. 16A ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3.11 Reservation Charge Credit - Malin Primary Delivery Point If PGT fails to deliver to Malin, Oregon ninety-five percent (95%) or more of the aggregate Confirmed Daily Nominations (as hereinafter defined) of all Shippers with a Malin primary delivery point receiving service under this rate schedule (hereinafter referred to as the "Non- Deficiency Amount") for more than twenty-five (25) days in any given Contract Year, then for each day during that Contract Year in excess of twenty-five (25) days that PGT so fails to deliver the Non-Deficiency Amount (a "Credit Day") Shipper, as its sole remedy, shall be entitled to a Reservation Charge Credit calculated in the manner hereinafter set forth. For the purpose of this Paragraph 3.10, Confirmed Daily Nomination shall mean for any day, the lesser of (1) Shipper's Maximum Daily Quantity or (2) the actual quantity of gas that the connecting pipeline upstream of PGT is capable of delivering for Shipper's account to PGT at Shipper's primary point of receipt(s) on PGT less Shipper's requirement to provide compressor fuel and line losses under the Statement of Effective Rates and Charges of PGT's FERC Gas Tariff, First Revised Volume No. 1-A or (3) the quantity of gas that Pacific Gas And Electric Company (PG&E) is capable of accepting at Malin for Shipper's account or (4) Shipper's nomination to PGT. The Reservation Charge Credit for each Credit Day for a particular Shipper shall be computed as follows: Reservation Charge A B - C Credit for Each ____ x _____ Credit Day = 30.4 B where A = Shipper's Monthly Reservation Charge B = Shipper's confirmed daily nomination for the Credit Day C = Actual quantity of gas delivered by PGT to PG&E at Malin for Shipper's account for the Credit Day Except as provided for in Paragraph 3.11 of this rate schedule, this Reservation Charge Credit is Shipper's sole remedy for nondelivery of gas by PGT. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 16B First Revised Volume No. 1-A Superseding First Revised Sheet No. 16B ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3.12 Reservation Charge Credit - Other than Malin Primary Delivery Point If PGT fails to deliver to a primary delivery point on its system other than Malin, Oregon, ninety-five percent (95%) or more of the aggregate Confirmed Daily Nominations (as hereinafter defined) of all Shippers at such primary delivery point other than Malin receiving service under this rate schedule (hereinafter referred to as the "Non-Deficiency Amount") for more than twenty-five (25) days in any given Contract Year, then for each day during that Contract Year in excess of twenty-five (25) days that PGT so fails to deliver the Non-Deficiency Amount (a "Credit Day") Shipper, as its sole remedy, shall be entitled to a Reservation Charge Credit calculated in the manner hereinafter set forth. For the purpose of this Paragraph 3.11, Confirmed Daily Nomination shall mean for any day, the lesser of (1) Shipper's Maximum Daily Quantity or (2) the quantity of gas that the connecting downstream pipeline(s), local distribution company pipeline(s), or end-user(s) is/are capable of accepting for Shipper's account at Shipper's point(s) of primary delivery on PGT or (3) the quantity of gas that the connecting pipeline upstream of PGT is capable of delivering to PGT for Shipper's account to PGT at Shipper's primary point of receipt(s) on PGT less Shipper's requirement to provide compressor fuel and line losses under the Statement of Effective Rates and Charges of PGT's FERC Gas Tariff, First Revised Volume No. 1-A or (4) Shipper's nomination to PGT. The Reservation Charge Credit for each Credit Day for a particular Shipper shall be computed as follows: Reservation Charge A B - C Credit for Each ____ x _____ Credit Day = 30.4 B where A = Shipper's Monthly Reservation Charge B = Shipper's confirmed daily nomination for the Credit Day C = Actual quantity of gas delivered by PGT to a Shipper's primary delivery point(s) (other than Malin) for Shipper's account for the Credit Day Except as provided for in Paragraph 3.10 of this rate schedule, this Reservation Charge Credit is Shipper's sole remedy for nondelivery of gas by PGT. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Third Revised Sheet No. 17 First Revised Volume No. 1-A Superseding Second Revised Sheet No. 17 ________________________________________________________________________________ RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 4. FUEL AND LINE LOSS Shipper shall furnish to PGT quantities of gas for compressor station fuel, line loss and other utility purposes, plus other unaccounted for gas used in the operation of PGT's combined pipeline system between the International Boundary near Kingsgate, British Columbia and the Oregon-California boundary for the transportation quantities of gas delivered by PGT to Shipper, based upon the effective fuel and line loss percentages in accordance with Paragraph 37 of the General Terms and Conditions. 5. TRANSPORTATION GENERAL TERMS AND CONDITIONS All of the Transportation General Terms and Conditions are applicable to this rate schedule, unless otherwise stated in the executed Firm Transportation Service Agreement between PGT and Shipper. Any future modifications, additions or deletions to said Transportation General Terms and Conditions, unless otherwise provided, are applicable to firm transportation service rendered under this rate schedule, and by this reference, are made a part hereof. ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Eighth Revised Sheet No. 51 First Revised Volume No. 1-A Superseding Seventh Revised Sheet No. 51 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS TABLE OF CONTENTS
Paragraph No. Provision Sheet No. 1 Definitions 52 2 Gas Research Institute Charge Adjustment Provision 55 3 Quality of Gas 56 4 Measuring Equipment 58 5 Measurements 60 6 Inspection of Equipment and Records 61 7 Billing 61 8 Payment 62 9 Reserved 63 10 Force Majeure 63 11 Warranty of Eligibility for Transportation 64 12 Possession of Gas and Responsibility 64 13 Indemnification 65 14 Arbitration 65 15 Governmental Regulations 66 16 Miscellaneous Provision 66 17 Transportation Service Agreement 66 18 Operating Provisions 67 19 Priority of Service, Scheduling and Nominations 81 20 Curtailment 81C 21 Balancing 82 22 Annual Charge Adjustment (ACA) Provision 85 23 Shared Operating Personnel and Facilities 85 24 Complaint Procedures 86 25 Information Concerning Availability and Pricing of Transportation Service and Capacity Available for Transportation 87 26 Market Centers 88 27 Planned PGT Capacity Curtailments and Interruptions 88A 28 Capacity Release 89 29 Flexible Receipt and Delivery Points 119 30 Gas Supply Restructuring Transition Costs 123 31 Reserved 127 32 Equality of Transportation Service 129 33 Right of First Refusal Upon Termination of Firm Shipper's Service Agreement 130 34 Electronic Bulletin Board 132 35 Reserved 137 35A Crediting of Interruptible Transportation Revenues for Extensions 138A 36 Discount Policy 139 37 Adjustment Mechanism for Fuel, Line Loss and Other Unaccounted For Gas Percentages 140 38 Reserved 142 39 Sales of Excess Gas 143 (Continued)
________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 13, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 52 First Revised Volume No. 1-A Superseding First Revised Sheet No. 52 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS 1.1 The word "day" shall mean a period of twenty-four (24) consecutive hours, beginning and ending at 7:00 o'clock a.m. Pacific Standard Time or such other time as Shipper and PGT may agree upon. 1.2 The word "month" shall mean a period extending from the beginning of the first day in a calendar month to the beginning of the first day in the next succeeding calendar month. 1.3 The term "Maximum Daily Quantity" (MDQ) shall mean the maximum daily quantity in MMBtu of gas which PGT agrees to deliver exclusive of an allowance for compressor station fuel, line loss and other unaccounted for gas and transport for the account of Shipper to Shipper's point(s) of delivery on each day during each year during the term of Shipper's Transportation Service Agreement with PGT. 1.4 The term "marketing affiliate" shall mean Pacific Gas and Electric Company and Hermiston Generating Company, L.P. 1.5 The word "gas" shall mean natural gas. 1.6 The term "cubic foot of gas" shall mean that quantity of gas which, at a temperature of sixty degrees (60/./) Fahrenheit and at a pressure of 14.73 pounds per square inch absolute, occupies one (1) cubic foot. 1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet of gas and shall be measured as set forth in Paragraph 5 hereof. The term "MMcf" shall mean one million (1,000,000) cubic feet of gas. 1.8 The term "Btu" shall mean British Thermal Unit. The term "MMBtu" shall mean one million (1,000,000) British Thermal Units. 1.9 The term "gross heating value" shall mean the number of Btu's in a cubic foot of gas at a temperature of sixty degrees (60/./) Fahrenheit, saturated with water vapor, and at an absolute pressure equivalent to thirty (30) inches of mercury at thirty-two degrees (32/./) Fahrenheit. 1.10 The term "psig" shall mean pounds per square inch gauge. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: MARCH 01, 1996 Effective: APRIL 01,1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 53 First Revised Volume No. 1-A Superseding Original Sheet No. 53 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS (Continued) 1.11 Releasing Shipper: A firm transportation Shipper which intends to post its service to be released to a Replacement Shipper, has posted the service for release, or has released its service. 1.12 Replacement Shipper: A Shipper which has contracted to utilize a Releasing Shipper's service for a specified period of time. 1.13 Posting Period: The period of time during which a Releasing Shipper may post, or have posted by the pipeline, all or a part of its service for release to a Replacement Shipper. 1.14 Release Term: The period of time during which a Releasing Shipper intends to release, or has released all or a portion of its contracted quantity of service to a Replacement Shipper. 1.15 Bid Period: The period of time during which a Replacement Shipper may bid to contract for a parcel which has been posted for release by a Releasing Shipper. 1.16 Parcel: The term utilized to describe an amount of capacity, expressed in MMBtu/d, from a specific receipt point to a specific delivery point for a specific period of time which is released and bid on pursuant to the capacity release provisions contained in Paragraph 28 of these Transportation General Terms and Conditions. 1.17 Primary Release: The term used to describe the release of capacity by a Releasing Shipper receiving service under a Part 284 firm transportation rate schedule. 1.18 Secondary Release: The term used to describe the release of capacity by a Replacement Shipper receiving service under a Part 284 firm transportation rate schedule. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Third Revised Sheet No. 54 First Revised Volume No. 1-A Superseding Second Revised Sheet No. 54 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS (Continued) 1.19 Bid Reconciliation Period: The period of time subsequent to the Bid Period during which bids are evaluated by PGT. 1.20 Match Period: The period of time subsequent to the Bid Reconciliation Period and before the notification deadline for awarding capacity for Prearranged Deal C during which the Prearranged Shipper may match any higher bids for the Parcel. 1.21 The term Mainline Facilities shall mean the 36-inch and 42-inch mains and appurtenant facilities extending from the interconnection with the pipeline facilities of Alberta Natural Gas Company and Foothills Pipe Lines (South B.C.) Ltd., near Kingsgate, British Columbia to the interconnection with the pipeline facilities of Pacific Gas and Electric Company near Malin, Oregon. 1.22 The term Extension Facilities shall mean the 12-inch mains and appurtenant facilities extending from PGT's mainline facilities at Milepost 304.25 and the 16-inch and 12-inch mains and appurtenant facilities extending from PGT's Mainline Facilities at Milepost 599.20 that were authorized in Docket No. CP93-618-000. The term "Extension Facility" shall mean one of the Extension Facilities. 1.23 The term "Subject Shipper" shall mean the Shippers identified in Appendix G of the Stipulation and Agreement in Docket No. RP94-149- 000, et al., and Shippers that have obtained service rights from such Shippers. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 55 First Revised Volume No. 1-A Superseding First Revised Sheet No. 55 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 2. GAS RESEARCH INSTITUTE CHARGE ADJUSTMENT PROVISION 2.1 Purpose: PGT has joined with other gas enterprises in the formation of, and participation in, the activities and financing of the Gas Research Institute (GRI), an Illinois Not For Profit corporation. GRI has been organized for the purpose of sponsoring Research, Development and Demonstration (RD&D) programs in the field of natural and manufactured gas for the purpose of assisting all segments of the gas industry in providing adequate, reliable, safe, economic and environmentally acceptable gas service for the benefit of gas consumers and the general public. For the purpose of funding GRI's approved expenditures, this Paragraph 2 establishes a GRI Adjustment Charge to be applicable to PGT's Rate Schedules ITS-1, AIS-1, PS-1 and FTS-1 in this FERC Gas Tariff First Revised Volume No. 1-A; provided, however, such charge shall not be applicable in the event gas is delivered to a downstream interstate pipeline that is a member of GRI. 2.2 Basis for the GRI Adjustment Charges: The rate schedule specified in Paragraph 2.1 hereof shall include an increment for a GRI Adjustment Charge for RD&D. Such GRI Adjustment Charge shall be that increment, adjusted to PGT's pressure base and heating value if required, which has been approved by Federal Energy Regulatory Commission Orders approving GRI's RD&D expenditures. The GRI Adjustment Charge shall be reflected in the current Statement of Effective Rates and Charges for Transportation of Natural Gas in this FERC Gas Tariff First Revised Volume No. 1-A. 2.3 Filing Procedure: The notice period and proposed effective date of filings pursuant to this paragraph shall be as permitted under Section 4 of the Natural Gas Act; provided, however, that any such filing shall not become effective unless it becomes effective without suspension or refund obligation. 2.4 Remittance to GRI: PGT shall remit to GRI, not later than fifteen (15) days after the receipt thereof, all monies received by virtue of the GRI Adjustment Charge, less any amounts properly payable to a Federal, State or Local authority relating to the monies received hereunder. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 55A First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 2. GAS RESEARCH INSTITUTE CHARGE ADJUSTMENT PROVISION (Continued) 2.5 A high load factor Shipper is a Shipper with a load factor greater than fifty (50) percent. A low load factor Shipper is a Shipper with a load factor equal to or less than fifty (50) percent. A Shipper's load factor for each service agreement shall be determined annually using the most recent twelve (12) months of actual throughput available (including throughput using capacity released pursuant to Paragraph 28 of the Transportation General Terms and Conditions). The Shipper's load factor shall remain in effect during the calendar year. In the event twelve (12) months of actual data does not exist, the Shipper's load factor shall be determined monthly based on the latest recorded throughput data. The appropriate GRI demand surcharge is applied monthly until such time as twelve (12) months of actual data is accumulated. At such time the Shipper's load factor shall remain in effect during the calendar year. 2.6 For the purpose of funding GRI's approved expenditures, and subject to the further terms and conditions set forth in the Stipulation and Agreement Concerning the Post-1993 GRI Funding Mechanism and the orders approving such Stipulation and Agreement found at Gas Research Institute, 62 FERC (P)61,316 (1993) this Paragraph 2 establishes a GRI Funding Unit which shall be collected for quantities of gas transported under PGT's rate schedules provided, however, such charge shall not be applicable to discounted transactions except where the discounted rate is less than the GRI Funding Unit. In this instance PGT shall remit that portion of the GRI Funding Unit actually collected. For purposes of discounted transactions, any GRI Funding Unit shall be considered to be the first component of rates discounted. The GRI Funding Unit may be discounted to zero and shall not be applied to the same quantity of gas more than once. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: JANUARY 10, 1994 Effective: JANUARY 01, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 56 First Revised Volume No. 1-A Superseding Original Sheet No. 56 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. QUALITY OF GAS 3.1 Quality Standards: The gas which Shipper delivers hereunder to PGT for transport (and the gas which PGT transports hereunder for Shipper) shall be merchantable gas at all times complying with the following quality requirements: (a) Heating Value: The gas shall have a gross heating value of not less than nine hundred ninety-five (995) Btus per standard cubic foot on a dry basis, but with the consent of Shipper, PGT may deliver gas at a lower gross heating value. (b) Freedom from Objectionable Matter: The gas: (1) Shall be commercially free from sand, dust, gums, crude oil, impurities and other objectionable substances which may be injurious to pipelines or which may interfere with its transmission through pipelines or its commercial utilization. (2) Shall not have a hydrocarbon dew-point in excess of fifteen degrees (15/./) Fahrenheit at pressures up to eight hundred (800) psig. (3) Shall not contain more than one-quarter (1/4) grain of hydrogen sulfide per one hundred (100) standard cubic feet. (4) Shall not contain more than ten(10) grains of total sulphur per one hundred (100) standard cubic feet. (5) Shall not contain more than two percent (2%) by volume of carbon dioxide. (6) Shall not contain more than four (4) pounds of water vapor per one million (1,000,000) standard cubic feet. (7) Shall not exceed one hundred ten degrees (110/./) Fahrenheit in temperature at the point of measurement. (8) Shall be as free of oxygen as it can be kept through the exercise of all reasonable precautions, and shall not in any event contain more than four-tenths of one percent (0.4%) by volume of oxygen. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 57 First Revised Volume No. 1-A Superseding First Revised Sheet No. 57 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. QUALITY OF GAS (Continued) 3.2 Quality Tests: (a) The quality specifications of the gas received by PGT hereunder shall be determined by tests which PGT shall cause to be made at the International Boundary or such other locations on PGT's system if required accordance with this Paragraph 3.2. (b) The gross heating value of gas delivered hereunder shall be determined from read-outs of continuously operating measuring instruments. The method shall consist of one or more of the following: (1) calorimeter (2) gas chromatograph (3) any other method mutually agreed upon by the parties. Measurement of gross heating value with the calorimeters shall comply with the standards set forth in the American Society for Testing and Materials' ASTM D 1826. Analysis of gas with gas chromatograph shall comply with the standards set forth in ASTM D 1945. Calculation of the gross heating value from compositional analysis by gas chromatography shall comply with the standards set forth in ASTM D 3588. PGT or its agent shall calibrate and maintain the gross heating value measurement device at intervals as agreed upon by PGT and Shipper. Shipper shall have access to PGT's devices and shall be allowed to inspect the devices and all charts or other records of measurement at any reasonable time. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 58 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. QUALITY OF GAS (Continued) 3.2 Quality Tests (Continued) (c) Tests shall be made to determine the total sulphur, hydrogen sulfide, carbon dioxide and oxygen content of the gas, by approved standard methods in general use in the gas industry, and to determine the hydrocarbon dew-point and water vapor content of such gas by methods satisfactory to the parties. Tests shall be made frequently enough to ensure that the gas is conforming continuously to the quality requirements. Shipper shall have the right to require PGT to have remedied any deficiency in quality of the gas and, in the event such deficiency is not remedied, the right, in addition to all other remedies available to it by law, to refuse to accept such deficient gas until such deficiency is remedied. 4. MEASURING EQUIPMENT 4.1 Installation: Unless PGT and Shippers agree otherwise, all gas volume measuring equipment, devices and materials at the point(s) of receipt and/or delivery shall be furnished and installed by PGT at Shipper's expense including the tax-on-tax effect. All such equipment, devices and materials shall be owned, maintained and operated by PGT. Shipper may install and operate check measuring equipment provided it does not interfere with the use of PGT's equipment. 4.2 Testing Meter Equipment: The accuracy of either PGT's or Shippers measuring equipment shall be verified by test, using means and methods acceptable to the other party, at intervals mutually agreed upon, and at other times upon request. Notice of the time and nature of each test shall be given by the entity conducting the test to the other entity sufficiently in advance to permit convenient arrangement for the presence of the representative of the other entity. If, after notice, the other entity fails to have a representative present, the results of the test shall nevertheless be considered accurate until the next test. If any of the measuring equipment is found to be registering inaccurately in any percentage, it shall be adjusted at once to read as accurately as possible. All tests of such measuring equipment shall be made at the expense of the entity conducting the same, except that the other entity shall bear the expense of tests made at its request if the inaccuracy is found to be two percent (2%) or less. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 59 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. MEASURING EQUIPMENT (Continued) 4.3 Correction and Adjustment: If at any time any of the measuring equipment is registering inaccurately by an amount exceeding two percent (2%) at a reading corresponding to the average hourly rate of flow, the previous readings of such equipment shall be corrected to zero error for any period definitely known or agreed upon, or if not so known or agreed upon, one-half (1/2) of the elapsed time since the last test. If the measuring equipment is out-of-service, the volume of gas delivered during such period shall be determined: (a) By using the data recorded by any check measuring equipment accurately registering; or (b) If such check measuring equipment is not registering accurately but the percentage of error is ascertainable by a calibration test, by using the data recorded, corrected to zero error; or (c) If neither of the methods provided in (a) and (b) above can be used, by estimating the quantity delivered, by reference to deliveries under similar conditions during a period when the equipment was registering accurately. No correction shall be made in the recorded volumes of gas delivered hereunder for measuring equipment inaccuracies of two percent (2%) or less, and in no event shall inaccuracies less than 25 Mcf be considered for adjustment. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 60 First Revised Volume No. 1-A Superseding Original Sheet No. 60 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. MEASUREMENTS 5.1 Metering: The gas shall be metered by one or more orifice, turbine, or displacement-type meters, at the discretion of PGT. When orifice meters are used, they shall be installed and maintained, and volumes shall be measured, in accordance with the methods prescribed in ANSI/API 2530, also published as A.G.A No. 3. When turbine meters are used, they shall be installed and maintained, and volumes shall be measured, in accordance with methods prescribed in AGA Report No. 4 or any subsequent revision. When displacement meters are used, they shall be installed and maintained and quantities shall be measured in accordance with methods prescribed in A.G.A. No. 2, and the number of Mcf delivered hereunder shall be computed by including factors for pressure, temperature and deviation from Boyle's Law. To accurately determine the deviation from Boyle's Law, a quantitative analysis of the gas components shall be made at reasonable intervals with such apparatus as shall be agreed upon by both parties. 5.2 Specific Gravity: The specific gravity of the gas delivered hereunder shall be determined from the read-outs of continuously operating measuring instruments. The method shall consist of one of the following: (a) gravitometer (b) gas chromatography (c) other instruments acceptable to both parties Analysis of chromatograph shall comply with the standards set forth in ASTM D 1945. Calculation of the specific gravity from compositional analysis by gas chromatography shall comply with the standards set forth in ASTM D 3588. Measurement of the specific gravity with a gravitometer shall comply with the standards set forth in ASTM D 1070. 5.3 Flowing Temperature: Flowing gas temperature shall be continuously measured and used in flow calculations. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 61 First Revised Volume No. 1-A Superseding Original Sheet No. 61 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. INSPECTION OF EQUIPMENT AND RECORDS 6.1 Inspection of Equipment and Data: PGT and Shipper shall have the right to inspect equipment installed or furnished by the other, and the charts and other measurement or test data of the other, at all times during business hours; but the reading, calibration and adjustment of such equipment and changing of charts shall be done only by the entity installing or furnishing same. Unless PGT and Shipper otherwise agree, each shall preserve all original test data, charts and other similar records in such party's possession, for a period of at least six (6) years. 6.2 Information for Billing: When information necessary for billing by PGT is in the control of Shipper, Shipper shall furnish such information, estimated if actual is not available, to PGT on or before the third (3rd) working day of the month following the month transportation service was rendered. If shipper furnishes estimated information, the actual information shall be furnished to PGT on or before the sixth (6th) working day of the month following the month transportation service was rendered. 6.3 Verification of Computations: PGT and Shipper shall have the right to examine at reasonable times the books, records and charts of the other to the extent necessary to verify the accuracy of any statement, charge or computation made pursuant to these Transportation General Terms and Conditions and to the rate schedules to which they apply, within twelve (12) months of any such statement, charge or computation. 7. BILLING 7.1 Billing under all Rate Schedules: On or before the twentieth (20th) day of each month, PGT shall render a bill to each Shipper under all applicable Rate Schedules for the service(s) rendered during the preceding month. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 62 First Revised Volume No. 1-A Superseding First Revised Sheet No. 62 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 8. PAYMENT 8.1 Payment under all Rate Schedules: On or before the last day of each month, each Shipper under all applicable Rate Schedules shall pay to or upon the order of PGT in lawful money of the United States at PGT's office in Portland, Oregon, the amount of the bill rendered by PGT during the month in accordance with Paragraph 7.1 of these Transportation General Terms and Conditions. 8.2 Interest on Unpaid Amounts: Should Shipper fail to pay the amount of any bill rendered by PGT when such amount is due, interest thereon shall accrue from the due date until paid at the rate of interest effective from time to time under 18 CFR Section 154.67. 8.3 Remedies for Failure to Pay: If such failure to pay continues for thirty (30) days after payment is due, PGT, in addition to any other remedy it may have, may suspend further delivery of gas until such amount is paid, unless Shipper in good faith disputes the amount owing and pays such amount as it concedes to be correct. Either party may submit to arbitration in accordance with Paragraph 14 of these Transportation General Terms and Conditions any dispute as to the amount due PGT hereunder. 8.4 Late Billing: If presentation of a bill by PGT is delayed after the date specified in Paragraph 7.1 hereof, then the time for payment shall be extended correspondingly unless Shipper is responsible for such delay. 8.5 Adjustment of Billing Error: In the event an error is discovered in any bill rendered by PGT, the amount of such error shall be adjusted, provided that claim therefor shall have been made within twelve (12) months from the date such bill was rendered. The adjustment shall be made within thirty (30) days of such timely claim. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 63 First Revised Volume No. 1-A Superseding Original Sheet No. 63 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 9. NOTICE OF CHANGES IN OPERATING CONDITIONS PGT and Shipper shall each ensure that the other is notified from time to time as necessary of expected changes in the rates of delivery or receipt of gas, or in the pressures or other operating conditions, and the reason for such expected changes, so that they may be accommodated when they occur. 10. FORCE MAJEURE 10.1 If either party shall fail to perform any obligation imposed upon it by these Transportation General Terms and Conditions or by an executed Transportation Service Agreement, and such failure shall be caused, or materially contributed to, by force majeure which means any acts of God, strikes, lockouts, or other industrial disturbances, acts of public enemies, sabotage, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, floods, storms, fires, washouts, extreme cold or freezing weather, arrests and restraints of rulers and people, civil disturbances, explosions, breakage of or accident to machinery or lines of pipe, hydrate obstructions of lines of pipe, inability to obtain pipe, materials or equipment, legislative, administrative or judicial action which has been resisted in good faith by all reasonable legal means, any acts, omissions or causes whether of the kind herein enumerated or otherwise not reasonably within the control of the party invoking this paragraph and which by the exercise of due diligence such party could not have prevented, the necessity for making repairs to, replacing, or reconditioning machinery, equipment, or pipelines not resulting from the fault or negligence of the party invoking this paragraph, such failure shall be deemed not to be a breach of the obligation of such party, but such party shall use reasonable diligence to put itself in a position to carry out its obligations. Nothing contained herein shall be construed to require either party to settle a strike or lockout by acceding against its judgment to the demands of the opposing parties. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 64 First Revised Volume No. 1-A Superseding Original Sheet No. 64 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 10. FORCE MAJEURE (Continued) 10.2 No such cause as described in Paragraph 10.1 affecting the performance of either party shall continue to relieve such party from its obligation after the expiration of a reasonable period of time within which by the use of due diligence such party could have remedied the situation preventing its performance, nor shall any such cause relieve either party from any obligation unless such party shall give notice thereof in writing to the other party with reasonable promptness; and like notice shall be given upon termination of such cause. 10.3 No cause whatsoever, including without limitation the failure of PGT to perform including the causes specified in Paragraph 10.1, shall relieve Shipper from its obligations to make payments due, including the payments of reservation charges for the duration of such cause except as provided for in Paragraphs 3.10 and 3.11 of Rate Schedule FTS-1. 11. WARRANTY OF ELIGIBILITY FOR TRANSPORTATION Any Shipper transporting gas on the PGT system under this FERC Gas Tariff First Revised Volume No. 1-A warrants for itself, its successors and assigns, that it will have at the time of delivery of the gas to PGT hereunder good title to such gas and that all gas delivered to PGT for transportation hereunder is eligible for the requested transportation in interstate commerce under applicable rules, regulations or orders of the FERC, or other agency having jurisdiction. Shipper will indemnify PGT and save it harmless from all suits, actions, damages, costs, losses, expenses (including reasonable attorney fees) and costs connected with regulatory proceedings, arising from breach of this warranty. 12. POSSESSION OF GAS AND RESPONSIBILITY PGT shall be deemed to be in control and possession of, and responsible for, all gas delivered from the time that such gas is received by it at the point of receipt to the time that it is delivered at the point of delivery. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 65 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 13. INDEMNIFICATION Shipper agrees to indemnify and hold harmless PGT, its officers, agents, employees and contractors against any liability, loss or damage whatsoever occurring in connection with or relating in any way to the executed Transportation Service Agreement, including costs and attorneys' fees, whether or not such liability, loss or damage results from any demand, claim, action, cause of action, or suit brought by Shipper or by any person, association or entity, public or private, that is not a party to the executed Transportation Service Agreement, where such liability, loss or damage is suffered by PGT, its officers, agents, employees or contractors as a direct or indirect result of any breach of the executed Transportation Service Agreement or sole or concurrent negligence or gross negligence or other tortious act(s) or omission(s) by Shipper, its officers, agents, employees or contractors. 14. ARBITRATION Any arbitration provided for or agreed to by Shipper and PGT shall be conducted in accordance with the following procedures and principles: Upon the written demand of either PGT or Shipper and within ten (10) days from the date of such demand, each entity shall appoint an arbitrator and the two arbitrators so appointed shall promptly thereafter appoint a third. If either PGT or Shipper shall fail to appoint an arbitrator within ten (10) days from the date of such demand, then the arbitrator shall be appointed by a Superior Court of the State of California in accordance with the California Code of Civil Procedure. If the two arbitrators shall fail within ten (10) days from their appointment to agree upon and appoint the third arbitrator, then upon the application of either PGT or Shipper such third arbitrator shall be appointed by a Superior Court of the State of California in accordance with the California Code of Civil Procedure. The arbitrators shall proceed immediately to hear and determine the matter in controversy. The award of the arbitrators, or a majority of them, shall be made within forty-five (45) days after the appointment of the third arbitrator, subject to any reasonable delay due to unforeseen circumstances. The award of the arbitrators shall be drawn up in writing and signed by the arbitrators, or a majority of them, and shall be final and binding on both PGT and Shipper, and PGT and Shipper shall abide by the award and perform the terms and conditions thereof. Unless otherwise determined by the arbitrators, the fees and expenses of the arbitrator named for each party shall be paid by that party and the fees and expenses of the third arbitrator shall be paid in equal proportion by both PGT and Shipper. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 66 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 15. GOVERNMENTAL REGULATIONS These Transportation General Terms and Conditions, the rate schedules to which they apply, and any executed Transportation Service Agreement are subject to valid laws, orders, rules and regulations of duly constituted authorities having jurisdiction. 16. MISCELLANEOUS PROVISION 16.1 Waiver of Default: No waiver by either PGT or Shipper of any default by the other in the performance of any provisions of an executed Transportation Service Agreement shall operate as a waiver of any continuing or future default, whether of a like or different character. 16.2 Assignability: An executed Transportation Service Agreement shall bind and inure to the respective successors and assignees of PGT and Shipper thereto, but no assignment shall release either party thereto from such party's obligations without the written consent of the other party, which consent shall not be unreasonably withheld; provided, however, nothing contained herein shall give Shipper the right to reassign or broker its right to ship the quantities of gas specified in the Transportation Service Agreement on PGT's system to others. Further, nothing contained herein shall prevent either party from pledging, mortgaging or assigning its rights as security for its indebtedness and either party may assign to the pledgee or mortgagee (or to a trustee for the holder of such indebtedness) any money due or to become due under any service agreement. 16.3 Effect of Headings: The headings used throughout these Transportation General Terms and Conditions, the rate schedules to which they apply, and the executed Transportation Service Agreements are inserted for reference purposes only and are not to be considered or taken into account in construing the terms and provisions of any paragraph nor to be deemed in any way to qualify, modify or explain the effects of any such terms or provisions. 17. TRANSPORTATION SERVICE AGREEMENT 17.1 Form: Shipper shall enter into a contract with PGT utilizing PGT's appropriate standard form of Transportation Service Agreement. 17.2 Term: The term of the Transportation Service Agreement shall be agreed upon between Shipper and PGT at the time of the execution thereof. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46,000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 67 First Revised Volume No. 1-A Superseding First Revised Sheet No. 67 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS Initial Service: For purposes of scheduling commencement of initial transportation service five (5) business days prior to the day on which Shipper desires service to commence, or such lesser period of time as mutually agreed upon by PGT and Shipper, Shipper will provide PGT a completed Customer Nomination Form provided to: Pacific Gas Transmission Company Gas Transportation and Services 2100 Southwest River Parkway Portland, OR 97201 Phone - 503-833-4300 Fax -503-833-4396 Shipper shall not be entitled to receive transportation service under this FERC Gas Tariff First Revised Volume No. 1-A if Shipper is not current in its payments to PGT for any charge, rate or fee authorized by the Commission for transportation service; provided, however, if the amount not current pertains to a bona fide dispute, including but not limited to force majeure claims relating to this FERC Gas Tariff, Shipper shall be entitled to receive or continue to receive transportation service if Shipper posts a bond satisfactory to PGT to cover the payment due PGT. 18.1 Firm Service The provisions of this Paragraph 18.1 shall be applicable to firm transportation service under Rate Schedule FTS-1 contained in this First Revised Volume No. 1-A. Firm transportation service under this First Revised Volume No. 1-A shall be provided when, and to the extent that, PGT determines that firm capacity is available on PGT's existing facilities. PGT shall not be required to provide firm transportation service in the event firm capacity is unavailable or to construct new facilities to provide firm service. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 68 First Revised Volume No. 1-A Superseding Original Sheet No. 68 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.1 Firm Service (Continued) For capacity that becomes available other than the circumstances identified in Paragraphs 28 and 33, requests for firm capacity shall be accommodated in the following manner and subject to the following conditions and limitations: (a) In order to be eligible for firm capacity, a party requesting service (requestor) must be deemed credit-worthy per Paragraph 18.3 and submit a valid request in accordance with the provisions herein. (b) PGT will post on Pacific Trail, PGT's Electronic Bulletin Board (EBB), available capacity. A requestor that submits a valid request may submit a bid via the EBB for the available capacity subsequent to PGT's posting of such capacity on the EBB. The Bid Period will be 5 business days, during which time other requestors with valid requests may submit a bid. All bids not withdrawn prior to the close of the Bidding Period shall be binding. At the end of the Bidding Period, PGT will evaluate the bids and determine the bid(s) having the greatest economic value as determined in Paragraph 18.1(c) below. (c) After the close of the Bidding Period, PGT may tender a Service Agreement for execution to the requestor(s) submitting the bid(s) having the greatest economic value for the capacity available, subject to the provisions of Paragraph 18.1(e). The criteria for determining which requestor(s) has submitted the bid(s) with the greatest economic value shall be the Net Present Value (NPV) of the reservation charge as calculated at Paragraph 28 that requestor(s) would pay at the rates requestor(s) has bid, which shall not be less than the Minimum Rate nor greater than the Maximum Rate, as stated on the currently effective Statement of Rates and Charges governing such service, over the term of service specified in the request. If the economic values of separate bids are equal, then service shall be offered to such requestors on a pro-rata basis. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 69 First Revised Volume No. 1-A Superseding Original Sheet No. 69 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.1 Firm Service (Continued) (d) If PGT accepts the winning bid(s) and tenders a Service Agreement, requestor(s) shall complete and return the Service Agreement within thirty (30) days. (e) Except as provided in Paragraph 28, PGT shall not be obligated to tender or execute a Service Agreement for service at any rate less than the Maximum Rate set forth in the Statement of Effective Rates and Charges applicable to the service requested. (f) A Shipper receiving service under FTS-1 shall not lose its priority for purposes of Paragraph 19 by the renewal or extension of term of that service; provided, however, any renewal or extension must be pursuant to a rollover or evergreen provision of the Service Agreement. Shipper's preexisting priority shall not apply, however, to any increase in transportation quantity or new primary point of delivery. 18.2 Interruptible Service The provisions of this Paragraph 18.2 shall be applicable to interruptible transportation service under Rate Schedule ITS-1 contained in this First Revised Volume No. 1-A. (a) Interruptible transportation service under this First Revised Volume No. 1-A shall be provided when, and to the extent that, capacity is available in PGT's existing facilities, which capacity is not subject to a prior claim under a pre-existing agreement pursuant to Rate Schedule FTS-1 or under another class of firm service. (b) In the event where natural gas tendered by Shipper to PGT at the receipt point(s) for transportation, or delivered by PGT to Shipper (or for Shipper's account) at the delivery point(s), is commingled with other natural gas at the time of measurement, the determination of deliveries applicable to Shipper shall be made in accordance with operating arrangements satisfactory to Shipper, PGT and any third party transporting to or from PGT's system. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 70 First Revised Volume No. 1-A Superseding Original Sheet No. 70 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.2 Interruptible Service (Continued) (c) PGT shall process the requests of potential Shippers requesting similar interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A on a first-come, first-served basis, to the extent practicable, taking into account the nature and character of the service requested. Available interruptible capacity shall be allocated by PGT on a first-come, first-served basis as provided in Paragraph 19 and determined by the date and time PGT receives a completed request for service under this FERC Gas Tariff which conforms to Paragraph 18 of these Transportation General Terms and Conditions. (d) A Shipper receiving service under ITS-1 shall not lose its priority for purposes of Paragraph 19 by the renewal or extension of term of that service; provided, however, any renewal or extension must be pursuant to a rollover or evergreen provision of the Service Agreement. Shipper's pre-existing priority shall not apply, however, to any increase in transportation quantity or new primary points of delivery. (e) If Shipper fails to nominate and tender gas within the later of: (a) fifteen (15) days after initial notification by PGT of the availability of service, (b) receipt of any necessary regulatory approvals, or (c) the installation of any necessary facilities, Shipper's priority date shall be deemed null and void, and the day Shipper first tenders gas to PGT at any receipt point shall be Shipper's new assigned priority date for service. Shipper's priority date designation pursuant to Section 2.3 of the Transportation Service Agreement shall not be deemed null and void if Shipper's failure to nominate and tender gas is caused by an event of force majeure as defined in PGT's Transportation General Terms and Conditions. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 70A First Revised Volume No. 1-A Superseding Original Sheet No. 70A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 Credit-worthiness (A) Credit-worthiness for Firm Transportation Service (1) PGT shall not be required to perform or to continue transportation service under this FERC Gas Tariff First Revised Volume 1-A on behalf of any Shipper who is or has become insolvent or who, after PGT's request, fails within a reasonable period to establish or confirm credit-worthiness. Shippers shall provide, initially and on a continuing basis, financial statements, evidence of debt and/or credit ratings, and other such information as is reasonably requested by PGT to establish or confirm Shipper's qualification for service. Credit limits will be established based on the level of requested service and Shipper credit-worthiness as established by the following: (a) Credit-worthiness must be evidenced by at least a long term bond (or other senior debt) rating of BBB or an equivalent rating. Such rating may be obtained in one of three ways: (i) The rating will be determined by Standard and Poors or another recognized U.S. or Canadian debt rating service; (ii) If Shipper's debt is not rated by a recognized debt rating service, an equivalent rating as determined by PGT, based on the financial rating methodology, criteria and ratios for the industry of the Shipper as published by the above rating agencies from time to time. In general, such equivalent rating will be based on the audited financial statements for the Shipper's two most recent fiscal years, all interim reports, and any other relevant information; (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: APRIL 20, 1994 Effective: MAY 21, 1994 Pacific Gas Transmission Company FERC Gas Tariff Third Revised Sheet No. 71 First Revised Volume No. 1-A Superseding Second Revised Sheet No. 71 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (A) Credit-worthiness for Firm Transportation Service (Continued) (iii) Shipper may, at its own expense, obtain a private rating from a recognized debt rating service, or request that an independent accountant or financial advisor, mutually acceptable to PGT and the Shipper, prepare an equivalent evaluation based on the financial rating methodology, criteria, and ratios for the industry of the Shipper as published by the above rating agencies from time to time; or (b) Approval by PGT's lenders; or (c) If Shipper is requesting credit to bid on a parcel that is for one year (365 days) or less of service through PGT's Capacity Release Program contained in Paragraph 28, and this option is selected by the Releasing Shipper, Shipper may demonstrate credit-worthiness by providing two years of audited financial statements for itself, or for its parent company if it is a subsidiary which is consolidated with its parent company and does not issue stand-alone financial statements, demonstrating adequate financial strength to justify the amount of credit to be extended. PGT shall apply consistent evaluation practices to determine credit-worthiness. (2) If Shipper does not establish or maintain credit-worthiness as described above, Shipper has the option of receiving transportation service under this FERC Gas Tariff by providing to PGT one of the following alternatives: (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 72 First Revised Volume No. 1-A Superseding First Revised Sheet No. 72 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (A) Credit-worthiness for Firm Transportation Service (Continued) (a) A guarantee of Shipper's financial performance in a form satisfactory to PGT and for the term of the Gas Transportation Agreement from a corporate affiliate of the Shipper or a third party either of which meets the credit-worthiness standard discussed above. (b) Other security acceptable to PGT's lenders. 18.3 (B) Credit-worthiness for Interruptible Transportation Service (1) PGT shall not be required to perform or to continue interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A on behalf of any Shipper who is or has become insolvent or who, at PGT's request, fails within a reasonable period to demonstrate credit-worthiness. Shipper's credit-worthiness shall be determined by providing proof of least two of the items listed below: (a) A long-term bond or commercial paper rating from Standard and Poors or Moody's equivalent to a "Ba" or better, or a commercial paper rating from Standard and Poors or Moody's equivalent to Prime-3 or better. (b) Audited financial statements for itself, or for its parent company if it is a subsidiary which is consolidated with its parent company and does not issue stand-alone financial statements, for the two preceding years showing good financial strength. (c) An estimated financial strength rating by Dun and Bradstreet sufficient to cover the credit to be extended and a corresponding Dun and Bradstreet composite credit appraisal of "fair" or better. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective:SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 73 First Revised Volume No. 1-A Superseding Original Sheet No. 73 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (B) Credit-worthiness for Interruptible Transportation Service (Continued) (d) A demonstration by the Shipper that the Company has sufficient financial capacity or backing to warrant an extension of credit. This demonstration could include proof of banking relationships sufficient to cover the service agreement, or a detailed listing of credit references within the industry, exhibiting a good credit history. (2) If Shipper does not demonstrate credit-worthiness, Shipper has the option of receiving interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A if Shipper provides PGT a letter of credit in an amount equal to the cost of performing the maximum level of service requested for a three (3) month period of time. The letter of credit must be from a credit worthy financial institution and be in place before the Transportation Service Agreement can be signed. The Shipper also has the option of receiving transportation service if Shipper prepays for transportation services on a month-to-month basis pursuant to the following terms: (a) For a calendar month in which transportation service is desired (delivery month), Shipper must notify PGT no later than eight (8) business days prior to the commencement of delivery month (estimation date) of its estimation of the maximum, cumulative gas deliveries (monthly estimation) desired for the delivery month. (For Shipper's initial monthly estimation, the delivery month, or remaining portion thereof, shall commence eight (8) days after the estimation date.) Notice of monthly estimation may be telephonic or written; telephonic notices must be confirmed in writing and received by PGT within five (5) business days. PGT will advise Shipper within forty-eight (48) hours of the estimation date of the exact dollar amount of the prepayment. Shipper shall not deliver or receive gas in excess of the monthly estimation during delivery month. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 74 First Revised Volume No. 1-A Superseding Original Sheet No. 74 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (B) Credit-Worthiness for Interruptible Transportation Service (Continued) (b) No later than three (3) business days (settlement date) prior to commencement of delivery month, Shipper shall pay to PGT and PGT shall have received from Shipper lawful money of the United States in an amount equal to the prepayment amount provided to Shipper by PGT described above. (c) On or before the twentieth (20th) day following delivery month, PGT shall provide a statement to Shipper detailing the transportation service provided during the delivery month. The statement will reconcile the amount prepaid in accordance with the monthly estimation, with the actual cost of transportation service provided, and provide a credit to Shipper, if applicable. Any such credit will be deducted from the prepayment for the following month. Should the Shipper elect not to receive transportation services for the following month, Shipper shall so notify PGT in writing; PGT will issue a check to the Shipper within seven (7) business days following receipt by PGT of such notice. 18.3 (C) Credit-worthiness for Firm and Interruptible Transportation Service For purposes of this FERC Gas Tariff First Revised Volume No. 1-A the insolvency of a Shipper shall be evidenced by the filing by such Shipper or any parent entity thereof (hereinafter collectively referred in this paragraph to as "the Shipper") of a voluntary petition in bankruptcy or the entry of a decree or order by a court having jurisdiction in the premises adjudging the Shipper as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 75 First Revised Volume No. 1-A Superseding Original Sheet No. 75 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (C) Credit-worthiness for Firm and Interruptible Transportation Service (Continued) or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper or of any substantial part of its property, or the ordering of the winding-up liquidation of its affairs, with said order or decree continuing unstayed and in effect for a period of sixty (60) consecutive days. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 76 First Revised Volume No. 1-A Superseding Original Sheet No. 76 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.4 Upon request of PGT, Shipper shall from time to time submit estimates of daily, monthly and annual quantities of gas to be transported, including peak day requirements. 18.5 PGT shall not be obligated to install additional facilities, other than those specified in Paragraph 4.1 herein, that are required to provide service under this FERC Gas Tariff First Revised Volume No. 1-A; provided, however, PGT may install or Shipper may pay all of the expenses incurred for installing additional facilities on a nondiscriminatory basis and under terms that are mutually agreeable. In the event PGT incurs the cost of installing additional facilities on behalf of a Shipper, Shipper shall pay, in addition to the rate(s) stated in the applicable rate schedule, the prorated(based on Transportation Contract Demand) cost of service attributable to any such additional facilities until such time as a different allocation procedure is specified by Commission order. 18.6 No transportation service will be conducted for the account of Shipper by PGT until PGT has received the completed service request form, unedited and complete as to form, and Shipper has been advised by PGT that the transportation service may commence. 18.7 Requests for interruptible and firm transportation service hereunder shall be made by providing the information contained in PGT's Transportation Request Form to PGT. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 77 First Revised Volume No. 1-A Superseding Original Sheet No. 77 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Transportation Request Form Gentlemen: ________________________________ (Shipper) hereby requests gas transportation service from Pacific Gas Transmission Company (PGT) in accordance with Paragraph 18.8 of the Transportation General Terms and Conditions of PGT's tariff and concurrently provides the following information relative to this request: 1. Shipper's Name ___________________________________________ Business Address __________________________________________ State or Province of Incorporation ________________________ 2. Requesting Party ____________________ Title _______________ Contact Name ________________________ Phone _______________ 3. Shipper's Status: LDC ____ Intrastate ____ End User ____ (Check one) Producer ____ Marketer/Broker __________ Gatherer ____ Interstate ____ Other __________________________________ 4. Type of Service Requested: (Check all applicable) a. Part 284 Interruptible ____ b. Part 284 Firm ____* c. New Service ____ d. Amendment to PGT Contract #_______ e. Add/Change Receipt/Delivery Point ____ f. Authority to Bid for Released Capacity ____ * PGT will accept requests for firm transportation service. At such time that firm capacity may become available, PGT will evaluate such requests. Currently, no excess firm capacity is available on the PGT system. 5. Type of Authority: Blanket Section 7 (Part 284, Subpart G)____ Section 311(a) (Part 284, Subpart B)____ (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 78 First Revised Volume No. 1-A Superseding First Revised Sheet No. 78 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Transportation Request Form (Continued) 6. If Shipper requests service under Section 311(a), provide the following information concerning the party on whose behalf the transportation will be provided (the "On Behalf of" party): (a) The exact legal name of the "On Behalf Of" party: ________________________________________________________________ (b) The "On Behalf Of" party's address (if other than Shipper): ________________________________________________________________ ________________________________________________________________ ________________________________________________________________ (c) Is the "On Behalf Of" party: A Local Distribution Company ______ An Intrastate Pipeline ______ 7. If Shipper requests service under Section 311(a), Shipper must provide a certification that the service qualifies under 18 C.F.R. (S) 284.102. To enable PGT to verify that the requested transportation service will qualify under 18 C.F.R. (S) 284.102, the certification must provide facts showing that: (a) the "On Behalf Of" party will have physical custody of and transport the natural gas at some point; or (b) the "On Behalf Of" party will hold title to the natural gas at some point, which may occur prior to , during, or after the time that the gas is transported by PGT, for a purpose related to the "On Behalf Of" party's status and function as an intrastate pipeline or its status and function as a local distribution company; or (c) the gas will be delivered to a customer that is either located in the "On Behalf Of" party's service area, if the "On Behalf Of" party is a local distribution company, or is physically able to receive direct deliveries of gas from the "On Behalf Of" party, if the "On Behalf Of" party is an interstate pipeline, and that "On Behalf Of" party has certified that it is on its behalf that PGT will be providing the requested transportation service. (The "On Behalf Of" party's certification must be submitted with the Transportation Request Form.) (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 79 First Revised Volume No. 1-A Superseding Substitute Original Sheet No. 79 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Transportation Request Form (Continued) 8. The intended use of the gas is: _____ utility or pipeline system supply _____ end use by industry or commerce _____ other (specify) 9. Requested Commencement Date _______________ (not to exceed 3 months from request date) Termination Date __________________ Evergreen clause desired (Complete for Part 284 Interruptible or Firm Service only): Yes _____ No _____ 10. Transportation Quantities: a) Total Maximum Daily Quantity (MDQ): __________ MMBtu/day b) Total quantity for contract period: __________ MMBtu 11. Notices to: _______________________________________________________ Mailing Address _______________________________________________________ City State Zip _______________________________________________________ Street Address (if P.O. Box was used above) _______________________________________________________ City State Zip _______________________________________________________ Attention Title _______________________________________________________ Telephone Number Fax Number (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 80 First Revised Volume No. 1-A Superseding Substitute Revised Sheet No. 80 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Tranportation Request Form (Continued) Invoices to: _______________________________________________________ Mailing Address _______________________________________________________ City State Zip _______________________________________________________ Street Address (if P.O. Box was used above) _______________________________________________________ City State Zip _______________________________________________________ Attention Title _______________________________________________________ Telephone Number Fax Number (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 81 First Revised Volume No. 1-A Superseding First Revised Sheet No. 81 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS 19.1 Priority of Firm Service PGT shall provide service first for firm transportation Shippers for service at Shipper's primary receipt and delivery points in accordance with the applicable executed service agreements and rate schedules. Next, PGT will provide firm transportation service for service at Shipper's secondary receipt and delivery points or primary receipt and secondary delivery points in accordance with the applicable executed service agreements and rate schedules. If full service cannot be provided, PGT shall provide service on a pro rata basis according to the respective total Maximum Daily Demand or Maximum Daily Quantity, as appropriate, specified in each executed service agreement, first for service at Shipper's primary receipt and delivery points and second for service at Shipper's secondary receipt and delivery points. These provisions also apply for capacity released under PGT's capacity release program, and are subject to the terms and conditions as specified in an executed firm service agreement between PGT and Shipper. All service under the capacity release program shall be considered firm for purposes of priority of service. 19.2 Priority of Interruptible Service Interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A shall be provided when, and to the extent that, capacity is available in PTG's existing facilities, which capacity is not subject to a prior claim under a pre-existing contract, service agreement, certificate or under Priority 1 - Firm Service. PGT will provide interruptible transportation service, as set forth in Paragraph 19 of these Transportation General Terms and Conditions, on a first-come, first-served basis, as determined by the date and time PGT receives a completed request for service conforming to Paragraph 18.8, as approved by the Commission in Docket No. CP87-159-000. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 81.01 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued) 19.2 Priority of Interruptible Service Interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A shall be provided when, and to the extent that, capacity is available in PGT's existing facilities, which capacity is not subject to a prior claim under a pre-existing contract, service agreement, certificate or under Priority 1 - Firm Service. PGT will provide interruptible transportation service, as set forth in Paragraph 19 of these Transportation General Terms and Conditions, first to shippers paying the maximum rate in accordance with PGT's IT Queue, which is determined by the date and time PGT receives a completed request for service conforming to Paragraph 18.8, as approved by the Commission in Docket No. CP87-159-000. PGT will next allocate capacity to shippers paying a discounted rate to the shipper(s) paying the highest rate. For the purposes of this Section 19.2, the term "highest rate" shall be determined by multiplying the distance in pipeline miles from the receipt point to the delivery point by the sum of the Base Tariff Rate, GRI Surcharge, GSR Surcharge, and ACA Surcharge. In the event of a tie, shippers shall receive a pro-rata allocation based on the quantity that otherwise would be scheduled if not for the capacity limitation. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 81A First Revised Volume No. 1-A Superseding Original Sheet No. 81A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued) 19.3 Priority of Authorized Overrun Service Authorized overrun service shall have a priority lower than firm or interruptible as defined above. Priority within the overrun class shall be determined using a first-come, first-serve procedure. 19.4 Nominations Quantities nominated for transportation shall be for previously approved and valid receipt and delivery points and shall be provided by Shipper via the Electronic Bulletin Board (EBB), to PGT's Gas Control no later than 10:00 a.m. Pacific Time for the following day. Nominations for an entire month may be made at any time up to 10:00 a.m. Pacific Time on the last day of the month. PGT shall have the discretion to accept nominations at such other later times as operating conditions may permit and without detrimental impact to other Shippers and upon confirmation that corresponding upstream and downstream arrangements in a manner satisfactory to PGT have been made. The receipt of the nomination by PGT is notice that all necessary regulatory approvals have been received and that valid upstream and downstream transportation and other contractual arrangements are in place. Shipper shall provide as a component of its nomination such other information as may be required by PGT to enable it to identify, confirm and schedule the nomination. Shipper shall also prioritize nominated receipts and deliveries when there is more than one supplier and more than one shipper customer respectively. Shipper designated priorities will be used to allocate gas when the upstream and downstream nominations vary from PGT's Shipper nominations. PGT shall be allowed to rely conclusively on the information submitted as part of the nomination in confirming the nomination for scheduling and allocation. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 81B First Revised Volume No. 1-A Superseding First Revised Sheet No. 81B ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued) 19.4 Nominations (Continued) Requests to amend previously scheduled nominations may be accepted during the gas day, subject to operational conditions and, further that corresponding upstream and downstream adjustments in a manner satisfactory to PGT can be confirmed. A request to increase a nomination for firm transportation up to the MDQ specified in the Service Agreement will be accommodated to the extent operating conditions permit; provided, however an increased nomination will not be scheduled to the extent it would affect another Shipper's flowing quantities during the Gas Day that the increased nomination is received. A request to increase a nomination for interruptible transportation shall be permitted only to the extent that capacity is available and that no displacement of other interruptible transportation occurs. Such changes will become effective only when system operating conditions, as determined by PGT, permit changes to occur. Quantities nominated are for a daily rate, and will be received and delivered at a uniform hourly rate of confirmed quantity divided by 24, unless as determined by PGT, variance from the hourly rate will not be detrimental to the operation of the pipeline or adversely affect other PGT Shippers. Nominations, as amended by Shipper and received by PGT, shall remain in effect during the month for which the nomination is applicable, whether or not transportation occurs, until a new or amended nomination is provided by Shipper and received by PGT. PGT reserves the right to reject any nominated quantity of less than 24 MMBTU/day. PGT's primary method of nomination transmission shall be the EBB. If and only if, the EBB is inoperable, shall PGT accept nominations via alternative means such as fax transmittal. PGT requires that a Shipper designate, in writing, those individuals who will be authorized to place nominations for transportation on the system. 19.5 Priority of Parking and Authorized Imbalance Service Parking and Authorized Imbalance Service shall have the lowest priority on PGT's system. All other transportation service, including rectification of imbalances, have superior priority to these services. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 12, 1994 Effective: SEPTEMBER 14, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-145-000, dated AUGUST 03, 1994 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 81C First Revised Volume No. 1-A Superseding First Revised Sheet No. 81C ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. CURTAILMENT PGT shall have the right to curtail, interrupt, or discontinue Transportation Service on any portion of its system at any time for reasons of Force Majeure or when capacity, supply, or operating conditions so require or it is necessary or desirable to make modifications, repairs, or operating changes to its system. PGT shall provide notice of such occurrences as is reasonable under the circumstances. Capacity may become constrained at individual receipt points, delivery points or on segments of the pipeline. PGT shall exercise this curtailment provision only at the point(s) or segment(s) of the pipeline affected by the constraint. When capacity is constrained or otherwise insufficient to serve all the transportation requirements which are scheduled to receive service, transportation service will be curtailed in reverse order of the scheduling provided in Paragraph 19. Curtailment of firm service if necessary, will be performed pro rata based on the MDQ across the contracts scheduled to use capacity at the applicable delivery point(s) or mainline segment(s) of pipeline, applied first to secondary delivery points. Curtailment of firm service, if necessary, at receipt points will be performed pro rata based on the quantities scheduled at the affected receipt point(s), applied first to secondary receipt points. If, on any day, PGT determines the capacity of its mainline system, or any portion thereof, including the points at which gas is tendered for transportation, is insufficient to serve transportation requirements which are otherwise scheduled to receive service on such day, or to accept the quantities of gas tendered, capacity which requires allocation shall be allocated in a manner which results in curtailment of capacity, to zero if necessary, first to the last quantities scheduled, and then sequentially in reverse order to the scheduling provided for in Paragraph 19, except that mid-gas day nomination increases by interruptible Shippers shall not bump those interruptible Shippers' volumes already confirmed for that gas day. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 82 First Revised Volume No. 1-A Superseding Original Sheet No. 82 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING Balancing of thermally equivalent quantities of gas received and delivered by PGT shall be achieved as nearly as feasible on a daily basis, with any cumulative imbalance accounted for on a monthly basis. Correction of imbalances shall be the responsibility of the Shipper whether or not notified by PGT at the time of incurrence of the imbalance. Correction of imbalances shall be scheduled with PGT using the nomination process as soon as an imbalance is known to exist based on the best available current data. Nominations to correct imbalances shall have the lowest priority for scheduling purposes and shall be subject to the availability of capacity and other operational constraints for imbalance correction. If on any day capacity is insufficient to schedule all imbalance nominations, all such nominations shall be prorated accordingly. To maintain the operational integrity of its system, PGT shall have the right to balance any Shipper's account as conditions may warrant. Imbalances shall exist as defined below and be subject to the applicable charges and penalties if not corrected. a) Actual delivered quantity exceeds MDQ An imbalance shall exist if the actual delivered quantity on any day exceeds the MDQ and the delivered quantity in excess of the MDQ has not been authorized by PGT (Unauthorized Overrun). Penalty: A Shipper shall be assessed $5/MMBTU for the quantity that is greater than 10% of the MDQ or 1000 MMBTU, whichever is greater. In addition, the quantity delivered in excess of the MDQ shall be charged the Authorized Overrun charge as provided in the applicable rate schedule of Shipper. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 83 First Revised Volume No. 1-A Superseding Original Sheet No. 83 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING (Continued) (b) Actual delivered quantity exceeds receipt quantity A net positive imbalance shall exist if the difference between the delivered quantity and the quantity received, taking into account the reduction in quantity for compressor fuel use, yields a positive result. Commencing upon notification by PGT of the existence of the imbalance, Shipper shall have 3 days to correct the imbalance. Penalty: If, at the end of the 3 day period the difference between the actual delivered quantity and the receipt quantity is in excess of 10% of the delivered quantity or 1000 MMBTU, whichever is greater, the Shipper shall be assessed a charge of $5/MMBTU applied to the excess quantities. If the imbalance is not corrected within 45 days of PGT's notice of an imbalance, the Shipper shall be assessed an additional charge of $5/MMBTU, applied to the net imbalance remaining at the end of the 45 day balancing period. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 84 First Revised Volume No. 1-A Superseding Original Sheet No. 84 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING (Continued) (c) Actual quantity received exceeds delivered quantity A net negative imbalance shall exist if the difference between the delivered quantity and the quantity received taking into account the reduction in quantity for compressor fuel use, yields a negative result. Commencing upon notification by PGT of the existence of the imbalance, Shipper shall have 3 days to correct the imbalance. Penalty: If, at the end of the 3 day period the difference between the actual quantity received and the delivered quantity is in excess of 10% of the delivered quantity or 1000 MMBTU, whichever is greater, the Shipper shall be assessed a penalty of $2/MMBTU applied to the excess quantity. If the imbalance is not corrected within 45 days of PGT's notice of an imbalance, PGT shall be able to retain the remaining imbalance quantity without compensation to the Shipper and free and clear of any adverse claim. (d) Scheduled delivery quantity exceeds actual delivered quantity An imbalance shall exist when the quantity scheduled (nominated and confirmed) for delivery exceeds the actual delivered quantity. Penalty: When the difference between the scheduled delivery quantity and actual delivered quantity is in excess of 10% of the actual deliveries, or 1000 MMBTU, whichever is greater, the Shipper shall be assessed the maximum applicable interruptible transportation rate applied to the excess quantities. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 84A First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING (Continued) (e) Actual delivered quantity exceeds scheduled delivery quantity An imbalance shall exist when the quantity delivered exceeds the quantity scheduled (nominated and confirmed). Penalty: When the difference between the actual delivered quantity and the scheduled delivery quantity is in excess of 10% of the scheduled quantity or 1000 MMBTU whichever is greater, the Shipper shall be assessed a charge of $5/MMBTU applied to the excess quantity. Imbalance determinations as described above will be performed on a daily basis and each daily occurrence will constitute a separate incident. It is recognized and understood that more than one penalty provision may apply to each imbalance incident. In the event that any penalty would otherwise be applicable under these provisions as a direct consequence of any action or failure to take action by PGT or the failure of any facility under PGT's control, or an event of force majeure as defined in these Transportation General Terms and Conditions, said penalty shall not apply. The payment of a penalty in dollars pursuant to Paragraph 21 shall under no circumstances be considered as giving any Shipper the right to deliver or take overrun quantities. Upon termination of a Service Agreement, Shipper shall have 60 days to correct any remaining imbalances. After his period has elapsed, PGT shall have the right to retain any negative imbalance quantity without compensation to the Shipper and shall assess a charge of $5/MMBTU for any positive imbalance quantity as applicable. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 85 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 22. ANNUAL CHARGE ADJUSTMENT (ACA) PROVISION 22.1 Purpose: PGT shall recover from Shippers the annual charge assessedto PGT by the Federal Energy Regulatory Commission for budgetary expenses pursuant to Section 154.38(d)(6) of the Commission's regulations and Order No. 472 issued May 29, 1987. PGT shall recover this charge by means of an Annual Charge Adjustment (ACA); a per unit rate equivalent to the unit rate assessed against PGT by the Commission shall be included in PGT's transportation rates. (During the period that this ACA provision is in effect, PGT shall not recover in a Natural Gas Act Section 4 rate case annual charges recorded in FERC Account No. 928 assessed to PGT by the Commission pursuant to Order No. 472.) 22.2 Filing Procedure: The notice period and proposed effective date of filings pursuant to this paragraph shall be as permitted under Section 4 of the Natural Gas Act; provided, however, that any such filing shall not become effective unless they become effective without suspension or refund obligation. 22.3 ACA Unit Rate Adjustment: PGT's ACA unit rate shall be the unit rate used by the Commission to determine the annual charge assessment to PGT, and shall be reflected in the Statement of Effective Rates and Charges of this FERC Gas Tariff First Revised Volume No. 1-A. 22.4 Affected Rate Schedules: The ACA provision shall apply to all rate schedules contained in PGT's FERC Gas Tariff First Revised Volume No. 1-A. 23. SHARED OPERATING PERSONNEL AND FACILITIES PGT and its marketing affiliate do not share any operating personnel. PGT does not share any facilities with its marketing affiliate. To the extent PG&E elects service under Rate Schedule USS-1, PGT employees involved with the implementation of USS-1 service will operate independently from PGT's pipeline operating employees. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 86 First Revised Volume No. 1-A Superseding Original Sheet No. 86 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 24. COMPLAINT PROCEDURES 24.1 Any Shipper or potential Shipper may register a complaint regarding requested or provided transportation service. The complaint may be communicated to PGT primarily by use of PGT's Electronic Bulletin Board (EBB) and secondarily either orally, and/or in writing. Oral complaints should be made to PGT's Manager of Gas Transportation and Services, telephone (503) 833-4300. Written complaints should be sent via registered or certified mail, facsimile (FAX No. (503) 833-4396) , or hand delivered to: Pacific Gas Transmission Company 2100 Southwest River Parkway Portland, OR 97201 Attention: Manager of Gas Transportation and Services Oral, written and EBB-submitted complaints must contain the following minimum information: - Shipper or potential Shipper's name, address, and FAX and telephone numbers; - Shipper or potential Shipper's contact representative; - A clear, concise statement of the complaint. Each complaint will be recorded in PGT's Transportation Service Complaint Log maintained by PGT's Gas Transportation and Services Department located in Portland. Complaints will be logged by date and time received by PGT. 24.2 PGT will initially respond to each complaint within forty-eight (48) hours after PGT receives it. PGT will provide a written response to each complaint within thirty (30) days after PGT receives it. PGT's written response will be sent to Shipper or potential Shipper by certified or registered mail If the complaint was filed by the EBB, then PGT shall respond via the EBB. A copy of all complaints will be filed in the Transportation Service Complaint Log. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 87 First Revised Volume No. 1-A Superseding First Revised Sheet No. 87 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 25. INFORMATION CONCERNING AVAILABILITY AND PRICING OF TRANSPORTATION SERVICE AND CAPACITY AVAILABLE FOR TRANSPORTATION 25.1 Any affiliated or nonaffiliated Shipper or potential Shipper may obtain information concerning the availability and pricing of PGT's transportation services and the pipeline capacity available for transportation by: (a) Contacting PGT at: Pacific Gas Transmission Company Marketing and Transportation Department 2100 Southwest River Parkway Portland, OR 97201 Telephone: (503) 833-4300 or (California customers) Pacific Gas Transmission Company California Marketing Group 101 Spear Street, Suite 200 San Francisco, CA 94105 Telephone: (415) 778-3000 Fax: (415) 778-3091 Inquiries may be made orally or in writing. Upon request, PGT will provide to any Shipper or potential Shipper a copy of its FERC Gas Tariff, First Revised Volume No. 1-A, as well as any published notices concerning discounts then available to existing Shippers on the PGT system. (b) Subscribing to PGT's twenty-four (24) hour Electronic Bulletin Board by calling 1-503-833-4310. The Electronic Bulletin Board provides current information concerning the availability and pricing of transportation service on the PGT system, including all effective rates and discount notices, and capacity available for transportation. 25.2 The procedures to be followed by a potential Shipper requesting transportation service from PGT or by an existing Shipper requesting an amendment to its existing service or additional service from PGT are specified in Paragraph 18 of these Transportation General Terms and Conditions. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 88 First Revised Volume No. 1-A Superseding First Revised Sheet No. 88 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 25. INFORMATION CONCERNING AVAILABILITY AND PRICING OF TRANSPORTATION SERVICE AND CAPACITY AVAILABLE FOR TRANSPORTATION (Continued) 25.3 The procedures to be followed by Shippers for submitting nominations for transportation service are specified in Paragraph 19 of these Transportation General Terms and Conditions. 26. MARKET CENTERS The Market Center is defined as a point of interconnection between PGT and other pipelines and local distribution companies. PGT shall provide for Market Centers on PGT. Parties wishing to use Market Centers on the PGT system shall contact PGT for this service. At these Market Centers, entities may trade gas quantities without actively shipping the gas either upstream or downstream of the Market Center. Such entities must nominate for the gas transactions in accordance with the nomination procedures of the Transportation General Terms and Conditions of First Revised Volume No. 1-A. An entity's nomination for upstream supply and downstream delivery must match the corresponding upstream Shipper nomination and the downstream customer request. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 88A First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 27. PLANNED PGT CAPACITY CURTAILMENTS AND INTERRUPTIONS 27.1 When PGT needs to temporarily curtail or interrupt service to any Shipper hereunder for the purpose of making planned alterations or repairs, PGT shall give Shipper as much notice as possible of the process so that each Shipper's firm transportation requirements are taken into account in the planning process. 27.2 In the spring of each year PGT shall publish on its electronic bulletin board (EBB) to all Shippers a schedule of planned major maintenance and repairs which affect system capacity. The schedule shall show the estimated delivery point capacity for the next 12 months. 27.3 On a daily basis PGT shall post, on its EBB, capacity for each forthcoming gas day plus the estimated capacity for the next two gas days. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 89 First Revised Volume No. 1-A Superseding Original Sheet No. 89 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE 28.1 Eligibility to Release Any firm Shipper which contracts for firm transportation service under Part 284 of the Commission's regulations (Releasing Shipper) is eligible to release all or part of its capacity (Parcel) for use by another party (Replacement Shipper). Any Replacement Shipper which has previously contracted for a Parcel may also release its capacity to another party as a secondary release subject to the terms and conditions described herein. Upon releasing a Parcel, consistent with the terms and conditions described herein, all Releasing Shippers shall remain ultimately liable for all reservation charges billable for the originally contracted service. The Releasing Shipper, whether a primary or secondary capacity holder, must post the capacity it seeks to release on PGT's Electronic Bulletin Board (EBB) prior to the close of the Posting Period defined herein. A Releasing Shipper may release all or a portion of its capacity for the remainder of the term of its contract and extinguish its contractual obligations to PGT with respect to that portion provided that: 1) the Replacement Shipper for this capacity is creditworthy pursuant to PGT's credit standards; and 2) that the rate paid by the Replacement Shipper be no less than the rate contracted between the Releasing Shipper and PGT for the maximum volume, for the remaining term of the contract or the Releasing Shipper's maximum tariff rate. The release may be structured such that the right of first refusal may transfer to the Replacement Shipper even if the release has recall provisions and has been recalled by the Releasing Shipper at the end of the service agreement. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 Pacific Gas Transmission Company FERC Gas Tariff Sub. Second Revised Sheet No. 90 First Revised Volume No. 1-A Superseding First Revised Sheet No. 90 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.2 Types of Release A Releasing Shipper may release a Parcel for a term (Release Term) up to or equivalent to the remaining term under its service agreement with PGT. Types of releases include: Rapid Release - thirty-one days or less, is not prearranged, requires bidding and is restricted to options 1 or 2 for the allocation of Parcels without special terms or conditions. A standard recall provision may be selected. (Capacity up to the full quantity of the release maybe recallable on 2 business days notice. This capacity may be returned to the Replacement Shipper on 2 business days notice. Replacement Shipper may refuse to accept such capacity returned in this fashion.) Standard Release - greater than or equal to one day, is not prearranged, and requires bidding. Prearranged Deal-A - less than or equal to thirty-one days. This type of release is prearranged and does not require bidding. Such prearranged deals shall be posted for informational purposes within 48 hours after the release transaction commences. This release cannot be rolled-over, renewed or otherwise extended beyond the term described above unless the Releasing Shipper follows the posting and bidding procedures that apply to the particular term sought contained in this Paragraph 28. The Releasing Shipper may not re-release this Parcel to the same Replacement Shipper until 28 days after the term of the initial release has ended. Rollovers are permitted without bidding or a waiting period provided the Prearranged Shipper agrees to pay the maximum rate and meet all the other terms and conditions of the release. Prearranged Deal-B - greater than or equal to thirty-one days at the maximum rate bid pursuant to the methodology selected by Releasing Shipper. This type of release is prearranged and does not require bidding. Prearranged Deal-C - greater than or equal to one day at a rate less than the maximum rate bid pursuant to the methodology selected by the Releasing Shipper. This type of release is prearranged, allows for bidding, and allows the right of first refusal. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Mgr. Gas Supply & Reg. Affairs Issued on: JUNE 19, 1995 Effective: JULY 10, 1995 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RM95-5-00, dated MAY 31, 1995 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 91 First Revised Volume No. 1-A Superseding First Revised Sheet No. 91 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.3 Notice Requirements Any Releasing Shipper electing to release capacity shall submit a notice via PGT's EBB that it elects to release firm capacity. The notice shall set forth the following information: (a) Releasing Shipper's legal name, contract number, and the name, title, address, telephone number, and fax number of the individual responsible for authorizing the release of capacity. (b) Rate schedule of the Releasing Shipper. (c) Whether bidders will bid on the reservation charge or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load-factor basis. If a volumetric rate is used, Releasing Shipper must indicate whether bids on a reservation charge basis will be accepted as well and if so must specify the method of evaluating the two types of bids. Releasing Shipper also should indicate whether bids will be accepted on a dollar basis or as a percentage of the Releasing Shipper's as-billed rate. (d) Daily quantity of capacity to be released, expressed in MMBtu/d, at the designated delivery point(s). (This must not exceed Releasing Shipper's maximum contract demand available for capacity release and shall state the minimum quantity expressed in MMBtu/d acceptable for release.) (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 92 First Revised Volume No. 1-A Superseding Original Sheet No. 92 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.3 Notice Requirements (Continued) (e) The term of the release, identifying the date release is to begin and terminate. The minimum release term acceptable to PGT shall be one day. (f) Whether the Releasing Shipper is willing to consider release for a shorter period of time than that specified in (e) above and if so, the minimum acceptable period of release. (g) The receipt and delivery point. (h) Whether Option 1, 2, or 3 shall be used to determine the highest valued bid. If Option 3 is selected, Releasing Shipper must describe the criteria by which bids are to be evaluated. (i) Whether the Releasing Shipper wants PGT to market its released capacity. (j) Whether the Releasing Shipper requests to waive the creditworthiness requirements and agrees in such event to remain liable for all charges, or, if the release is for one year (365 days) or less, whether Releasing Shipper requests that the creditworthiness provisions of Paragraph 18.3(A)(1)(c) shall apply. (k) Whether Releasing Shipper is a marketing or other affiliate of PGT. (l) If release is a prearranged release, the Prearranged Shipper must be qualified pursuant to the criteria of Paragraph 28.6(a) unless waived above. Releasing Shipper shall include the Prearranged Shipper bid information pursuant to Paragraph 28.6(b) with its release information and shall indicate whether the Prearranged Shipper is affiliated with PGT or the Releasing Shipper. (m) Any special nondiscriminatory terms and conditions applicable to the release. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: MAY 31, 1994 Effective: MAY 21, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-211-000, dated MAY 20, 1994 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 93 First Revised Volume No. 1-A Superseding Original Sheet No. 93 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.3 Notice Requirements (Continued) (n) Tie-breaker method preferred: (1) pro rata, (2) lottery, (3) order of submission (first-come/first-serve), (4) other. Other method must be objectively stated, administratively feasible as determined by PGT and nondiscriminatory. If none are selected, the system defaults to pro rata. (o) Recall provisions. These provisions must be objectively stated, nondiscriminatory, applicable to all bidders, operationally and administratively feasible as determined by PGT and in accordance with PGT's tariff. (p) The minimum rate (percentage of: reservation charge or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load-factor basis) acceptable to Releasor for this Parcel. Releasing Shipper also should indicate whether bids will be accepted on a dollar basis or as a percentage of the Releasing Shipper's as-billed rate. (q) Whether the Releasing Shipper is willing to accept contingent bids that extend beyond the close of the Bid Period and, if so, any nondiscriminatory terms and conditions applicable to such contingencies including the date by which such contingency must be satisfied (which date shall not be later than the last day upon which PGT must award capacity) and whether, or for what time period, the next highest bidder(s) will be obligated to acquire the capacity should the winning contingent bidder be unable to satisfy the contingency specified in its bid. (r) Whether the Releasing Shipper wants to specify a longer bidding period for its Parcel than specified at Paragraph 28.8. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 94 First Revised Volume No. 1-A Superseding Original Sheet No. 94 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.4 Marketing of Capacity Fee PGT may act as a facilitator between a Releasing Shipper and a Replacement Shipper(s) that wishes to contract for that Releasing Shipper's capacity. All such Parcels must be posted on the EBB initially. A posting of a Parcel facilitated by PGT will include both the Parcel by the Releasing Shipper and the bid by the Prearranged Shipper. A marketing of capacity fee shall be negotiated between PGT and Releasing Shipper in a nondiscriminatory manner. Such a fee will apply when: a Releasing Shipper requests PGT to market released capacity, PGT actively markets such capacity beyond posting on the EBB, and such marketing results in capacity being released to a Replacement Shipper. 28.5 Posting of a Parcel The posting of a Parcel constitutes an offer to release the capacity provided a willing Replacement Shipper submits a valid bid consistent with PGT's Transportation General Terms and Conditions. The posting must contain the information contained in Paragraph 28.3. Any specific conditions posted by the Releasing Shipper must be operationally feasible, nondiscriminatory to other shippers, and in conformance with PGT's tariffs. If the Parcel is being released as a secondary release, then any recall provisions included in the primary release which may affect the re-release of this capacity must be included in the terms and conditions of the secondary release. Each Parcel will be reviewed by PGT prior to posting on the EBB for bidding. The receipt of a valid release will be acknowledged by the issuance of a release confirmation to the Releasing Shipper's EBB mailbox by PGT. It is the Releasing Shipper's sole responsibility to provide release and Prearranged Shipper bid information in advance of the close of the Posting Period. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 95 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.5 Posting of a Parcel (Continued) Releasing Shippers who elect to release capacity and select Option 3 for the highest valued bid methodology and/or include, in their release, nondiscriminatory recall provisions and/or special terms and conditions are required to submit their request to release capacity by 12:00 p.m. Pacific Time at least two business days before the close of the Posting Period. This is to ensure adequate time for PGT to review and validate that the Option 3 criteria and/or any recall and special terms and conditions are not discriminatory. All Prearranged Shipper bids are subject to the Prearranged Shipper(s) meeting the preliminary qualifications as defined in Paragraph 28.6(a) for Replacement Shippers. A Parcel may be revised or withdrawn by the Releasing Shipper at any time prior to the close of the Posting Period. A Parcel cannot be revised after the close of the Posting Period. Parcels may be withdrawn subsequent to the close of the Posting Period and up until the close of the Bid Period only in situations where the Releasing Shipper has an unanticipated need for the capacity. In such instances, Releasing Shipper shall notify PGT via the EBB of its need to withdraw the Parcel due to an unanticipated need for the capacity. The withdrawal or revision of a Parcel will terminate all bids submitted for that Parcel to date. Replacement Shippers will need to resubmit their bids for the Parcel if the Parcel is resubmitted for release. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 96 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (a) Preliminary Qualification To bid for a Parcel, a Replacement Shipper must: pre-qualify by submitting a completed request for authority to bid for a Parcel, meet PGT's credit criteria, and execute an FTS-1 service agreement for capacity release as set forth in these Transportation General Terms and Conditions. Replacement Shippers may carry out these requirements through the use of PGT's EBB. Replacement Shippers are encouraged to pre-qualify in advance of any postings on PGT's EBB as credit requirements will take differing amounts of time to process depending on the particular financial profile of Replacement Shippers. The pre-qualification process will authorize a pre-set maximum monthly financial exposure level for the Replacement Shipper. Such exposure levels may be adjusted by PGT periodically re-evaluating a Replacement Shipper's credit-worthiness. Releasing Shippers may exercise their option to waive the credit requirements for any Replacement Shipper wishing to bid on a Parcel posted by that Releasing Shipper. Such waiver must be made on a nondiscriminatory basis. PGT must be informed of such waiver via the EBB before it will authorize such Replacement Shipper's participation with respect to that particular Parcel. In this instance, no pre- set maximum monthly financial exposure level is applicable. Should a Releasing Shipper waive the credit requirements for a Replacement Shipper, the Releasing Shipper shall be liable for all charges incurred by the Replacement Shipper in the event such Replacement Shipper defaults on payment to PGT for such capacity release service. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 97 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (a) Preliminary Qualification (Continued) The execution of the FTS-1 service agreement for capacity release is to be signed "electronically" by the Replacement Shipper. The Replacement Shipper shall execute the FTS-1 service agreement for capacity release (exhibits excluded) through the use of an authorization code procedure on the EBB. Upon notification by PGT of an award of a Parcel, PGT shall complete Exhibit R with the particulars of the awarded Parcel and Replacement Shipper shall execute, electronically, Exhibit R to the FTS-1 service agreement for capacity release. A hard copy of the FTS-1 service agreement for capacity release, including Exhibit R (signed by hand by PGT and Replacement Shipper), will follow subsequent to the awarding of a Parcel. A Replacement Shipper that subsequently obtains additional Parcels is not required to execute an additional FTS-1 service agreement for capacity release; rather, for each such additional Parcel obtained, an additional Exhibit R (designated sequentially "Exhibit R-2", "Exhibit R-3", etc.) will be executed and amended to such Replacement Shipper's FTS-1 service agreement for capacity release. Once the Replacement Shipper has met PGT's preliminary contractual and credit requirements, PGT will amend the Replacement Shipper's authorization to add access to the bidding and releasing portions of PGT's capacity release program on its EBB. This authorization, in combination with the Replacement Shipper's password, which will be unique and known only by the Replacement Shipper, will entitle the (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 98 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (a) Preliminary Qualification (Continued) Replacement Shipper to submit a bid for a Parcel. Once a Replacement Shipper has acquired capacity, authority is granted to the Replacement Shipper to release that capacity. The execution of the FTS-1 service agreement for capacity release and use of this authorization to submit a bid or to release capacity will constitute an obligation on the part of the Replacement Shipper to be bound by the terms and conditions of PGT's capacity release program as set forth in these Transportation General Terms and Conditions. (b) Submitting a Bid All bids must be submitted through the use of PGT's EBB. Such bids shall be "open" for all participants to review. The particulars of all bids will be available for review but not the identity of bidders. PGT will post the identity of the winning bidder(s) only. A Replacement Shipper cannot request that its bid be "closed", nor can a Releasing Shipper specify that "closed" bids be submitted on its releases. A Replacement Shipper may submit only one bid per Parcel posted at any one point in time. Bids received after the close of the Bid Period shall be invalid. The Replacement Shipper may bid for no more than the quantity of the Parcel posted by the Releasing Shipper. Simultaneous bids for more than one Parcel are permitted. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 99 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (b) Submitting a Bid (Continued) A valid bid to contract for a Parcel must contain the following information: (1) Replacement Shipper's legal name, address, telephone and fax numbers and the name and title of the individual responsible for authorizing the bid. (2) The identification of the Parcel bid on. (3) Term of service requested. The term of service must not exceed the term included in the Parcel. (4) Percentage of the applicable maximum rate, as identified in the Parcel, that Replacement Shipper is willing to pay. A Replacement Shipper may not bid below the minimum applicable charge or rate nor above the maximum authorized charge or rate for the Parcel. (5) The quantity desired not to exceed the quantity contained in the Parcel, expressed on a MMBtu/d delivered basis and greater than the minimum quantity acceptable to Replacement Shipper. (6) Under Options 1 or 2 acceptance or rejection of all recall provisions and special nondiscriminatory terms and conditions of service associated with the release. Rejection of any terms results in an invalid bid. (7) Whether or not Replacement Shipper is an affiliate of the Releasing Shipper. (8) A statement as to whether or not Replacement Shipper is affiliated with PGT. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 100 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (b) Submitting a Bid (Continued) (9) An affirmative statement that Replacement Shipper agrees to be bound by the terms and conditions of Rate Schedule FTS-1 and PGT's capacity release provisions in its tariff. (10) Whether the bid is a contingent bid and the contingencies which must be satisfied by the date specified by the Releasing Shipper in its posting of the Parcel. (c) Confirmation of Bids The receipt of a valid bid by PGT will be acknowledged by the issuance of a bid confirmation to the Replacement Shipper's EBB mailbox by PGT. It is the Replacement Shipper's sole responsibility to verify the correctness of the submitted bid and to take any corrective action necessary by resubmitting a bid when notified of an invalid or incomplete bid by PGT via the EBB. This must be done before the close of the Bid Period. (d) Withdrawn or Revision of Bids A previously submitted bid may be withdrawn or revised and resubmitted at any time prior to the close of the Bid Period with no obligation on the Replacement Shipper's part. Resubmitted bids must be equal to or greater in value than the initial bids. Lower valued bids will be invalid. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 101 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (a) Primary Allocation Winning bids for Parcels shall be awarded based on one of the following three options to be selected by the Releasing Shipper when posting a Parcel: Option 1 - Price Bids will be given priority based on the maximum rate bid as represented by a Replacement Shipper's bid of the percentage of: the maximum authorized reservation charge or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load factor basis. Releasing Shippers using a volumetric rate and wishing to accept reservation charge bids will be considered an Option 3 criteria. In this instance Releasing Shipper must define the method for evaluating such bids. A bid queue will be maintained for each individual Parcel. Option 2 - Net Present Value Bids will be given priority based on the net present value per MMBtu for the term of the bid according to the following formula: n (1 + i) -1 Present Value per unit = P * R * _________ n i (1 + i) where: P = percent of the rate or charge that the Replacement Shipper is willing to pay. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 102 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (a) Primary Allocation (Continued) R = Rate or charge calculated as: The maximum authorized reservation charge (or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load factor basis) in effect at the time of the bid for service from the same receipt point to the same delivery point under the Releasing Shipper's rate schedule. i = FERC's annual interest rate divided by 12. n = number of periods for which the bidder wishes to contract, not to exceed the maximum periods to be released by the Releasing Shipper. For releases greater than or equal to one month, the period is the number of months. For releases less than one month the period is the number of days. A bid queue will be maintained for each individual Parcel. Option 3 - Releasing Shipper's Criteria for Highest Valued Bids Bids will be given priority based on the criteria established by the Releasing Shipper for determining the highest valued bids. The criteria must be objectively stated, applicable to all potential bidders, operationally and administratively feasible as determined by PGT, nondiscriminatory, and in conformance with PGT's tariff. A bid queue will be maintained for each individual Parcel. If Releasing Shipper does not specify an option for determining best bid, Option 2 will be the default option used. Under all options, PGT will evaluate and rank all bids for Parcels. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02,1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 103 First Revised Volume No. 1-A Superseding Original Sheet No. 103 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (b) Right of First Refusal In the case of a Prearranged Shipper's bid for a Parcel with a term equal to one month or greater, at a rate other than at the highest valued bid, pursuant to the methodology specified by the Releasing Shipper, if the bid submitted by a subsequent Replacement Shipper exceeds the value of the Prearranged Shipper's bid, the Prearranged Shipper will be allowed to match the higher valued bid. The Prearranged Shipper will be allowed 1 business day from the close of the Bid Reconciliation Period to match the higher valued bid, otherwise, the allocation will be awarded to subsequent Replacement Shipper(s) in accordance with the primary and secondary allocation mechanisms. (c) Secondary Allocation To the extent there is more than one Replacement Shipper submitting a winning bid, the Parcel shall be allocated based on one of the following tie-breaker methodologies to be selected by the Releasing Shipper: pro rata, lottery, order of submission (first come/first serve), or by a method designated by the Releasing Shipper. Releasing Shipper's method must be objectively stated, applicable to all bidders, nondiscriminatory, administratively feasible as determined by PGT and in accordance with PGT's tariffs. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 104 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (d) Confirmation of Allocation Upon each completion of an allocation, the successful Replacement Shipper(s) will be notified of the terms under which they have contracted for the awarded Parcel. The notification will be provided in the form of a notice in the Replacement Shipper's EBB mailbox. The notice will include an Exhibit R to the Replacement Shipper's Rate Schedule FTS-1 service agreement for capacity release which specifies the pertinent terms of the Replacement Shipper's bid as well as any additional terms specified by the Releasing Shipper. The Releasing Shipper will be notified of the terms under which its Parcel has been awarded. The notification will be provided in the form of a notice in the Releasing Shipper's EBB mailbox. The notification will include an Exhibit C to the Releasing Shipper's service agreement which specifies the pertinent terms of the credit to be applied to the Releasing Shipper as a result of the awarding of Parcel to the Replacement Shipper(s). In the case of multiple Replacement Shippers and Parcels, an Exhibit C to the Releasing Shippers' service agreement will be generated for each Parcel and Replacement Shipper. The Exhibit C's shall be numbered sequentially as Exhibit C-1, C-2, etc. (e) Purging of Expired Bids All unfulfilled bids, as well as any unfulfilled portions of bids which receive a partial award, will become ineffective as of the completion of bid reconciliation and the close of the Bid Period. Each unsuccessful Replacement Shipper which has bid shall receive a notice in its EBB mailbox indicating the ineffectiveness of the bid. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 105 First Revised Volume No. 1-A Superseding Original Sheet No. 105 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (e) Purging of Expired Bids (Continued) Information regarding all bids for all Parcels shall be archived off-line before being purged from the system. 28.8 Scheduling of Parcels, Bids and Notifications (a) Rapid Release - one month or less, not prearranged. Posting Period - up to 12:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. Bid Period - a minimum period of 2 hours subsequent to the close of the Posting Period. The bid period may be extended by the Releasing Shipper. The Bid Period closes at 2:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. Notification of the results of the bidding for Parcels will be posted at 2:00 p.m. Pacific Time on the 2nd business day prior to the commencement of the Release Term. (b) Standard Release-greater than or equal to one day, not prearranged. Posting Period - up to 12:00 p.m. Pacific Time 5 business days prior to the commencement of the Release Term. Bid Period - a minimum period of 1 business day subsequent to the close of the Posting Period. The Bid Period closes at 2:00 p.m. Pacific Time 4 business days prior to the commencement of the Release Term. Bid Reconciliation Period - a period of 2 business days subsequent to the close of the Bid Period. The Bid Reconciliation Period closes at 2:00 p.m. Pacific Time 2 business days prior to the commencement of the Release Term at which time notification of the results of the bidding for Parcels will be posted. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Sub. Second Revised Sheet No. 106 First Revised Volume No. 1-A Superseding First Revised Sheet No. 106 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.8 Scheduling of Parcels, Bids and Notifications (Continued) (c) Prearranged Deal-A - less than or equal to thirty-one days. Releasing Shipper must inform PGT via the EBB of the particulars of the prearranged deal by 12:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. Posting Period - PGT will post the particulars of the prearranged deal no later than 12:00 p.m. Pacific Time 2 business days after the commencement of the Release Term. (d) Prearranged Deal-B - equal to or greater than thirty-one days at the highest valued bid pursuant to the methodology selected by the Releasing Shipper. Posting Period - Releasing Shipper must submit the particulars of the prearranged deal to PGT for posting on the EBB no later than 12:00 p.m. Pacific Time 2 business days before the commencement of the Release Term. (e) Prearranged Deal-C - greater than or equal to one day. Posting Period - up to 12:00 p.m. Pacific Time on the 6th business day before the commencement of the Release Term. Bid Period - a minimum period of 1 business day subsequent to the close of the Posting Period. The Bid Period closes at 2:00 p.m. Pacific Time on the 5th business day before the commencement of the Release Term. Bid Reconciliation Period - a period of 2 business days subsequent to the close of the Bid Period. The Bid Reconciliation Period closes at 2:00 p.m. Pacific Time on the 3rd business day before the commencement of the Release Term. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Mgr. Gas Supply & Reg. Affairs Issued on: JUNE 19, 1995 Effective: JULY 10, 1995 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RM95-5-000, dated MAY 31, 1995 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 107 First Revised Volume No. 1-A Superseding Original Sheet No. 107 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.8 Scheduling of Parcels, Bids and Notifications (Continued) (e) Prearranged Deal-C - greater than or equal to one day (Continued) Match Period - a period of 1 business day subsequent to the close of the Bid Reconciliation Period. The Match Period closes at 2:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. At that time results of the bidding shall be posted no later than 2:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 108 First Revised Volume No. 1-A Superseding Original Sheet No. 108 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) Reserved For Future Use. ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 109 First Revised Volume No. 1-A Superseding Original Sheet No. 109 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.9 Crediting, Billing Adjustments and Refunds (a) Eligibility PGT shall provide revenue credits to any Releasing Shipper which releases capacity to a Replacement Shipper pursuant to the provisions of Paragraph 28. (b) Monthly Crediting Procedure Revenue credits for released capacity shall be credited monthly as an offset to a Releasing Shipper's reservation charge (or the volumetric equivalent of the reservation charge on a 100% load- factor basis applicable to the Releasing Shipper. This shall also be referred to in this Paragraph 28.9 as the equivalent volumetric rate) payable to PGT under the applicable rate schedule for the service that has been released. PGT shall credit each month to the Releasing Shipper's account 100% of the revenues from the charges invoiced to the Replacement Shipper(s) for the reservation charge (or equivalent volumetric rate). (c) Billing Adjustments PGT shall apply the revenues received from Replacement Shippers first to the reservation charge (or equivalent volumetric rate), next to the GRI reservation surcharge. Should Replacement shipper default on payment to PGT of the reservation charge (or equivalent volumetric rate) PGT shall bill Releasing Shipper for such unpaid charges and apply interest to such adjustments in accordance with the provisions of Paragraph 8 of the Transportation General Terms and Conditions. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 110 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.9 Crediting, Billing Adjustments and Refunds (Continued) (d) Excess Revenue Credits Releasing Shipper is entitled to excess revenue credits resulting when the reservation charge (or equivalent volumetric rate) revenues actually received by PGT from the Replacement Shipper(s) exceed the reservation charge (or equivalent volumetric rate) revenues which would have been received by PGT from the Releasing Shipper if capacity was not released. (e) Refunds PGT shall track all changes in its rates approved by the Commission. In the event the Commission orders refunds of any such rates charged by PGT and previously approved, PGT shall make corresponding refunds to all affected Shippers including Shippers receiving capacity release service. In such instances when rates to Replacement Shippers are reduced, PGT shall make corresponding adjustments to the crediting of revenues to Releasing Shippers for the period such refunds are payable. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 111 First Revised Volume No. 1-A Superseding Original Sheet No. 111 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) (STANDARD RELEASE) SEE GRAPHIC INDEX AT REAR OF DOCUMENT. (CAPACITY RELEASE TIMELINE GRAPH) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Sheet No. 112 First Revised Volume No. 1-A Superseding Original Sheet No. 112 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) (RAPID RELEASE) SEE GRAPHIC INDEX AT REAR OF DOCUMENT. (CAPACITY RELEASE TIMELINE GRAPH) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Sub. Second Revised Sheet No. 113 First Revised Volume No. 1-A Superseding First Revised Sheet No. 113 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) (PRE-ARRANGED DEAL - A) SEE GRAPHIC INDEX AT REAR OF DOCUMENT. (CAPACITY RELEASE TIMELINE GRAPH) ________________________________________________________________________________ Issued by: R.T. Howard, Mgr. Gas Supply & Regulatory Affairs Issued on: JUNE 19, 1995 Effective: JULY 10, 1995 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RM95-5-000, dated MAY 31, 1995 Pacific Gas Transmission Company FERC Gas Tariff Sub. Second Revised Sheet No. 114 First Revised Volume No. 1-A Superseding First Revised Sheet No. 114 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) (PRE-ARRANGED DEAL - B) SEE GRAPHIC INDEX AT REAR OF DOCUMENT. (CAPACITY RELEASE TIMELINE GRAPH) ________________________________________________________________________________ Issued by: R.T. Howard, Mgr. Gas Supply & Reg. Affairs Issued on: JUNE 19, 1995 Effective: JULY 10, 1995 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RM95-5-000, dated MAY 31, 1995 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 115 First Revised Volume No. 1-A Superseding Original Sheet No. 115 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) (PRE-ARRANGED DEAL - C) SEE GRAPHIC INDEX AT REAR OF DOCUMENT. (CAPACITY RELEASE TIMELINE GRAPH) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 116 First Revised Volume No. 1-A Superseding Sheet Nos. 116 - 118 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) Reserved For Future Use ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 119 First Revised Volume No. 1-A Superseding Original Sheet No. 119 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS 29.1 Firm Service (a) Addition of a Receipt Point Any firm Shipper receiving service under Part 284 of the Commission's regulations is entitled to use the receipt point specified in its service agreement as a primary receipt point. A firm Shipper may add a secondary receipt point, provided the secondary receipt point is downstream of the primary receipt point at any time during the life of the contract. Firm Shippers who are billed under a reservation charge and a delivery rate will continue to be billed reservation charges based on the primary receipt point while delivery rates, including fuel, will be calculated on the receipt point actually used. To the extent additional meter station capacity or other facilities are required to effect the receipt point change, PGT will construct the additional capacity consistent with Paragraph 18.5. (b) Changing a Receipt Point A firm Shipper may change primary receipt points to a downstream receipt point but will continue to be billed reservation charges based on the original primary receipt point. Changes in receipt points will be permitted provided sufficient receipt point capacity exists at the receiving meter station and subject to any operating constraints. To the extent additional meter station capacity or other facilities are required to effect the receipt point change, PGT will construct the additional capacity at the firm Shipper's expense consistent with Paragraph 18.5. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 120 First Revised Volume No. 1-A Superseding Original Sheet No. 120 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued) 29.1 Firm Service (Continued) (c) Addition of a Delivery Point Each firm Shipper is entitled to an allocation of its MDQ to a delivery point(s) as its primary delivery point(s). A firm Shipper may add secondary delivery points provided the secondary delivery points are upstream of the primary delivery point, at any time during the life of the contract. In this case, the firm Shipper will continue to be billed any applicable reservation charges based on the primary delivery point; however, delivery rates, including fuel, will be calculated based on the delivery point actually used. A firm Shipper with primary deliveries allocated to a minor delivery point may add secondary delivery points to its contract provided that the addition of the secondary delivery point does not materially impact service to other firm Shippers. To the extent additional meter station capacity is required to effect the delivery point(s) change, and subject to any operating constraints PGT will construct the additional capacity consistent with Paragraph 18.5. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 121 First Revised Volume No. 1-A Superseding Original Sheet No. 121 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued) 29.1 Firm Service (Continued) (d) Changing a Delivery Point A firm Shipper may change primary delivery points, to an upstream delivery point but will continue to be billed reservation charges based on the original primary delivery point. Changes in delivery points will be permitted provided sufficient delivery point capacity exists at the delivery meter station. To the extent additional meter station and subject to any operating constraints capacity is required to effect the delivery point change, PGT will construct the additional capacity at the firm Shipper's expense consistent with Paragraph 18.5. A firm Shipper with primary deliveries allocated to a minor delivery point may change primary delivery points in its contract provided that the change of primary delivery point does not materially impact service to other firm Shippers. 29.2 Interruptible Service (a) Change of a Receipt/Delivery Point Interruptible Shippers will have the right to flexible receipt and delivery points, at a lower priority than firm or released services. (b) Addition of a Receipt Point Except as otherwise provided in this paragraph, Shippers receiving service under any Part 284 interruptible transportation rate schedule may add any receipt point downstream of the primary receipt point on the PGT system at any time during the life of the contract with no effect on the Interruptible Shipper's previously granted interruptible transportation priority. However, requests by an interruptible Shipper to increase its total MDQ and/or to add an upstream receipt point will be considered a new request for service. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 122 First Revised Volume No. 1-A Superseding Original Sheet No. 122 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued) 29.2 Interruptible Service (Continued) (c) Addition of a Delivery Point An Interruptible Shipper may request interruptible service at additional delivery points at any time. The request of an additional downstream delivery point, or a request to increase the delivery quantity at an existing delivery point, will be considered a new request for service with priority assigned in accordance with Paragraph 19.2. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 123 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS 30.1 Purpose This Paragraph 30 establishes the means by which PGT shall recover GSR Costs. PGT will make one or more separate rate filings to recover GSR Costs pursuant to this Paragraph 30. 30.2 Definitions The following defines certain terms as they are used in this Paragraph 30: (a) "Gas Supply Restructuring Costs" shall mean amounts in cash or other consideration eligible for recovery under Order Nos. 500, et seq., or 528, et seq., or 636, et seq., or which are incurred to restructure, reform or terminate the existing International Contract between PGT and A&S and underlying A&S gas supply contracts, or to resolve claims by Canadian gas suppliers related to past or future liabilities or obligations of PGT or A&S under the International Contract and underlying A&S gas supply contracts. (b) "The Initial GSR Cost Collection Period" will consist of the three (3) years commencing with the effective date of the rate filing to recover GSR Costs. An Initial GSR Cost Collection Period shall apply to each rate filing PGT makes to recover GSR Costs. (c) "Carryover GSR Cost Collection Period" will consist of the extension of the Initial GSR Collection Period in accordance with Paragraph 30.6 hereof to complete the full recovery (but no overrecovery) of PGT's GSR Costs. (d) "Approved GSR Costs" shall mean those GSR costs as defined in Paragraph 30.2(a) above, which are approved by FERC for recovery by PGT through the Transition Cost Recovery Mechanism as defined in this Paragraph 30. (e) "Northwest Shippers", for purposes of this paragraph, are defined as Washington Natural Gas Company, Cascade Natural Gas Company, Washington Water Power Company/WP Natural Gas and Northwest Natural Gas Company. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 124 First Revised Volume No. 1-A Superseding Original Sheet No. 124 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued) 30.3 Applicability of GSR Transition Costs GSR Transition Costs shall be applicable to all Shippers except those firm Shippers paying incremental rates on PGT which are also Supporting Parties to the FERC-approved settlement in Docket No. RS92- 46-000. 30.4 Recovery of Surcharge Amounts PGT shall recover from each Shipper meeting the applicability criteria defined in Paragraph 30.3 the affected Shipper's GSR Surcharge amounts and Direct Bill, if applicable, during the Initial GSR Cost Collection Period and shall continue to recover such amounts during any applicable Carryover GSR Cost Collection Period as necessary to complete the full recovery (but no overrecovery) of PGT's GSR Costs. 30.5 Transition Cost Recovery Mechanism (a) Absorption -- PGT's shareholder shall absorb 25% of all Approved GSR Costs. (b) Direct Bill -- 25% of all Approved GSR Costs will be recovered by PGT through a Direct Bill. A Direct Bill will be assessed to PG&E for 100% of the Direct Bill amount, excluding the amount to be collected from the Northwest Shippers and credited against the Direct Bill portion as defined in Paragraph 30.5(d). PG&E may pay its Direct Bill in a lump sum, plus carrying charges on the principal amount accrued, in accordance with Paragraph 30.5(e) until the payment is made. In lieu of paying the Direct Bill in a lump sum, PG&E may elect one of three payment schedules. PG&E's Direct Bill amount and the monthly amount due under each extended payment option, which shall include carrying charges accrued on the unpaid balance in accordance with Paragraph 30.5(e), shall be specified in the Statement of Effective Rates and Charges of First Revised Volume No. 1-A. (c) GSR Transition Cost Surcharge -- 50% of all Approved GSR Costs will be recovered by PGT through a volumetric MMBtu-mile surcharge. The GSR Transition Cost Surcharge shall include any applicable carrying charges accruing on the unrecovered balance. The GSR Transition Cost Surcharge shall be stated in the Statement of Effective Rates and Charges of PGT's FERC Gas Tariff First Revised Volume No. 1-A as the same may change from time to time, depending on PGT's GSR Costs. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: DECEMBER 10, 1993 Effective: NOVEMBER 15, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-24-000, dated NOVEMBER 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 125 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued) 30.5 Transition Cost Recovery Mechanism (Continued) (d) Northwest Shippers' GSR Cost Responsibility -- All Northwest Shippers (excluding Washington Natural Gas Company) shall pay a Direct Bill and Washington Natural Gas shall pay a GSR transition cost surcharge (different from that provided in (c) above) for their share of GSR transition costs. The Northwest Shippers' responsibility shall be equal to 1.3 percent of the Approved GSR costs that are not absorbed by PGT and in any event shall not exceed a total of $1,454,000. Of this amount, one-third, up to $485,000, will be credited against the amount allocated to the Direct Bill as described in Paragraph 30.5(b), and two-thirds, up to $969,000, will be credited against the amount allocated to the GSR surcharge provided in Paragraph 30.5(c). The amounts allocated to the Northwest Shippers as a group will be allocated among the individual Northwest Shippers based on the percentages shown below and will not exceed the applicable total amount for each Shipper.
Total Percentage Amount Washington Natural Gas Company 55.02% up to $ 800,000 Cascade Natural Gas Corporation 24.07% up to 350,000 Washington Water Power Company/ WP Natural Gas 18.57% up to 270,000 Northwest Natural Gas Company 2.34% up to 34,000 Total Northwest Shippers 100.00% $1,454,000
Washington Water Power Company/WP Natural Gas (WWP), Cascade Natural Gas Corporation (CNG), and Northwest Natural Gas Company (NNG) will be billed and will pay immediately all amounts of the Approved GSR Costs allocated to them up to the total maximums noted above. The total amount allocated to Washington Natural Gas Company (WNG) will be recovered through a volumetric surcharge over a three-year amortization period based on the approved commodity throughput for WNG. Any amounts not recovered at the end of the 36-month amortization period will be due and payable in one lump sum. Once the maximum GSR Costs applicable to Northwest Shipper(s), as such amounts may be adjusted pursuant to the application of rolled-in rates on the PGT system, have been collected then the GSR Cost tariff provisions will no longer apply to such Northwest Shipper(s). (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 126 First Revised Volume No. 1-A Superseding Original Sheet No. 126 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued) 30.5 Transition Cost Recovery Mechanism (Continued) (e) Carrying Charges -- Carrying charges shall accrue beginning on the effective date of PGT's filing to recover GSR costs or the date PGT initiates payment for GSR costs, whichever is later. Carrying charges shall be calculated in accordance with Section 154.67 of the Commission's regulations. 30.6 Reconciliation (a) At the conclusion of the Initial GSR Cost Collection Period, PGT will determine its GSR Costs and the actual amounts of GSR Transition Cost Surcharge revenues. (b) If PGT's collections hereunder shall equal or exceed its GSR Costs, PGT shall file to terminate further collections hereunder. The amount of any excess collected shall be repaid to all Shippers affected hereby in proportion to the principal amount of GSR Transition Cost Surcharge payments they have provided pursuant to this Paragraph 30. Within ninety (90) days of the termination of collections pursuant to this Paragraph 30, PGT will submit a report to the Commission setting out a comparison of its GSR costs and the amounts collected hereunder and any repayments to be provided hereunder. Within thirty (30) days of the Commission's approval of such report, repayments, with applicable carrying charges, shall be paid. (c) If PGT's collections hereunder are less than its GSR Costs, PGT shall be permitted to recover such deficiency, including carrying charges, during the Carryover GSR Cost Collection Period by filing with the Commission GSR Transition Cost Surcharges within ninety (90) days of the conclusion of the Initial GSR Cost Collection Period. The GSR Transition Cost Surcharge will be determined by dividing the remaining GSR costs by the applicable quantities underlying PGT's then-effective rates. The GSR Transition Cost Surcharge shall be effective on the first day of the month following Commission approval of such filing. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 127 First Revised Volume No. 1-A Superseding First Revised Sheet No. 127 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. Reserved (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 128 First Revised Volume No. 1-A Superseding Original Sheet No. 128 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) Reserved for future use. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 129 First Revised Volume No. 1-A Superseding First Revised Sheet No. 129 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 32. EQUALITY OF TRANSPORTATION SERVICE PGT hereby states that the terms and conditions of service for all unbundled sales and transportation services provided in PGT's FERC Gas Tariff Second Revised Volume No. 1 and First Revised Volume No. 1-A, are provided on a basis that is equal in quality for all Shippers. All Shippers can access all sellers of gas and receive the same quality of service on PGT whether their gas supplies are purchased from PGT or any other seller. Furthermore, no preference is accorded to any affiliate of PGT for sales and transportation services provided by PGT. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 130 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 33. RIGHT OF FIRST REFUSAL UPON TERMINATION OF FIRM SHIPPER'S SERVICE AGREEMENT Firm Shippers (original capacity holders) under PGT's firm transportation rate schedules of First Revised Volume No. 1-A shall have the right of first refusal at the termination of their service agreements. Original capacity holders must notify PGT one year prior to termination of their intent to terminate the service agreement. One year prior to the expiration of the service agreement, PGT will post a notice on its EBB that the original capacity holder's service agreement will terminate in one year and the original capacity holder has either elected or not elected to terminate. 33.1 In the event original capacity holder elects termination, PGT shall subject this capacity to a bidding process. PGT shall require bids be submitted no later than 6 months prior to the service agreement expiration. The bid period will be 2 months. PGT will announce the bid winner(s) 1 month after the close of the bid period. Tied bids will be awarded on a pro rata basis. Winning Shipper(s) and PGT must execute a new firm transportation service agreement prior to service commencement. 33.2 In the event original capacity holder does not elect termination, PGT will commence open bidding 6 months prior to the service agreement termination. The bid period will be 1 month. The original capacity holder will have 1 month from the close of the bid period to match the highest bid(s). PGT will announce the winning bid(s) within 1 month after the close of the match period. If the original capacity holder matches the highest bid(s), the capacity is awarded to the original capacity holder. If the original capacity holder does not match the highest bid(s), the original capacity holder's bid shall be rejected. If there is more than one winning bid, PGT shall award capacity on a pro rata basis. New Shippers must execute a firm transportation service agreement with PGT prior to service commencement. Original capacity holder is allowed to retain a portion of its capacity by matching price and term according to the procedure outlined in this provision. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 131 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 33. RIGHT OF FIRST REFUSAL UPON TERMINATION OF FIRM SHIPPER'S SERVICE AGREEMENT (Continued) 33.3 Bids shall be evaluated on the net present value incorporating price and term. The price shall be the rate Shippers are willing to pay up to the maximum authorized rate. The maximum term is 20 years. 33.4 If there are no competing bids other than that of the original capacity holder, the rate and terms of continuing service is to be negotiated between existing capacity holder and PGT. In addition, in this instance, if the existing capacity holder agrees to pay the maximum authorized rate, the existing capacity holder may determine the term it desires and PGT must extend its contract to the existing capacity holder accordingly. 33.5 Shippers who terminate their service agreements are not liable for any reservation charges or other charges applicable to the new Shipper contracting for this capacity. 33.6 Only bona fide bids will be accepted. A bona fide bid offer shall be: (a) submitted via PGT's EBB; (b) accepted in principle; and (c) pursuant to an arms-length transaction. If the Service Agreement is not executed within 30 days, the request for capacity shall expire without prejudice to the prospective Shipper's right to submit a new request for capacity. PGT shall then notify the Shipper via the EBB of the acceptable offer, if any, having the next greatest economic value in accordance with the provisions of this Paragraph. If there is no other acceptable offer, the Shipper may continue service in accordance with this Paragraph. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 132 First Revised Volume No. 1-A Superseding First Revised Sheet No. 132 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD 34.1 General PGT shall use its Electronic Bulletin Board (EBB), "Pacific Trail" for capacity release. PGT shall maintain an EBB which will provide a range of electronic pipeline services and information to all parties on a nondiscriminatory basis. The EBB is available to any party that has compatible equipment for electronic communication and transmission of data. Access to the EBB is obtained by contacting PGT's Gas Control Department at 1-800-238-2781 and requesting a user identification. The EBB will operate 24 hours a day; however, certain functions may be limited to specific operating times during the business day. There is no direct connection charge to use the EBB. However, PGT reserves the right to change the telephone access from an "800" number to a "900" number at its sole discretion. PGT shall exercise reasonable efforts to ensure the accuracy and security of information presented on the EBB. 34.2 Menu of Services and Information PGT's EBB will provide the following main menu of services and information: (a) Capacity Release (b) Bulletins and Capacity Available (c) Nominations (d) Submit Request for Firm or Interruptible Service (e) Interruptible Transportation Queue (f) Tariffs and Rates (g) Account Status of Shipper (h) Marketing Affiliate Information (i) Offers to Purchase Capacity (j) Procedures for Filing Complaints (k) E-mail to Other Shippers/PGT System Administrator (l) EBB Mailbox (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 133 First Revised Volume No. 1-A Superseding Original Sheet No. 133 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.2 Menu of Services and Information (Continued) (a) Capacity Release The capacity release menu would allow the following options: (1) Review Available Released Parcels (2) Submit/Check Status of Request for Authority to\ Bid/Release Capacity (3) Post/Withdraw Capacity for Release (4) Submit/Withdraw Bid for Released Capacity (5) Review the Status of Shipper's Active Bids (6) Review the Status of Shipper's Active Released Parcels (7) Review Shipper's Authority to Bid for Released Capacity (8) Review Transaction Log of Previous Releases (b) Bulletins and Capacity Available The bulletins and capacity available menu would allow the following options: Capacity Availability Information: (1) At Receipt Points (2) At Major Delivery Points (3) At Minor Delivery Points (4) Projected Capacity (5) PGT Maintenance Schedules (6) Whether the Capacity is Available From PGT or Through PGT's Capacity Release Program (7) Operational Bulletins (8) Regulatory Bulletins (c) Nominations (1) Submit Nominations to PGT Gas Control (2) Review Confirmation (3) E-mail to Gas Control (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 134 First Revised Volume No. 1-A Superseding Original Sheet No. 134 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.2 Menu of Services and Information (Continued) (d) Submit Request for Firm or Interruptible Service (e) Interruptible Transportation Queue (f) Tariffs and Rates The tariffs and rates menu would allow the following options: (1) Transportation Rates (2) Transportation Rate Discounts (including negotiated ITS-1 rates) (3) First Revised Volume No. 1-A - Tariff (4) Second Revised Volume No. 1 - Tariff (g) Account Status of Shippers (h) Marketing Affiliate Information The marketing affiliate information would allow the following options: (1) Transportation request data (2) Receipt/delivery point data (3) Delivery point discount data (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 135 First Revised Volume No. 1-A Superseding Original Sheet No. 135 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.2 Menu of Services and Information (Continued) (i) Offers to Purchase Capacity PGT shall post the following information on offers to purchase capacity: (1) Legal Name of Offerer (2) Name, telephone Number, Fax Number, Address of Contact Person and Alternate Contact Person (3) Firm or Interruptible Service Requested (4) Amount of Capacity Sought (5) Term Sought (6) Other Information (j) Procedures for Filing Complaints The Procedures for filing complaints menu offers the following options: (1) Review Complaint Procedure (2) Enter a Complaint (3) Send E-Mail to PGT System Administrator (k) E-Mail to other Shippers/PGT Systems Administrator (l) EBB Mailbox (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 136 First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.3 Historical Information PGT will back up daily transaction information on the EBB. This historical information shall be kept for a three-year period and may be archived off-line. Information that may be accessed includes Parcel information and bid information associated with that Parcel, including the identity of the winning bid and bidder. PGT will provide access to historical data in one of the following manners: (a) Direct access by parties via the EBB. In such cases, data may be viewed, down loaded to a computer or printed by the party. (b) PGT may elect to archive historical data off-line. Parties may access this data by sending a written or an electronic mail request to the PGT Capacity Release System Administrator requesting such historical data. PGT will make such information available to Shippers. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 137 First Revised Volume No. 1-A Superseding First Revised Sheet No. 137 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 35. Reserved (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 138 First Revised Volume No. 1-A Superseding Original Sheet No. 138 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) Reserved for future use. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 138A First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 35A. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES ON EXTENSIONS (1) Interruptible Transportation Revenue Credits on Coyote Springs Extension (a) Applicability. Revenue credits from interruptible transportation revenues received by PGT from Rate Schedule ITS-1 (E-3) Shippers shall be provided to PGT's firm Shippers under Rate Schedules FTS-1 (E-3) ("Eligible Shippers"), excluding Shippers receiving service under a Capacity Release Service Agreement. (b) Crediting Percentage. PGT shall credit to Eligible Shippers 90 percent of interruptible transportation revenues received during each 12-month period, commencing November 1st of each year, but only to the extent that such transportation revenues exceed the amount of fixed costs which were allocated to interruptible transportation (Cost Allocation Amount) by PGT as part of designing PGT's effective transportation rates during such 12-month period. To the extent that PGT is required to provide interruptible transportation revenue credits during any period during which this Paragraph 35A shall be or shall have been in effect for less than 12 months, a "Short Period", PGT shall pro rate the Cost Allocation Amount by the number of days during such Short Period as compared to the total number of days in such 12 months. To calculate the interruptible transportation revenue credit due under the provisions of this paragraph, where applicable, such pro rated Cost Allocation Amount shall be compared to PGT's actual interruptible revenues for the Short Period. (c) Timing of Credits. Within 45 days after November 1st of each 12-month period or after the end of a Short Period, if applicable, PGT shall determine the total amount of the applicable Rate Schedule ITS-1 (E-3) revenues received during the 12-month period or Short Period and the distribution of the interruptible revenue credits due to Eligible Shippers as described below. Such revenue credits shall be reflected as a credit billing adjustment in the next invoices rendered to the Eligible Shippers. In the event that such credit billing adjustment would result in a credit total invoice to any Shipper, PGT will refund the excess credit billing adjustment to the Shipper in cash within 15 days after determination of the amount of the credit due to the Shipper. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 29, 1995 Effective: NOVEMBER 01, 1995 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 138B First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 35A. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES ON EXTENSIONS (Continued) (1) Interruptible Transportation Revenue Credits on Coyote Springs Extension (Continued) (d) Exclusion. Revenue credits shall not be awarded for that portion of interruptible revenues that are attributable to: (1) the recovery by PGT of variable costs, which portion shall be equal to the minimum usage charge for Rate Schedule ITS-1 (E-3), (2) the recovery of Gas Supply Restructuring (GSR) costs to be recovered by a GSR volumetric surcharge under Rate Schedule ITS-1 (E-3), and (3) relate to other volumetric surcharges such as GRI and ACA. (e) Distribution Method. Interruptible transportation revenue credits shall be credited to each Eligible Shipper on a pro rata basis in proportion to the reservation revenues received during the 12-month period or Short Period from each Eligible Shipper divided by the total reservation revenue for each Eligible Shipper received during such period. The reservation revenues shall include the reservation charges which the Eligible Shippers actually pay prior to the distribution of all revenue credits, and including reservation charges applicable to capacity which was released into PGT's Capacity Release Programs during the 12-month period year or Short Period by the Eligible Shipper. (f) PGT shall pay interest to Eligible Shippers on any revenue credits from the date such credits accrue. Such interest shall be calculated based upon the rate of interest specified in Section 154.67(c) of the Commission's regulations. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 29, 1995 Effective: NOVEMBER 01, 1995 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 138C First Revised Volume No. 1-A ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 35A. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES ON EXTENSIONS (Continued) (2) Interruptible Transportation Revenue Credits on Medford Extension (a) Applicability. Revenue credits from interruptible transportation revenues received by PGT from Rate Schedule ITS-1 (E-1) Shippers shall be credited to the deferred account for Washington Water Power Company's WP Natural Gas subsidiary in accordance with the mechanism approved by Order of June 1, 1995, 71 FERC Paragraph 61,268. (b) Crediting Percentage. PGT shall credit to the deferred account 90 percent of interruptible transportation revenues received during each 12- month period, commencing November 1st of each year, but only to the extent that such transportation revenues exceed the amount of fixed costs which were allocated to interruptible transportation (Cost Allocation Amount) by PGT as part of designing PGT's effective transportation rates during such 12-month period. To the extent that PGT is required to provide interruptible transportation revenue credits during any period during which this Paragraph 35A shall be or shall have been in effect for less than 12 months, a "Short Period", PGT shall pro rate the Cost Allocation Amount by the number of days during such Short Period as compared to the total number of days in such 12 months. To calculate the interruptible transportation revenue credit due under the provisions of this paragraph, where applicable, such pro rated Cost Allocation Amount shall be compared to PGT's actual interruptible revenues for the Short Period. (c) Exclusion. Revenue credits shall not be awarded for that portion of interruptible revenues that are attributable to the recovery by PGT of variable costs, which portion shall be equal to the minimum usage charge for Rate Schedule ITS-1 (E-1). (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 29, 1995 Effective: NOVEMBER 01, 1995 Pacific Gas Transmission Company FERC Gas Tariff 2nd Sub. First Revised Sheet No. 139 First Revised Volume No. 1-A Superseding Original Sheet No. 139 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 36. DISCOUNT POLICY PGT may from time to time offer a discount from the maximum applicable rate for service under any service agreement governed by this FERC Gas Tariff. If and when PGT offers a discount, such discount shall first be applied to the GRI Surcharge and last to the base tariff rate. PGT shall not discount its GSR Surcharge. ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 26, 1996 Effective: SEPTEMBER 13, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RM95-3, 76-61,300, dated SEPTEMBER 28, 1995 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 140 First Revised Volume No. 1-A ________________________________________________________________________________ GENERAL TERMS AND CONDITIONS (Continued) 37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS, AND OTHER UNACCOUNTED FOR GAS PERCENTAGES The effective fuel and line loss percentages under Rate Schedules FTS-1 and ITS-1 shall be adjusted downward to reflect reductions and may be adjusted upward to reflect increases in fuel usage and line loss in accordance with this Section 37. 37.1 Computation of Effective Fuel and Line Loss Percentage The effective fuel and line loss percentage shall be the sum of the current fuel and line loss percentage and the fuel and line loss surcharge percentage. 37.2 The Current Fuel and Line Loss Percentage (a) For each month, the current fuel and line loss percentage shall be determined in accordance with Section 37.2(c) hereof. The current fuel and line loss shall be effective from the first day of such month and shall remain in effect for the month. (b) The current fuel and line loss percentage to be applicable for the month shall be posted on PGT's Electronic Bulletin Board not less than seven (7) days prior to the beginning of the month. (c) The current fuel and line loss percentage for the month shall be determined on the basis of (1) the estimated quantities of gas to be delivered by PGT for the account of Shippers during such month and (ii) the projected quantities of gas that shall be required for fuel and line loss during such month, adjusted for overrecoveries or underrecoveries of fuel and line loss during such month preceding the month in which the current fuel and line loss percentage is posted; provided, that the percentage shall not exceed the maximum current fuel and line loss percentage and shall not be less than the minimum current fuel and line loss percentage set forth on the Statement of Effective Rates and Charges. (Continued) ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: DECEMBER 22, 1993 Effective: JANUARY 22, 1994 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 141 First Revised Volume No. 1-A Superseding Original Sheet No. 141 ________________________________________________________________________________ GENERAL TERMS AND CONDITIONS (Continued) 37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS AND OTHER UNACCOUNTED FOR GAS PERCENTAGES (Continued) 37.2 The Current Fuel and Line Loss Percentage (Continued) (d) At least thirty (30) days prior to July 1 and January 1, PGT shall file with the Commission schedules supporting the current fuel and line loss percentages applicable during the six (6) months ending April 30 and October 31, respectively. 37.3 The Fuel and Line Loss Surcharge Percentage (a) For each six (6) month period beginning July 1 and January 1, the fuel and line loss surcharge percentage shall be determined in accordance with Section 37.3(c) hereof. The fuel and line loss surcharge percentage shall become effective on July 1 and January 1 and shall remain in effect for the six (6) month period ending December 31 and June 30, respectively. (b) At least thirty (30) days prior to each July 1 and January 1, PGT shall file with the Commission and post, as defined by Section 154.16 of the Commission's regulations, the fuel and line loss surcharge percentage, together with supporting documentation. (c) The fuel and line loss percentage shall be computed by (i) determining PGT's actual fuel and line loss for the six (6) month period ending April 30, if the effective date is July 1, or October 31, if the effective date is January 1, (ii) subtracting the actual quantities retained by PGT during such six (6) month period, and (iii) dividing the result by the estimated quantities of gas to be delivered by PGT for the account of Shippers during the six month period beginning with the effective date of the fuel and line loss surcharge percentage. If the percentage so determined is 0.0001% or less, the fuel and line loss surcharge percentage shall be deemed to be zero. ________________________________________________________________________________ Issued by: P.G. Rosput, Senior Vice President Issued on: JANUARY 10, 1994 Effective: JANUARY 22, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 142 First Revised Volume No. 1-A Superseding Original Sheet No. 142 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 38. Reserved. (Continued) ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Pacific Gas Transmission Company FERC Gas Tariff Third Revised Sheet No. 143 First Revised Volume No. 1-A Superseding Second Revised Sheet No. 143 ________________________________________________________________________________ TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 39. SALES OF EXCESS GAS PGT may from time to time purchase or sell gas on an interruptible basis at its Stanfield or Kingsgate receipt points as necessary to manage system pressure and maintain system integrity. Prior to purchasing or selling gas pursuant to this section, PGT shall post notice of its intent to purchase or sell gas through its EBB. Purchase or sale of gas shall be made on a nondiscriminatory basis. ________________________________________________________________________________ Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996 Graphic List to Exhibit 10.1 of the Form 10-K The substantive information conveyed by the Capacity Release Timelines Standard Release (Greater Than or Equal to One Day) graph (appearing in Paragraph 28) is described in the body of the electronic document at Paragraph 28.2 and Paragraph 28.8 (b) as permitted by Item 304 of Regulation S-T. The substantive information conveyed by the Capacity Release Timelines Rapid Release (Equal to or Less Than One Month) graph (appearing in Paragraph 28) is described in the body of the electronic document at Paragraph 28.2 and Paragraph 28.8 (a) as permitted by Item 304 of Regulation S-T. The substantive information conveyed by the Capacity Release Timelines Pre- Arranged Deal - A (Less Than or Equal to Thirty-One Days) graph (appearing in Paragraph 28) is described in the body of the electronic document at Paragraph 28.2 and Paragraph 28.8 (c) as permitted by Item 204 of Regulation S-T. The substantive information conveyed by the Capacity Release Timelines Pre- Arranged Deal - B (Equal To or Greater Than Thirty-One Days At the Highest Value Bid) graph (appearing at Paragraph 28) is described in the body of the electronic document at Paragraph 28.2 and Paragraph 28.8 (d) as permitted by Item 304 of Regulation S-T. The substantive information conveyed by the Capacity Release Timelines Pre- Arranged Deal - C (Greater Than or Equal to One Day) graph (appearing at Paragraph 28) is described in the body of the electronic document at Paragraph 28.2 and Paragraph 28.8 (e) as permitted by Item 304 of Regulation S-T. EX-11 4 COMPUTATION OF EARNINGS PER COMMON SHARE EXHIBIT 11 PG&E CORPORATION COMPUTATION OF EARNINGS PER COMMON SHARE
- ---------------------------------------------------------------------------------------------------------- Year Ended December 31, ---------------------------------------- (in thousands, except per share amounts) 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Net income $755,209 $1,338,885 $1,007,450 Less: preferred dividend requirement and redemption premium 33,113 70,288 57,603 -------- ---------- ---------- Net income for calculating EPS for Statement of Consolidated Income $722,096 $1,268,597 $ 949,847 ======== ========== ========== Average common shares outstanding 412,542 423,692 429,846 ======== ========== ========== EPS as shown in the Statement of Consolidated Income $ 1.75 $ 2.99 $ 2.21 ======== ========== ========== PRIMARY EPS (1) Net income $755,209 $1,338,885 $1,007,450 Less: preferred dividend requirement and redemption premium 33,113 70,288 57,603 -------- ---------- ---------- Net income for calculating primary EPS $722,096 $1,268,597 $ 949,847 ======== ========== ========== Average common shares outstanding 412,542 423,692 429,846 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at average market price) 9 126 57 -------- ---------- ---------- Average common shares outstanding as adjusted 412,551 423,818 429,903 ======== ========== ========== Primary EPS $ 1.75 $ 2.99 $ 2.21 ======== ========== ========== FULLY DILUTED EPS (1) Net income $755,209 $1,338,885 $1,007,450 Less: preferred dividend requirement and redemption premium 33,113 70,288 57,603 -------- ---------- ---------- Net income for calculating fully diluted EPS $722,096 $1,268,597 $ 949,847 ======== ========== ========== Average common shares outstanding 412,542 423,692 429,846 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at the greater of average or ending market price) 9 149 57 -------- ---------- ---------- Average common shares outstanding as adjusted 412,551 423,841 429,903 ======== ========== ========== Fully diluted EPS $ 1.75 $ 2.99 $ 2.21 ======== ========== ========== - ----------------------------------------------------------------------------------------------------------
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K. This presentation is not required by APB Opinion No. 15, because it results in dilution of less than 3%. EX-12.1 5 COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES EXHIBIT 12.1 PG&E CORPORATION AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- ------------------------------------------------------------------------------------------ Year ended December 31, ------------------------------------------------------------- (dollars in thousands) 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------ Earnings: Net income $ 755,209 $1,338,885 $1,007,450 $1,065,495 $1,170,581 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 2,488 3,820 (2,764) 6,895 (3,349) Income tax expense 554,994 895,289 836,767 901,890 895,126 Net fixed charges 683,393 715,975 730,965 821,166 802,198 ---------- ---------- ---------- ---------- ---------- Total Earnings $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556 ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279 Interest on short- term borrowings 75,310 83,024 77,295 87,819 61,182 Interest on capital leases 3,508 2,735 1,758 1,737 1,737 Capitalized Interest 637 957 2,660 46,055 6,511 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned subsidiaries 24,319 3,306 - - - ---------- ---------- ---------- ---------- ---------- Total Fixed Charges $ 684,284 $ 717,397 $ 733,625 $ 867,221 $ 808,709 ========== ========== ========== ========== ========== Ratios of Earnings to Fixed Charges 2.92 4.12 3.51 3.22 3.54 - ------------------------------------------------------------------------------------------
Note: For the purpose of computing the 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, the Company's equity in undistributed income or loss of 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, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. EX-12.2 6 COMPUTATION OF RATIOS OF EARNINGS EXHIBIT 12.2 PG&E CORPORATION AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- ------------------------------------------------------------------------------------------- Year ended December 31, -------------------------------------------------------------- (dollars in thousands) 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------- Earnings: Net income $ 755,209 $1,338,885 $1,007,450 $1,065,495 $1,170,581 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 2,488 3,820 (2,764) 6,895 (3,349) Income tax expense 554,994 895,289 836,767 901,890 895,126 Net fixed charges 683,393 715,975 730,965 821,166 802,198 ---------- ---------- ---------- ---------- ---------- Total Earnings $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556 ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279 Interest on short- term debt 75,310 83,024 77,295 87,819 61,182 Interest on capital leases 3,508 2,735 1,758 1,737 1,737 Capitalized Interest 637 957 2,660 46,055 6,511 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned subsidiaries 24,319 3,306 - - - ---------- ---------- ---------- ---------- ---------- Total Fixed Charges $ 684,284 $ 717,397 $ 733,625 $ 867,221 $ 808,709 ---------- ---------- ---------- ---------- ---------- Preferred Stock Dividends: Tax deductible dividends 10,057 11,343 4,672 4,814 5,136 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 39,108 99,984 96,039 108,937 130,147 ---------- ---------- ---------- ---------- ---------- Total Preferred Stock Dividends 49,165 111,327 100,711 113,751 135,283 ---------- ---------- ---------- ---------- ---------- Total Combined Fixed Charges and Preferred Stock Dividends $ 733,449 $ 828,724 $ 834,336 $ 980,972 $ 943,992 ========== ========== ========== ========== ========== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 2.72 3.56 3.08 2.85 3.03 - -------------------------------------------------------------------------------------------
Note: For the purpose of computing the 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, the Company's equity in undistributed income or loss of 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, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax earnings which would be required to cover such dividend requirements. EX-13 7 ANNUAL REPORT Exhibit 13 PG&E Corporation Selected Financial Data
(in thousands, except per share amounts) 1996 1995 1994 1993 1992 ------------- ------------- ------------- ------------- ------------- For the Year Operating revenues $ 9,609,972 $ 9,621,765 $10,350,230 $10,550,002 $10,315,713 Operating income 1,895,585 2,762,985 2,423,786 2,560,235 2,699,824 Net income 755,209 1,338,885 1,007,450 1,065,495 1,170,581 Earnings per common share 1.75 2.99 2.21 2.33 2.58 Dividends declared per common share 1.77 1.96 1.96 1.88 1.76 At Year End Book value per common share $ 20.73 $ 20.77 $ 20.07 $ 19.77 $ 19.41 Common stock price per share 21.00 28.38 24.38 35.13 33.13 Total assets 26,129,925 26,850,290 27,708,564 27,145,899 24,188,159 Long-term debt and preferred stock and securities with mandatory redemption provisions (excluding current portions) 8,207,567 8,486,046 8,812,591 9,367,100 8,525,948
Matters relating to certain data above are discussed in Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition and in Notes to the Consolidated Financial Statements. 8 PG&E Corporation Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a subsidiary of its new parent holding company, PG&E Corporation. PG&E's ownership interest in Pacific Gas Transmission Company (PGT) and PG&E Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. PG&E's debt securities and preferred stock were unaffected and remain securities of PG&E. This holding company structure is intended to improve PG&E Corporation's ability to respond to new business opportunities and changes in the utility industry. It will enhance the financial separation of the California utility business from PG&E Corporation's other businesses and will provide greater financing flexibility. The consolidated financial statements in this annual report include the accounts of PG&E and its wholly-owned and controlled subsidiaries (collectively, the Company) and, therefore, also represent the accounts of PG&E Corporation and its subsidiaries. PG&E provides generation, procurement, transmission, and distribution of electricity and natural gas to customers throughout most of Northern and Central California. PG&E is regulated by the California Public Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission, among others. PGT and Enterprises, previously wholly-owned by PG&E, are now wholly-owned subsidiaries of PG&E Corporation. Through these subsidiaries, the Company is expanding its presence in the "midstream" portion of the gas business, the independent power generation business, and the energy services business. The midstream portion of the gas business includes gas gathering, processing, storage, and transportation. The energy services business includes obtaining gas and electricity from competitive producers, arranging for distribution and transmission service, and providing customized energy billing and analysis, power quality assessments, energy efficiency products and services, and facility improvements. PGT transports gas from the Canadian border to the California border and the Pacific Northwest and is regulated by the FERC. In 1996, PGT acquired PGT Queensland Gas Pipeline in Australia and Energy Source, the North American gas operations of Edisto Resources Corporation. In January 1997, PG&E Corporation acquired Teco Pipeline Company (Teco) in Texas. Teco owns a natural gas pipeline system in Texas, investments in gas gathering and processing facilities, and a gas marketing company in Houston. Also in January 1997, PG&E Corporation agreed to acquire Valero Natural Gas Company (Valero) (see Acquisitions and Sales below). Enterprises, through its subsidiaries and affiliates, develops, owns, and operates unregulated electric and gas projects in the U.S. and around the world. Vantus Energy Corporation (Vantus), a subsidiary of Enterprises, markets gas and electricity commodities and provides energy services. The following discussion of consolidated results of operations and financial condition includes forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," and similar expressions identify forward-looking statements involving risks and uncertainties. These risks and uncertainties include but are not limited to the ongoing restructuring of the electric and gas industries and the outcome of regulatory proceedings related to that restructuring. The ultimate impacts of both increased competition and the changing regulatory environment on future results are uncertain, but both are expected to fundamentally change how the Company conducts its business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by the Company. Competition and Changing Regulatory Environment: The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies are challenging the utilities' exclusive relationship with customers and are seeking to replace certain utility functions with their own. Customers, too, are asking for choice in their energy provider. 9 PG&E Corporation Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition These pressures are causing a move from the existing regulatory framework to a framework under which competition would be allowed in certain segments of the gas and electric industries. For several years, PG&E has been working with its regulators to achieve an orderly transition to competition and to ensure that PG&E has an opportunity to recover investments made under the traditional regulatory policies. In addition, PG&E has proposed alternative forms of regulation for those services for which prices and terms will not be determined by competition. These alternative forms include performance-based ratemaking (PBR) and other incentive-based alternatives. Over the next five years, a significant portion of PG&E's business will be transformed from the current utility monopoly to a competitive operation. This change will impact PG&E's financial results and may result in greater earnings volatility. During the transition period, PG&E expects the return on Diablo Canyon Nuclear Power Plant (Diablo Canyon) and certain other generation assets to be significantly lower than historical levels. Electric Industry Restructuring: In 1995, the CPUC issued a decision that provides a plan to restructure California's electric utility industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called "transition costs." In 1996, California legislation was passed that adopts the basic tenets of the CPUC's restructuring decision, including recovery of transition costs. In addition, the legislation provides a 10 percent rate reduction for residential and small commercial customers by January 1, 1998, freezes electric customer rates for all other customers, and requires the accelerated recovery of transition costs associated with owned generation facilities. The legislation also establishes the operating framework for a competitive generation market. The rate freeze will continue until the earlier of March 31, 2002, or until PG&E has recovered its transition costs (the transition period). The freeze will hold rates at 1996 levels for all customers except those receiving the 10 percent rate reduction. The rate freeze will hold the rates for these customers at the reduced level. To achieve the 10 percent rate reduction, the legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current cost of capital. Once this portion of transition costs is financed, PG&E would collect a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs will lower the amounts paid by these customers each year during the transition period thereby achieving the 10 percent reduction in rates. During 1997, differences between authorized and actual base revenues and differences between the actual cost of electric generation and the revenue designated for recovery of such revenues or costs will be recorded in balancing accounts. Any residual balance will be available for transition cost recovery. During 1997, amounts recorded in balancing accounts will be subject to a reasonableness review by the CPUC. Absent the rate freeze, PG&E's rates would be expected to decline under existing cost-based ratemaking methodologies. The most significant reasons for the decrease in cost-based rates are the declining cost of power committed under certain purchased power contracts, the reduction in the Diablo Canyon price for power under the existing CPUC-approved settlement, and the decline in uncollected electric balancing accounts. Transition Cost Recovery: The legislation authorizes the CPUC to determine the costs eligible for recovery as transition costs. The amount of costs will be based on the aggregate of above-market and below-market values of utility-owned generation assets and obligations. PG&E has proposed that costs eligible for transition cost recovery include: (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and currently collected through rates) and future costs, such as costs related to plant removal, (2) above-market costs associated with purchase power obligations with Qualifying Facilities (QFs) and other Power Purchase Agreements, and (3) generation-related regulatory assets and obligations. PG&E cannot determine the exact amount of sunk 10 costs that will be above market and recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each generation facility. This process will be completed during the transition period. In compliance with the CPUC's restructuring decision and the restructuring legislation, PG&E has filed numerous regulatory applications and proposals that detail its transition cost recovery plan. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of-service revenue requirement for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) accelerated recovery of transition costs, and (3) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period. The unbundling of PG&E's revenue requirement enables it to separate revenue provided by frozen rates into transmission, distribution, PPPs, and generation. As proposed, revenues collected under frozen rates would be assigned to transmission, distribution, and PPPs based upon their respective cost of service. Revenue would also be provided for other costs, including nuclear decommissioning, rate-reduction-bond debt service, the on-going cost of generation, and transition cost recovery. The combination of a rate freeze and decreasing costs, based upon existing ratemaking and cost recovery periods, provides an adequate amount of revenue available for full transition cost recovery. PG&E has proposed to accelerate recovery for certain transition costs related to generation facilities, including Diablo Canyon. Additionally, PG&E would receive a reduced return on common equity associated with generation plant assets for which recovery is accelerated. The lower return reflects the reduced risk associated with the shorter amortization period and increased certainty of recovery. In applying its cost recovery plan to Diablo Canyon, PG&E has proposed to replace the existing settlement prices with: (1) a sunk cost revenue requirement to recover fixed costs, including a return on these costs, and (2) a PBR mechanism to recover the facility's variable costs and capital addition costs. As proposed, the sunk cost revenue requirement would accelerate recovery of Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five-year period beginning in 1997 and ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90 percent of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. The reduced rate of return combined with a shorter recovery period would result in an estimated $4 billion decrease in the net present value of PG&E's future revenues from Diablo Canyon operations. If the proposed cost recovery plan for Diablo Canyon were adopted during 1996, Diablo Canyon's 1996 reported net income would have been reduced by $350 million ($0.85 per share). Most transition costs must be recovered by March 1, 2002. However, the legislation authorizes recovery of certain transition costs after that time. These costs include: (1) certain employee-related transition costs, (2) payments under existing QF and power purchase contracts, and (3) unrecovered implementation costs. Excluding these exceptions, any transition costs not recovered during the transition period will be absorbed by PG&E. Nuclear decommissioning costs, which are not considered transition costs, will be recovered through a CPUC authorized charge. During the transition period, this charge will be incorporated into the frozen rates. After the transition period, customers will be assessed a surcharge until the nuclear decommissioning costs are fully recovered. PG&E's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the extent to which application of the current regulatory framework established by the restructuring legislation will continue to be applied, (2) the amount of transition costs approved by the CPUC, (3) the market value of PG&E's generation plants, (4) future sales levels, (5) fuel and operating costs, (6) the market price of electricity, and (7) the ratemaking methodology adopted for Diablo Canyon. Considering its current evaluation of these factors, PG&E believes it will recover its transition costs and that its owned generation plants are not impaired. However, a change in these factors could affect the probability of recovery of transition costs and result in a material loss. PG&E has proposed to implement portions of its transition cost recovery plan in 1997. The CPUC decision on PG&E's 1997 Energy Cost Adjustment Clause (ECAC) application would decrease PG&E's 1997 revenue requirement by $720 million. This decrease would be partially offset by a $160 million revenue requirement increase, provided by the legislation, for purposes of enhancing transmission and distribution system 11 PG&E Corporation Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition safety and reliability. This increase was approved by the CPUC as part of PG&E's transition cost recovery plan. Given the electric customer rate freeze, the $560 million net revenue requirement decrease resulting from the consolidation of the ECAC decision and the revenue requirement increase contemplated in the cost recovery plan would be available for transition cost recovery. The proposed accelerated recovery of Diablo Canyon would absorb an estimated $400 million of this available revenue requirement. The remaining revenue requirement would be available to recover other transition costs. Competitive Market Framework: In addition to transition cost recovery, the legislation establishes the operating framework for the competitive generation market in California. This framework will consist of a power exchange (PX) and an independent system operator (ISO). The PX, open to all electricity providers, will conduct a competitive auction to establish the price of electricity. The ISO will ensure system reliability and provide all electricity generators with open and comparable access to transmission and distribution services. Although the PX will be available to all customers, the legislation allows customers to bypass the PX by entering into direct access contracts with other electricity providers, subject to a nonbypassable transition charge. This direct access will be available to certain customers by January 1, 1998, and will be phased in for all remaining customers through December 31, 2001. During the transition period, PG&E will bill direct access customers based upon fully bundled frozen rates. Direct access customers' bills from PG&E would then be reduced by an amount based on the PX price and the customers' electric usage. These customers can be billed for their usage directly by their chosen supplier, or the supplier may contract with PG&E to perform this billing. During the transition period, these customers' overall electric rates will vary only to the extent that their direct access contract price differs from the PX price. To prevent undue influence on the PX price by any participant in the competitive framework, PG&E has indicated it is willing to proceed with divestiture of at least 50 percent of its fossil-fueled power plants as directed by the CPUC. PG&E has filed an application seeking approval from the CPUC to sell four plants before the end of 1997. The book value for these plants is approximately $400 million, and together they generate approximately 10 percent of PG&E's total electric sales. PG&E proposes to recover any shortfall in proceeds from divestiture of these plants as a transition cost. Accordingly, the Company does not expect any adverse impact on its results of operations from the sale of these plants. In addition to the CPUC's electric industry restructuring discussed above, the FERC has required utilities to provide wholesale open access to electric transmission systems on terms that are comparable to the way utilities use their own systems. PG&E's open access tariff, filed in July 1996, provides access to any eligible party interested in wholesale transmission service over PG&E's transmission system. The FERC also reaffirmed its intention to permit utilities to recover any legitimate, verifiable, and prudently incurred costs stranded as a result of customers taking advantage of wholesale open access orders to meet their power needs from other sources. Further, the FERC asserted that it has jurisdiction over the transmission component of retail direct access. By developing the PX and the ISO and by implementing direct access to generation and open access to transmission, regulators have established the operating framework of the competitive generation and wholesale transmission markets. Although this framework will fundamentally change the way PG&E does business, the Company does not believe that the changes will have a material adverse impact on its ability to recover transition costs. Accounting for the Effects of Regulation: PG&E accounts for the financial effects of regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows the Company to record certain regulatory assets and liabilities that would not be recorded under generally accepted accounting principles for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," requires that regulatory assets be written off when they are no longer probable of recovery and that impairment losses be recorded for long-lived assets when related future cash flows are less than the carrying value of the asset. As a result of applying the provisions of SFAS No. 71, PG&E has accumulated approximately $1.6 billion of regulatory assets attributable to electric generation at December 31, 1996. 12 The net investments in Diablo Canyon and the other generation assets were $4.5 billion and $2.7 billion, respectively, at December 31, 1996. The net present value of above-market QF power purchase obligations is estimated to be $5.3 billion at January 1, 1998, at an assumed PX price of $0.025 per kilowatt-hour (kWh) beginning in 1997 and escalating at 3.2 percent per year. PG&E believes that the restructuring legislation establishes a definitive transition to market-based pricing for electric generation. Incorporating the effects of the PX and direct access, this transition includes cost-of-service based ratemaking. In addition, PG&E's generation-related transition costs will be collected through a nonbypassable charge. Based on this structure, PG&E believes it will continue to meet the requirements of SFAS No. 71 throughout the transition period. At the conclusion of the transition period, PG&E believes it will be at risk to recover its generation costs through market-based revenues. At that time, PG&E expects to discontinue the application of SFAS No. 71 for the electric generation portion of its business. Since PG&E anticipates it will have recovered all transition costs required to be recovered during the transition period, including generation-related regulatory assets and above-market investments in net plant, PG&E does not expect a material adverse impact on its financial position or results of operations from discontinuing the application at that time. As a result of the CPUC's restructuring decision and California's electric industry restructuring legislation, the Securities and Exchange Commission (SEC) has begun inquiries regarding the appropriateness of the continued application of SFAS No. 71 by California utilities to their electric generation businesses. As discussed above, PG&E believes it currently meets and will continue to meet the requirements to apply SFAS No. 71 during the transition period. In the event that the SEC concludes that the current regulatory and legal framework in California no longer meets the requirements to apply SFAS No. 71 to the generation business, the Company would reevaluate the financial impact of electric industry restructuring and a material write-off could occur. Given the current regulatory environment, PG&E's electric transmission and distribution businesses are expected to remain regulated and, as a result, will continue application of the provisions of SFAS No. 71. Gas Industry Restructuring: Restructuring of the natural gas industry on both the national and the state level has given customers greater options in meeting their gas supply needs. PG&E's customers may buy commodity gas directly from competing suppliers and purchase transmission- and distribution-only services from PG&E. Transmission and distribution services have remained "bundled," or sold together at a combined rate, within the state. PGT, as an interstate pipeline, has provided nondiscriminatory transmission-only service since 1993 and no longer sells commodity gas. Most of PG&E's industrial and larger commercial (noncore) customers purchase their commodity gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers continue to buy commodity gas as well as transmission and distribution from PG&E as a bundled service. In 1995 and 1996, PG&E actively pursued changes in the California gas industry in an effort to promote competition and increase options for all customers, as well as to position itself for the competitive marketplace. In 1996, PG&E submitted to the CPUC the Gas Accord Settlement (Accord). The Accord is the result of an extensive negotiation process, begun in 1995, among a broad coalition of customer groups and industry participants. The Accord must be approved by the CPUC before it can be implemented. A CPUC decision is expected in 1997. The Accord consists of three broad initiatives: (1) The Accord would separate, or "unbundle," PG&E's gas transmission and storage services from its distribution services and would change the terms of service and rate structure for gas transportation. Unbundling would give customers the opportunity to select from a menu of services offered by PG&E and would enable them to pay only for the services they use. PG&E would be at risk for variations in revenues resulting from differences between actual and forecasted transmission throughput. PG&E would also continue to provide cost-of- service based distribution service, much as it does today. (2) The Accord would increase opportunities for PG&E's core customers to purchase gas from competing suppliers and, therefore, could reduce PG&E's role in procuring gas for such customers. However, PG&E would continue to procure gas as a regulated utility supplier for those customers who request it. The Accord also would establish principles for continuing negotiations between PG&E and California gas producers for 13 PG&E Corporation Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition the mutual release of supply contracts and the sale of gas gathering facilities. Also related to PG&E's procurement activities, PG&E has proposed that traditional reasonableness reviews of its core gas costs be replaced with a core procurement incentive mechanism (CPIM) for the period June 1, 1994, through 2002. Under the CPIM, PG&E would be able to recover its gas commodity and interstate transportation costs and would receive benefits or be penalized depending on whether its actual core procurement costs were within, below, or above a "tolerance band" constructed around market benchmarks. Actual core procurement costs measured for the period June 1, 1994, through December 31, 1996, have generally been within the CPIM "tolerance band." The CPIM proposal also requests authorization to use derivative financial instruments to reduce the risk of gas price and foreign currency fluctuations. Gains, losses, and transaction costs associated with the use of derivative financial instruments would be included in the purchased gas account and the measurement against the benchmarks. (3) The Accord would resolve various regulatory issues (see further discussion in Note 3 to the Consolidated Financial Statements) including: . the disallowances ordered by the CPUC in connection with PG&E's 1988 through 1995 gas reasonableness proceedings; . the recovery of certain capital costs associated with the PG&E portion of the PGT/PG&E Pipeline Expansion; . the recovery of costs related to PG&E's capacity commitments with Transwestern Pipeline Company through 2002; and . the recovery, through PG&E's interstate transition cost surcharge, of fixed demand charges paid to El Paso Natural Gas Company and PGT for firm capacity held by PG&E on behalf of its customers. As of December 31, 1996, PG&E has reserved approximately $527 million, including $182 million reserved during 1996, relating to its gas regulatory issues and gas capacity commitments, the majority of which are addressed by the Accord. PG&E believes the ultimate resolution of these matters, whether through approval of the Accord or otherwise, will not have a material adverse impact on its financial position or future results of operations. Acquisitions and Sales: The Company has developed strategies to focus on the unregulated independent power generation market, the unregulated energy services market, and the regulated and unregulated "midstream" portions of the gas market. As a result of this focus, the Company has been acquiring related businesses and disposing of unrelated businesses. Enterprises participates in multiple domestic and international energy businesses. The majority of Enterprises' domestic investments are in nonregulated energy projects through U.S. Generating Company (USGen), a joint venture with Bechtel Enterprises, Inc. (Bechtel). USGen and its affiliates develop, own, and operate power plants in the United States. Enterprises' entry into the international market was also made in partnership with Bechtel. Enterprises and Bechtel formed International Generating Company, Ltd., (InterGen) which develops, owns, and operates international electric generation projects. However, in November 1996, Enterprises and Bechtel reached an agreement for Bechtel to acquire Enterprises' interest in InterGen. The Company expects to complete the sale in the first quarter of 1997 and realize an after-tax gain. Enterprises has refined its international strategy to focus on select countries and to concentrate on end-use energy customers. In 1995, Enterprises formed Vantus, a retail energy services provider, to assist customers in locating the most cost-effective electric and gas products and services. Vantus' energy services include power marketing for industrial and large commercial businesses nationwide. In 1996, Vantus opened new offices in the western United States to establish a presence and market its services in emerging energy markets. Also in 1995, Enterprises sold DALEN Corporation (DALEN). The sales price was $455 million, including $340 million cash and the assumption of $115 million of existing debt. The sale resulted in an after-tax gain of approximately $13 million. 14 The Company is pursuing gas-related opportunities as the gas industry continues to evolve. In July 1996, the Company, through its subsidiary PGT, purchased PGT Queensland State Gas Pipeline, a 389-mile natural gas transportation system in the Australian state of Queensland. The final purchase price was $136 million. In December 1996, PGT entered the unregulated gas marketing arena with the purchase of Energy Source (ESI), the North American gas marketing operations of Edisto Resources Corporation for approximately $23 million. The purchase included most of ESI's existing contracts for the purchase, sale, and transportation of natural gas and natural gas futures. In 1996, ESI generated over $1.1 billion in gas marketing revenues, of which $283 million was earned in December 1996. In January 1997, PG&E Corporation acquired Teco and its subsidiaries for approximately $380 million. Teco is an owner of a 500-mile natural gas pipeline system in Texas. Teco also has investments in gas gathering and processing facilities and owns a gas marketing company in Houston. Also in January 1997, PG&E Corporation agreed to acquire Valero. Valero's operations include the gathering, transportation, marketing, and storage of natural gas, the processing, transportation, and marketing of natural gas liquids, and the marketing of electric power. Valero operates approximately 7,500 miles of natural gas pipeline and also owns and operates 536 miles of natural gas liquid pipeline and eight natural gas processing plants in Texas. PG&E Corporation will acquire Valero for approximately $1.5 billion, comprised of approximately $720 million in PG&E Corporation common stock and the assumption of debt and liabilities. The acquisition is expected to be completed by mid-1997 and is subject to applicable regulatory and shareholder approvals. All of the above acquisitions have been or will be accounted for using the purchase method of accounting. Results of Operations: The Company's results of operations were derived from three business lines: utility (excluding Diablo Canyon and including PGT's gas pipeline operations), Diablo Canyon, and diversified operations (principally, Enterprises and ESI). The results of operations and total assets for 1996, 1995, and 1994 are reflected in the following table and discussed below:
Diablo Diversified Utility Canyon/(1)/ Operations Total ---------- ------------ ----------- ---------- (in millions, except per share amounts) 1996 Operating revenues $ 7,411 $1,789 $ 410 $ 9,610 Operating expenses 6,465 791 458 7,714 ------- ------ ------ ------- Operating income (loss) before income taxes $ 946 $ 998 $ (48) $ 1,896 ======= ====== ====== ======= Net income (loss) $ 292 $ 497 $(34)/(2)/ $ 755 ======= ====== ====== ======= Earnings per common share $ .65 $ 1.18 $(.08) $ 1.75 ======= ====== ====== ======= Total assets at year end $19,283 $5,413 $1,434 $26,130 ======= ====== ====== ======= 1995 Operating revenues $ 7,601 $1,845 $ 176 $ 9,622 Operating expenses 5,820 816 223 6,859 ------- ------ ------ ------- Operating income (loss) before income taxes $ 1,781 $1,029 $ (47) $ 2,763 ======= ====== ====== ======= Net income $ 820 $ 507 $ 12/(2)/ $ 1,339 ======= ====== ====== ======= Earnings per common share $ 1.80 $ 1.16 $ .03 $ 2.99 ======= ====== ====== ======= Total assets at year end $20,090 $5,717 $1,043 $26,850 ======= ====== ====== ======= 1994 Operating revenues $ 8,232 $1,870 $ 248 $10,350 Operating expenses 6,732 914 280 7,926 ------- ------ ------ ------- Operating income (loss) before income taxes $ 1,500 $ 956 $ (32) $ 2,424 ======= ====== ====== ======= Net income $ 539 $ 461 $ 7/(2)/ $ 1,007 ======= ====== ====== ======= Earnings per common share $ 1.15 $ 1.04 $ .02 $ 2.21 ======= ====== ====== ======= Total assets at year end $20,295 $5,978 $1,436 $27,709 ======= ====== ====== =======
/(1)/ See Note 4 to the Consolidated Financial Statements for discussion of allocations. /(2)/ Includes non-operating income resulting from property sales, partnership earnings, and investment income. Earnings Per Common Share: Earnings per common share were $1.75, $2.99, and $2.21 for 1996, 1995, and 1994, respectively. Utility earnings in 1996 were lower than 1995, reflecting revenue reductions ordered in the 1996 General Rate Case (GRC) and other related rate proceedings and reflecting several one-time charges. The revenue reductions resulted from a lower cost of capital, lower capital expenditures, and reductions in authorized expense levels. Actual maintenance and other operating expenses for distribution 15 PG&E Corporation Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition and customer-related services increased in 1996 and exceeded levels authorized in the 1996 GRC. These increases were primarily attributable to several projects related to transmission and distribution system reliability, and improved customer-related services. Additionally, PG&E recorded a charge of $.26 per common share for contingencies related to gas transportation commitments and recorded a charge of $.19 per common share for settlement of litigation. (See Operating Expenses below and Notes 3 and 13 to the Consolidated Financial Statements.) Finally, the Company recorded a charge of $.09 per common share for write-downs of nonregulated investments. Earnings per common share for 1995 were higher than 1994 due to fewer one-time charges against earnings than in 1994 (see Operating Expenses below). In addition, there were fewer scheduled refueling outages at Diablo Canyon in 1995, compared with 1994. On a consolidated basis, the Company earned 8.5, 14.6, and 11.1 percent returns on average common stock equity for the years ended December 31, 1996, 1995, and 1994, respectively. PG&E has received a CPUC decision which authorizes, for 1997, a return on common equity of 11.6 percent and an overall rate of return of 9.45 percent. However, PG&E has filed a proposal with the CPUC to accelerate recovery of certain transition costs related to generation facilities, including Diablo Canyon. Additionally, PG&E would receive a reduced return on common equity associated with generation plant assets for which recovery is accelerated. This return would equal 90 percent of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. (See Electric Industry Restructuring above.) Common Stock Dividend: The Company's common stock dividend is based on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. The Company's current quarterly common stock dividend is $.30 per common share which corresponds to an annualized dividend of $1.20 per common share. This represents a decrease from the previous annualized dividend of $1.96 per common share. The Company has identified a dividend payout ratio objective (dividends declared divided by earnings available for common stock) of between 50 and 65 percent (based on earnings exclusive of nonrecurring adjustments). Operating Revenues: Operating revenues in 1996 decreased slightly from 1995. The decreases in utility revenues as ordered in the 1996 GRC, discussed above, and in Diablo Canyon revenues were offset by increased revenues from diversified operations. Revenues from Diablo Canyon decreased due to a decline in the generation price, as provided in the Diablo Canyon rate case settlement as modified in 1995 (Diablo Settlement) (see Note 4 to the Consolidated Financial Statements). This decline was partially offset by higher net generation, which was a result of fewer scheduled refuelings in 1996 compared to 1995. Revenues from diversified operations increased primarily due to the purchase of ESI in December 1996. This purchase created $283 million of revenue but was partially offset by a decline in revenue due to the sale of DALEN in 1995. (See Acquisitions and Sales above.) Operating revenues for 1995 decreased $728 million from 1994. The decrease in utility revenues was primarily due to a decrease in electric energy costs caused by favorable hydroelectric conditions and lower natural gas prices. Diablo Canyon operating revenues decreased due to a decrease in the generation price as provided in the modified Diablo Settlement (see Note 4 to the Consolidated Financial Statements for further discussion). This decrease was partially offset by favorable operating revenues from Diablo Canyon resulting from fewer refueling days in 1995. Revenues from diversified operations decreased $72 million in 1995 compared to 1994 primarily due to the sale of DALEN in June 1995. Operating Expenses: Operating expenses increased $855 million in 1996 compared to 1995, primarily due to: (1) a charge of $182 million for contingencies related to gas transportation commitments, (2) increases in the cost of gas due to price increases, (3) increases in purchased power prices and volumes, (4) increases in maintenance and other operating expenses for transmission and distribution system reliability and for improved customer-related services, (5) increases in litigation costs, and (6) an increase in the cost of gas for resale due to the purchase of ESI in December 1996. The cost of gas increase from the purchase of ESI was offset by revenues as discussed above. Operating expenses decreased $1,067 million in 1995 compared to 1994 primarily due to decreased electric costs caused by favorable hydroelectric conditions, decreased natural gas 16 prices, and no workforce reduction charges in 1995. (See Note 10 to the Consolidated Financial Statements.) Other Income and (Expense): Other income and expense changed in 1996 compared to 1995 primarily due to write-downs of certain nonregulated investments. Liquidity and Capital Resources: The Company's capital requirements are funded from cash provided from operations and, to the extent necessary, external financing. The Company's policy is to finance its assets with a capital structure that minimizes financing costs, maintains financial flexibility, and complies with regulatory guidelines. Based on cash provided from operations and its capital requirements, the Company may repurchase equity and long-term debt in order to manage the overall balance of its capital structure. Debt: In 1996, 1995, and 1994, the Company redeemed or repurchased $1,113, $758, and $202 million, respectively, of long-term debt to manage the overall balance of the Company's capital structure. Long-term debt maturing during 1996, 1995, and 1994 was not refinanced. Included in the 1996 repurchases is $988 million of variable and fixed interest rate pollution control mortgage bonds and loan agreements which were replaced with variable interest rate pollution control loan agreements. Also in 1996, the Company entered into additional loan agreements of $92 million to finance the PGT acquisition of PGT Queensland State Gas Pipeline. In addition, the Company used its cash balances to reduce short-term borrowings by $115 million in 1996. In 1995, PGT issued $400 million of bonds and $70 million of medium-term notes. In addition, PGT issued commercial paper which is classified as long-term debt. This classification is based upon the availability of committed credit facilities expiring in 2000 and management's intent to maintain such amounts in excess of one year. The commercial paper outstanding was $108 and $109 million at December 31, 1996, and 1995, respectively. Substantially all of the proceeds of PGT's debt issued in 1995 were used to refinance outstanding debt. PG&E issues short-term debt (principally commercial paper) to fund fuel oil, nuclear fuel, and gas inventories, unrecovered balances in balancing accounts, and cyclical fluctuations in daily cash flows. At December 31, 1996, and 1995, PG&E had $681 and $796 million, respectively, of commercial paper outstanding. PG&E maintains a $1 billion revolving credit facility which primarily provides support for PG&E's commercial paper issuance. At maturity, commercial paper can be either reissued or replaced with borrowings from this credit facility. The facility can also be used for general corporate purposes. There were no borrowings under this facility in 1996, 1995, or 1994. In January 1997, PG&E Corporation established a $500 million revolving credit facility in order to provide for corporate short-term liquidity needs and other purposes. As discussed in electric industry restructuring above, to achieve the 10 percent rate reduction for residential and small commercial customers, the electric industry restructuring legislation authorizes utilities to finance a portion of the transition costs with "rate reduction bonds." PG&E expects to work with state authorities to coordinate the issuance of up to $2.5 billion of these bonds by a special purpose entity. Once issued, PG&E would collect, on behalf of the special purpose entity, a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. PG&E does not expect to secure the bonds with the Company's assets or unrelated future revenues. Equity: In 1996, 1995, and 1994, PG&E received $220, $140, and $274 million, respectively, in proceeds from the sale of common stock under the employee Savings Fund Plan, the Dividend Reinvestment Plan, and the employee Long-term Incentive Program. Since 1993, the Board has authorized the Company to repurchase up to $2 billion of its common stock on the open market or in negotiated transactions. These repurchases are funded by internally generated funds and are used to manage the overall balance of common stock in the Company's capital structure. Through December 31, 1996, the Company had repurchased approximately $1.5 billion of its common stock under this program. Repurchases for 1996, 1995, and 1994 were $455, $601, and $182 million, respectively. In 1996, PG&E did not redeem or repurchase any preferred stock. In 1995 and 1994, PG&E redeemed or repurchased $331 and $75 million, respectively, of its higher-cost preferred stock. In 1994, PG&E issued $62 million of preferred stock. PG&E is limited as to the amount of dividends that it may pay to PG&E Corporation based on PG&E's regulatory capital 17 PG&E Corporation Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition structure authorized by the CPUC. PG&E's equity shall be retained such that, on average, the capital structure authorized by the CPUC is maintained. This restriction is not expected to affect PG&E Corporation's ability to meet its cash obligations. Other Capital: In 1995, PG&E through its wholly-owned subsidiary, PG&E Capital I, issued $300 million of cumulative quarterly income preferred securities. Net proceeds were used to redeem and repurchase higher-cost preferred stock. Investing Activities: The Company's estimated capital requirements for the next three years are shown below:
Year ended December 31, 1997 1998 1999 --------- --------- --------- (in millions) Utility (including PGT) $1,773 $1,825 $1,705 Diablo Canyon 38 39 41 Diversified operations 211 80 172 --------- --------- --------- Total capital expenditures 2,022 1,944 1,918 Maturing debt and sinking funds 210 660 270 --------- --------- --------- Total capital requirements $2,232 $2,604 $2,188 ========= ========= =========
Utility and Diablo Canyon expenditures will be primarily for improvements to the Company's facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. Expenditures for diversified operations (consisting primarily of Enterprises) include capital contributions for Enterprises' equity share of generating facility projects. Ongoing capital expenditures for Teco are included in diversified operations in the above estimated capital requirements. In addition to the above, the Company, in January 1997, has acquired Teco for approximately $380 million, consisting of a note payable of $61 million and $319 million of PG&E Corporation's common stock. Further, the Company, in January 1997, agreed to acquire Valero for approximately $1.5 billion, consisting of approximately $720 million of PG&E Corporation's common stock and the assumption of debt and liabilities. The Company has other commitments as discussed in Notes 3 and 12 to the Consolidated Financial Statements. In December 1995, the Company had a balance of $734 million of cash and cash equivalents due to the sale of DALEN and the retention of cash for potential investments. Risk Management: Due to the changing business environment, the Company's exposure to risks associated with changes in energy commodity prices, interest rates, and foreign currencies is increasing. To manage these risks, the Company has adopted a price risk management policy and established an officer-level price risk management committee. The Company's price risk management committee oversees implementation of the policy, approves each price risk management program, and monitors compliance with the policy. The Company's price risk management policy and procedures adopted by the committee establish guidelines for implementation of price risk management programs. Such programs may include the use of energy and financial derivatives. (A derivative is a contract whose value is dependent on or derived from the value of some underlying asset.) Additionally, the Company's policy allows derivatives to be used for hedging and non-hedging purposes. (Hedging is the process of protecting one transaction by means of another to reduce price risk.) Both hedging and non-hedging activities are limited to those specifically approved by the committee only after appropriate controls and procedures are put in place to measure, monitor, and control the risk of such activities. The Company's policy prohibits the use of derivatives whose payment formula includes a multiple of some underlying asset. In 1996, the Company approved and implemented interest rate and foreign exchange risk management programs, applied for regulatory approval to use energy derivatives to manage commodity price risk in its utility business, and acquired certain natural gas marketing operations which engage in both hedging and non-hedging derivative transactions. Gains and losses associated with price risk management activities during 1996 were immaterial. Environmental Matters: The Company's projected expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. Capital expenditures for environmental protection are currently estimated to be approximately $36, $50, and $72 million for 1997, 1998, and 1999, respectively. Expenditures during these years will be primarily for nitrogen oxide (NOx) emission reduction projects at the Company's fossil fuel generating plants and natural gas compressor stations. Pursuant to federal and state legislation, 18 local air districts have adopted rules that require reductions in NOx emissions. These rules are subject to continued review and modification by the local air districts in which PG&E operates. The Company currently estimates that compliance with NOx rules could require capital expenditures of up to $360 million over the next ten years. On an ongoing basis, the Company assesses compliance with laws and regulations related to hazardous substance remediation. The Company has an accrued liability at December 31, 1996, of $170 million for remediation costs at sites where such costs are probable and quantifiable. The costs at identified sites may be as much as $400 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs, or identifiable possible outcomes change. The Company will seek recovery of prudently incurred compliance costs through ratemaking procedures approved by the CPUC. The Company has recorded a regulatory asset at December 31, 1996, of $146 million for recovery of these costs in future rates. Additionally, the Company will seek recovery of costs from insurance carriers and from other third parties. (See Note 13 to the Consolidated Financial Statements.) Effective January 1, 1997, the Company will adopt the provisions of the American Institute of Certified Public Accountants' Statement of Position (SOP) 96-1, Environmental Remediation Liabilities. This SOP provides authoritative guidance for recognition, measurement, display, and disclosure of environmental remediation liabilities in financial statements. The adoption of SOP 96-1 is not expected to have a material adverse impact on the Company's financial position or results of operations. Legal Matters: In the normal course of business, the Company is named as a party in a number of claims and lawsuits. Substantially all of these have been litigated or settled with no material adverse impact on either the Company's results of operations or financial position. In addition, the Company believes that the litigation or settlement of pending claims and lawsuits will not have a material adverse impact on its results of operations or financial position. See Note 13 to the Consolidated Financial Statements for further discussion of significant pending legal matters. Accounting for Decommissioning Expense: In 1996, the Financial Accounting Standards Board issued an exposure draft on a proposed SFAS entitled "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." If this exposure draft is adopted: (1) annual expense for power plant decommissioning could increase, and (2) the estimated total cost for power plant decommissioning could be recorded as a liability, with recognition of an increase in the cost of the related power plant, rather than accrued over time as accumulated depreciation. The Company does not believe that this change, if implemented as proposed, would have a material adverse impact on its results of operations due to its current and future ability to recover decommissioning costs through rates. (See Note 2 to the Consolidated Financial Statements for discussion of electric industry restructuring.) Inflation: The Company's rates are designed to recover operating and historical plant investment costs. Financial statements, which are prepared in accordance with generally accepted accounting principles, report operating results in terms of historic costs and do not evaluate the impact of inflation. Inflation affects the Company's construction costs, operating expenses, and interest charges. Due to the Company's five-year electric rate freeze, electric revenues will not reflect the impact of inflation. However, inflation at the levels currently being experienced is not expected to have a material adverse impact on the Company's future results of operations. 19 PG&E Corporation Statement of Consolidated Income
Year ended December 31, 1996 1995 1994 --------------- --------------- --------------- (in thousands, except per share amounts) Operating Revenues Electric utility $7,160,215 $7,386,307 $ 8,021,547 Gas utility 2,039,802 2,059,117 2,081,062 Diversified operations 409,955 176,341 247,621 --------------- --------------- --------------- Total operating revenues 9,609,972 9,621,765 10,350,230 --------------- --------------- --------------- Operating Expenses Cost of electric energy 2,303,488 2,116,840 2,570,723 Cost of gas 761,837 333,280 583,356 Maintenance and other operating 2,118,174 1,799,781 1,855,585 Depreciation and decommissioning 1,221,952 1,360,118 1,397,470 Administrative and general 1,016,439 971,576 973,302 Workforce reduction costs -- (18,195) 249,097 Property and other taxes 292,497 295,380 296,911 --------------- --------------- --------------- Total operating expenses 7,714,387 6,858,780 7,926,444 --------------- --------------- --------------- Operating Income 1,895,585 2,762,985 2,423,786 --------------- --------------- --------------- Interest income 72,900 72,524 79,643 Interest expense (639,823) (688,408) (729,207) Other income and (expense) (18,459) 87,073 69,995 --------------- --------------- --------------- Pretax Income 1,310,203 2,234,174 1,844,217 --------------- --------------- --------------- Income Taxes 554,994 895,289 836,767 --------------- --------------- --------------- Net Income 755,209 1,338,885 1,007,450 Preferred dividend requirement and redemption premium 33,113 70,288 57,603 --------------- --------------- --------------- Earnings Available for Common Stock $ 722,096 $1,268,597 $ 949,847 =============== =============== =============== Weighted Average Common Shares Outstanding 412,542 423,692 429,846 Earnings Per Common Share $ 1.75 $ 2.99 $ 2.21 Dividends Declared Per Common Share $ 1.77 $ 1.96 $ 1.96
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 20 PG&E Corporation Statement of Consolidated Cash Flows
Year ended December 31, 1996 1995 1994 ------------ ------------ ------------ (in thousands) Cash Flows From Operating Activities Net income $ 755,209 $ 1,338,885 $ 1,007,450 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and decommissioning 1,221,952 1,360,118 1,397,470 Amortization 93,948 89,353 95,331 Deferred income taxes and tax credits--net (149,990) (116,069) 15,312 Other deferred charges 94,475 61,700 32,740 Other noncurrent liabilities 113,244 (17,218) 181,902 Noncurrent balancing account liabilities and other deferred credits (185,390) (69,787) 316,920 Net effect of changes in operating assets and liabilities Accounts receivable (46,368) 212,515 (116,936) Regulatory balancing accounts receivable 302,188 498,756 (269,250) Inventories 32,043 32,409 66,783 Accounts payable 193,012 49,702 (110,033) Accrued taxes 36,014 (162,374) 132,892 Other working capital (6,234) 8,304 5,821 Other--net 156,773 50,423 191,285 ------------ ------------ ------------ Net cash provided by operating activities 2,610,876 3,336,717 2,947,687 ------------ ------------ ------------ Cash Flows From Investing Activities Capital expenditures (1,230,331) (944,618) (1,126,904) Diversified operations (99,532) (178,874) (308,810) Acquisition of PGT Queensland Gas Pipeline (136,227) -- -- Acquisition of Energy Source (23,270) -- -- Proceeds from sale of DALEN -- 340,000 -- Other--net (119,923) (122,913) (29,914) ------------ ------------ ------------ Net cash used by investing activities (1,609,283) (906,405) (1,465,628) ------------ ------------ ------------ Cash Flows From Financing Activities Common stock issued 219,726 139,595 274,269 Common stock repurchased (455,278) (601,360) (181,558) Preferred stock issued -- -- 62,312 Preferred stock redeemed or repurchased -- (358,212) (82,875) Company obligated mandatorily redeemable preferred securities issued -- 300,000 -- Long-term debt issued 1,087,732 591,160 60,907 Long-term debt matured, redeemed, or repurchased (1,471,390) (1,296,549) (436,673) Short-term debt issued (redeemed)--net (115,243) 305,262 (239,478) Dividends paid (843,997) (891,270) (891,850) Other--net (14,036) (21,543) 28,721 ------------ ------------ ------------ Net cash used by financing activities (1,592,486) (1,832,917) (1,406,225) ------------ ------------ ------------ Net Change in Cash and Cash Equivalents (590,893) 597,395 75,834 Cash and Cash Equivalents at January 1 734,295 136,900 61,066 ------------ ------------ ------------ Cash and Cash Equivalents at December 31 $ 143,402 $ 734,295 $ 136,900 ============ ============ ============ Supplemental disclosures of cash flow information Cash paid for Interest (net of amounts capitalized) $ 598,394 $ 644,978 $ 674,758 Income taxes 639,813 1,125,635 712,777
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 21 PG&E Corporation Consolidated Balance Sheet
December 31, 1996 1995 ------------- ------------- (in thousands) Assets Plant in Service Electric Nonnuclear $18,099,342 $17,530,446 Diablo Canyon 6,658,137 6,646,853 Gas 8,138,106 7,732,681 ------------- ------------- Total plant in service (at original cost) 32,895,585 31,909,980 Accumulated depreciation and decommissioning (14,301,934) (13,311,500) ------------- ------------- Net plant in service 18,593,651 18,598,480 ------------- ------------- Construction Work in Progress 414,229 333,263 Other Noncurrent Assets Nuclear decommissioning funds 882,929 769,829 Investment in nonregulated projects 817,259 855,962 Other assets 134,271 130,128 ------------- ------------- Total other noncurrent assets 1,834,459 1,755,919 ------------- ------------- Current Assets Cash and cash equivalents 143,402 734,295 Accounts receivable, net 1,499,674 1,268,936 Regulatory balancing accounts receivable 444,156 746,344 Inventories Materials and supplies 185,771 181,763 Gas stored underground 130,229 146,499 Fuel oil 23,433 40,756 Nuclear fuel 190,652 175,957 Prepayments 54,116 47,025 ------------- ------------- Total current assets 2,671,433 3,341,575 ------------- ------------- Deferred Charges Income tax-related deferred charges 1,133,043 1,079,673 Other deferred charges 1,483,110 1,741,380 ------------- ------------- Total deferred charges 2,616,153 2,821,053 ------------- ------------- Total Assets $26,129,925 $26,850,290 ============= =============
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 22 PG&E Corporation Consolidated Balance Sheet
December 31, 1996 1995 ------------ ------------ (in thousands) Capitalization and Liabilities Capitalization Common stock equity $ 8,363,301 $ 8,599,133 Preferred stock without mandatory redemption provisions 402,056 402,056 Preferred stock with mandatory redemption provisions 137,500 137,500 Company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures 300,000 300,000 Long-term debt 7,770,067 8,048,546 ------------ ------------ Total capitalization 16,972,924 17,487,235 ------------ ------------ Current Liabilities Short-term borrowings 680,900 829,947 Current portion of long-term debt 209,867 304,204 Accounts payable Trade creditors 834,143 413,972 Other 365,499 387,747 Accrued taxes 310,271 274,093 Amounts due customers 186,899 49,175 Deferred income taxes 157,064 227,782 Interest payable 63,193 70,179 Dividends payable 123,310 205,467 Other 309,104 455,798 ------------ ------------ Total current liabilities 3,240,250 3,218,364 ------------ ------------ Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 3,941,435 3,933,765 Deferred tax credits 379,563 393,255 Noncurrent balancing account liabilities 120,858 185,647 Other 1,474,895 1,632,024 ------------ ------------ Total deferred credits and other noncurrent liabilities 5,916,751 6,144,691 ------------ ------------ Commitments and Contingencies (Notes 1, 2, 3, 12, and 13) -- -- ------------ ------------ Total Capitalization and Liabilities $26,129,925 $26,850,290 ============ ============
23 PG&E Corporation
Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities Preferred Preferred Stock Stock Total Without With Additional Common Mandatory Mandatory Common Paid-in Reinvested Stock Redemption Redemption (dollars in thousands) Stock Capital Earnings Equity Provisions Provisions ---------- ---------- ---------- ---------- ---------- ---------- Balance December 31, 1993 $2,136,095 $3,666,455 $2,643,487 $8,446,037 $ 807,995 $ 75,000 ---------- ---------- ---------- ---------- ---------- ---------- Net income 1,007,450 1,007,450 Common stock issued (10,508,483 shares) 52,543 221,726 274,269 Common stock repurchased (7,485,001 shares) (37,425) (66,334) (77,799) (181,558) Preferred stock issued (2,500,000 shares) (188) (188) 62,500 Preferred stock redeemed (3,000,000 shares) (5,331) (2,544) (7,875) (75,000) Cash dividends declared Preferred stock (58,203) (58,203) Common stock (840,627) (840,627) Other (9,820) 5,540 (4,280) ---------- ---------- ---------- ---------- ---------- ---------- Balance December 31, 1994 2,151,213 3,806,508 2,677,304 8,635,025 732,995 137,500 ---------- ---------- ---------- ---------- ---------- ---------- Net income 1,338,885 1,338,885 Common stock issued (5,316,876 shares) 26,584 113,011 139,595 Common stock repurchased (21,533,977 shares) (107,669) (195,383) (298,308) (601,360) Preferred securities issued/(1)/ (12,000,000 shares) 300,000 Preferred stock redeemed or repurchased (13,237,554 shares) (7,814) (19,459) (27,273) (330,939) Cash dividends declared Preferred stock (56,006) (56,006) Common stock (829,828) (829,828) Other 95 95 ---------- ---------- ---------- ---------- ---------- ---------- Balance December 31, 1995 2,070,128 3,716,322 2,812,683 8,599,133 402,056 437,500 ---------- ---------- ---------- ---------- ---------- ---------- Net income 755,209 755,209 Common stock issued (9,290,102 shares) 46,448 173,278 219,726 Common stock repurchased (19,811,396 shares) (99,055) (182,088) (174,135) (455,278) Cash dividends declared Preferred stock (33,113) (33,113) Common stock (728,727) (728,727) Other 2,381 3,970 6,351 ---------- ---------- ---------- ---------- ---------- ---------- Balance December 31, 1996 $2,017,521 $3,709,893 $2,635,887 $8,363,301 $ 402,056 $437,500 ========== ========== ========== ========== ========== ==========
/(1)/ Relates to company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures. The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 24 PG&E Corporation Statement of Consolidated Capitalization
December 31, 1996 1995 ------------ ----------- (dollars in thousands, except per share amounts) Common Stock Equity Common stock, par value $5 per share (authorized 800,000,000 shares, issued and outstanding 403,504,292 and 414,025,856) $ 2,017,521 $ 2,070,128 Additional paid-in capital 3,709,893 3,716,322 Reinvested earnings 2,635,887 2,812,683 ------------ ----------- Common stock equity 8,363,301 8,599,133 Preferred Stock and Preferred Securities Preferred stock without mandatory redemption provisions Par value $25 per share/(1)/ Nonredeemable 5% to 6%--5,784,825 shares outstanding 144,621 144,621 Redeemable 4.36% to 7.44%--10,297,404 shares outstanding 257,435 257,435 ------------ ----------- Total preferred stock without mandatory redemption provisions 402,056 402,056 ------------ ----------- Preferred stock with mandatory redemption provisions Par value $25 per share/(1)/ 6.30% and 6.57%--5,500,000 shares outstanding, due 2002-2009 137,500 137,500 ------------ ----------- Preferred stock 539,556 539,556 ------------ ----------- Company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures 7.90%--12,000,000 shares outstanding, due 2025 300,000 300,000 ------------ ----------- Long-Term Debt PG&E long-term debt First and refunding mortgage bonds Maturity Interest rates 1996-2001 4.50% to 8.75% 880,450 915,249 2002-2006 5.875% to 7.875% 1,392,135 1,450,000 2007-2012 6.25% to 8.875% 475,000 477,870 2013-2019 7.5% to 8.2% 45,000 105,000 2020-2026 5.85% to 8.875% 2,627,736 2,749,651 ------------ ----------- Principal amounts outstanding 5,420,321 5,697,770 Unamortized discount net of premium (49,923) (55,802) ------------ ----------- Total mortgage bonds 5,370,398 5,641,968 Debentures, 12%, due 2000 57,539 57,539 Pollution control loan agreements, variable rates, due 2016-2026 987,870 925,000 Unsecured medium-term notes, 4.93% to 9.9%, due 1997-2014 828,900 1,096,400 Unamortized discount related to unsecured medium-term notes (1,187) (1,652) Other long-term debt 32,800 20,298 ------------ ----------- Total PG&E long-term debt 7,276,320 7,739,553 Long-term debt of PGT and Enterprises 703,614 613,197 ------------ ----------- Total long-term debt 7,979,934 8,352,750 Less current portion 209,867 304,204 ------------ ----------- Long-term debt, excluding current portion 7,770,067 8,048,546 ------------ ----------- Total Capitalization $16,972,924 $17,487,235 ============ ===========
/(1)/ Authorized 75,000,000 shares in total (both with and without mandatory redemption provisions). The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 25 PG&E Corporation Statement of Consolidated Segment Information
Electric Gas Diversified Intersegment (in thousands) Utility Utility Operations/(4)/ Eliminations Total ------------ ----------- -------------- -------------- ------------ 1996 Operating revenues $ 7,160,215 $2,039,802 $ 409,955 $ -- $ 9,609,972 Intersegment revenues/(1)/ 12,156 69,645 -- (81,801) -- ------------ ----------- -------------- -------------- ------------ Total operating revenues $ 7,172,371 $2,109,447 $ 409,955 $(81,801) $ 9,609,972 ============ =========== ============== ============== ============ Depreciation and decommissioning $ 919,958 $ 288,994 $ 13,000 $ -- $ 1,221,952 Operating income before income taxes/(2)/ 1,757,611 184,506 (47,921) 1,389 1,895,585 Capital expenditures/(3)/ 921,425 459,074 23,270 -- 1,403,769 Identifiable assets/(3)/ $18,005,105 $6,215,028 $1,434,216 $ -- $25,654,349 Corporate assets 475,576 ------------ Total assets at year end $26,129,925 ============ 1995 Operating revenues $ 7,386,307 $2,059,117 $ 176,341 $ -- $ 9,621,765 Intersegment revenues/(1)/ 12,678 85,356 -- (98,034) -- ------------ ----------- -------------- -------------- ------------ Total operating revenues $ 7,398,985 $2,144,473 $ 176,341 $(98,034) $ 9,621,765 ============ =========== ============== ============== ============ Depreciation and decommissioning $ 1,007,467 $ 306,717 $ 45,934 $ -- $ 1,360,118 Operating income before income taxes/(2)/ 2,267,193 540,378 (46,618) 2,032 2,762,985 Capital expenditures/(3)/ 679,866 282,724 2,067 -- 964,657 Identifiable assets/(3)/ $18,610,610 $6,064,596 $1,042,764 $ -- $25,717,970 Corporate assets 1,132,320 ------------ Total assets at year end $26,850,290 ============ 1994 Operating revenues $ 8,021,547 $2,081,062 $ 247,621 $ -- $10,350,230 Intersegment revenues/(1)/ 12,852 85,341 -- (98,193) -- ------------ ----------- -------------- -------------- ------------ Total operating revenues $ 8,034,399 $2,166,403 $ 247,621 $(98,193) $10,350,230 ============ =========== ============== ============== ============ Depreciation and decommissioning $ 982,859 $ 295,979 $ 118,632 $ -- $ 1,397,470 Operating income before income taxes/(2)/ 2,187,569 271,537 (32,093) (3,227) 2,423,786 Capital expenditures/(3)/ 834,494 292,000 19,456 -- 1,145,950 Identifiable assets/(3)/ $19,637,222 $6,167,314 $1,436,128 $ -- $27,240,664 Corporate assets 467,900 ----------- Total assets at year end $27,708,564 ============
/(1)/ Intersegment electric and gas revenues are accounted for at tariff rates prescribed by the CPUC. /(2)/ General corporate expenses are allocated in accordance with FERC Uniform System of Accounts and requirements of the CPUC. /(3)/ Includes an allocation of common plant in service and allowance for funds used during construction. /(4)/ Represents the nonregulated operations of wholly-owned subsidiaries including Enterprises, Mission Trail Insurance Ltd. (liability insurance), and Energy Source (gas marketing). The accompanying Notes to the Consolidated Financial Statements are an integral part of this schedule. 26 PG&E Corporation Notes to Consolidated Financial Statements Note 1: Significant Accounting Policies Corporate Restructuring: Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a subsidiary of its new parent holding company, PG&E Corporation. PG&E's ownership interest in Pacific Gas Transmission Company (PGT) and PG&E Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's outstanding common stock was converted on a share-for-share basis into PG&E Corporation's outstanding common stock. PG&E's debt securities and preferred stock were unaffected and remain securities of PG&E. The members of PG&E's current Board of Directors became directors of PG&E Corporation. Basis of Presentation: The consolidated financial statements include the accounts of PG&E and its wholly-owned and controlled subsidiaries (collectively, the Company) and, therefore, also represent the accounts of PG&E Corporation and its subsidiaries. All significant intercompany transactions have been eliminated. Certain amounts in the prior years' consolidated financial statements have been reclassified to conform to the 1996 presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, and liabilities and disclosure of contingencies. Actual results could differ from these estimates. Operations: The Company and its subsidiaries provide electric and natural gas services and retail energy services. PG&E is a regulated public utility which provides generation, procurement, transmission, and distribution of electricity and natural gas throughout most of Northern and Central California. PGT transports gas from the Canadian border to the California border and the Pacific Northwest. PGT also has operations in Australia and Texas. Enterprises, through its subsidiaries and affiliates, develops, owns, and operates electric and gas projects and provides energy services. Regulation: PG&E is regulated by the California Public Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission, among others. PG&E currently accounts for the economic effects of regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows the Company to record certain regulatory assets and liabilities which would be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities. Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 121 prescribes general standards for the recognition and measurement of impairment losses. In addition, it requires that regulatory assets continue to be probable of recovery in rates, rather than only at the time the regulatory asset is recorded. Regulatory assets currently recorded would be written off if recovery is no longer probable. Adoption of this standard had no material impact on the Company's financial position or results of operations. On an ongoing basis, PG&E reviews its regulatory assets and liabilities for the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. (See Note 2 for further discussion.) Net regulatory assets and liabilities include the following:
December 31, 1996 1995 ------ ------ (in millions) Deferred income tax $1,133 $1,080 Unamortized loss net of gain on reacquired debt 377 392 Diablo Canyon pre-settlement costs 364 382 Workers' compensation and disability claims costs 288 297 Regulatory balancing accounts (net) 323 561 Other deferred (net) 267 474 ------ ------ $2,752 $3,186 ====== ======
Revenues and Regulatory Balancing Accounts: Revenues are recorded primarily for delivery of gas and electric energy to customers. Electric and gas utility revenues include amounts for services rendered but unbilled at the end of the year. Revenues also are recorded for changes in regulatory balancing accounts established by the CPUC. Specifically, sales balancing accounts accumulate differences between authorized and actual base revenues. Energy cost balancing accounts accumulate differences between the actual cost of gas and electric energy and the revenues designated for recovery of such costs. Recovery of gas and electric energy costs through energy cost balancing accounts is subject to 27 PG&E Corporation Notes to Consolidated Financial Statements reasonableness reviews by the CPUC. The regulatory balancing accounts accumulate balances until they are refunded to or received from utility customers through authorized rate adjustments. Dividend Restriction: PG&E is limited as to the amount of dividends that it may pay to PG&E Corporation based on PG&E's regulatory capital structure authorized by the CPUC. PG&E's equity shall be retained such that, on average, the capital structure authorized by the CPUC is maintained. This restriction is not expected to affect PG&E Corporation's ability to meet its cash obligations. Financial Derivative Instruments (Derivatives): The Company engages in price risk management activities to manage risks associated with changes in energy commodity prices, interest rates, and foreign currencies. These price risk management activities include the use of derivatives. Gains and losses on derivatives used for hedging purposes are intended to offset losses and gains on the underlying hedged item. Under hedge accounting, changes in the market value of these transactions are deferred and recognized as an addition to the income or expense of the underlying instrument upon completion of the underlying transaction. All 1996 transactions were accounted for using hedge accounting. Gains and losses associated with derivative transactions during 1996 were immaterial. Plant in Service: The cost of plant additions and replacements includes labor, materials, construction overhead, and an allowance for funds used during construction (AFUDC) or capitalized interest. AFUDC is the estimated cost of debt and equity funds used to finance regulated plant additions. Capitalized interest is the interest incurred on borrowed funds used to finance nonregulated plant additions. The original cost of retired plant and removal costs less salvage value is charged to accumulated depreciation upon retirement of plant in service. Plant in service is depreciated using a straight-line remaining-life method. The Company's composite depreciation rates were 3.65, 4.09, and 4.31 percent for the years ended December 31, 1996, 1995, and 1994. Nuclear Decommissioning Costs: The estimated total obligation for decommissioning PG&E's nuclear power facilities is comprised of the total cost (including labor, materials, and other costs) of decommissioning and dismantling plant systems and structures. In addition, a contingency amount for possible changes in regulatory requirements and increases in waste disposal costs is included in the estimated total obligation. The estimated total obligation for nuclear decommissioning costs, based on a 1994 site study, is approximately $1.2 billion in 1996 dollars (or $5.9 billion in future dollars). Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, and costs of labor, materials, and equipment. The estimated total obligation is being recognized proportionately over the license of each facility. For the years ended December 31, 1996, 1995, and 1994, nuclear decommissioning costs recovered in rates through an annual allowance were $33, $54, and $54 million, respectively. Based on the 1994 site study, the amount assumed to be recovered in rates in 1997 and annually up to the commencement of decommissioning is $33 million. This amount will be reviewed in future rate proceedings. At December 31, 1996, the total nuclear decommissioning obligation accrued was $889 million and was 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. (See Note 8 for further discussion of nuclear decommissioning funds.) Decommissioning is scheduled to begin for Diablo Canyon Nuclear Power Plant's (Diablo Canyon) Unit 1 and Unit 2 in 2015 and 2016, respectively, with scheduled completion for both units in 2034. The decommissioning method selected for Diablo Canyon anticipates that the facilities will be decontaminated to a level that permits the property to be released for unrestricted use. Decommissioning for Humboldt Bay Power Plant is scheduled to begin in 2015. The decommissioning method selected consists of placing and maintaining the facility in protective storage until some future time when dismantling can be initiated. PG&E, as required by federal law, has signed a contract with the U.S. Department of Energy (DOE) to provide for the 28 disposal of spent nuclear fuel and high-level radioactive waste from PG&E's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has officially acknowledged that it will not be able to meet its contract commitment. 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, PG&E'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. PG&E is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. Gains and Losses on Reacquired Debt: Gains and losses on reacquired debt charged to operations subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining original lives of the debt reacquired, consistent with ratemaking principles. Gains and losses on reacquired debt associated with other operations are recognized in earnings at the time such debt is reacquired. Inventories: Stored nuclear fuel inventory is stated at lower of average cost or market. Nuclear fuel in the reactor is amortized based on the amount of energy output. Other inventories are valued at average cost except for fuel oil, which is valued by the last-in-first-out method. Cash Equivalents: Cash equivalents (stated at cost, which approximates market) include working funds and short-term investments with original maturities of three months or less. Note 2: Electric Industry Restructuring In 1995, the CPUC issued a decision that provides a plan to restructure California's electric utility industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called "transition costs." In 1996, California legislation was passed that adopts the basic tenets of the CPUC's restructuring decision, including recovery of transition costs. In addition, the legislation provides a 10 percent rate reduction for residential and small commercial customers by January 1, 1998, freezes electric customer rates for all other customers, and requires the accelerated recovery of transition costs associated with owned generation facilities. The legislation also establishes the operating framework for a competitive generation market. The rate freeze will continue until the earlier of March 31, 2002, or until PG&E has recovered its transition costs (the transition period). The freeze will hold rates at 1996 levels for all customers except those receiving the 10 percent rate reduction. The rate freeze will hold the rates for these customers at the reduced level. To achieve the 10 percent rate reduction, the legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current cost of capital. Once this portion of transition costs is financed, PG&E would collect a bond service payment to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs will lower the amounts paid by these customers each year during the transition period thereby achieving the 10 percent reduction in rates. Tax-exempt trusts have been established to oversee the development of the operating framework for the competitive generation market. The CPUC has authorized California utilities to guarantee bank loans of up to $250 million to be used by the trusts for this purpose. Under this authorization, PG&E will guarantee a maximum of $112.5 million of these loans. Transition Cost Recovery: The legislation authorizes the CPUC to determine the costs eligible for recovery as transition costs. The amount of costs will be based on the aggregate of above-market and below-market values of utility-owned generation assets and obligations. PG&E has proposed that costs eligible for transition cost recovery include: (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and currently collected through rates) and future costs, such as costs related to plant removal, 29 PG&E Corporation Notes to Consolidated Financial Statements (2) above-market costs associated with purchase power obligations with Qualifying Facilities (QFs) and other Power Purchase Agreements, and (3) generation-related regulatory assets and obligations. PG&E cannot determine the exact amount of sunk costs that will be above market and recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each generation facility. This process will be completed during the transition period. Most transition costs must be recovered by March 1, 2002. However, the legislation authorizes recovery of certain transition costs after that time. These costs include: (1) certain employee-related transition costs, (2) payments under existing QF and power purchase contracts, and (3) unrecovered implementation costs. Excluding these exceptions, any transition costs not recovered during the transition period will be absorbed by PG&E. Nuclear decommissioning costs, which are not considered transition costs, will be recovered through a CPUC authorized charge. During the transition period, this charge will be incorporated into the frozen rates. After the transition period, customers will be assessed a surcharge until the nuclear decommissioning costs are fully recovered. PG&E's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the extent to which application of the current regulatory framework established by the restructuring legislation will continue to be applied, (2) the amount of transition costs approved by the CPUC, (3) the market value of its generation plants, (4) future sales levels, (5) fuel and operating costs, (6) the market price of electricity, and (7) the ratemaking methodology adopted for Diablo Canyon. Considering its current evaluation of these factors, PG&E believes it will recover its transition costs and that its owned generation plants are not impaired. However, a change in these factors could affect the probability of recovery of transition costs and result in a material loss. PG&E has proposed to implement portions of its transition cost recovery plan in 1997. The CPUC decision on PG&E's 1997 Energy Cost Adjustment Clause (ECAC) application would decrease PG&E's 1997 revenue requirement by $720 million. This decrease would be partially offset by a $160 million revenue requirement increase, provided by the legislation, for purposes of enhancing transmission and distribution system safety and reliability. This increase was approved by the CPUC as part of PG&E's transition cost recovery plan. Given the electric customer rate freeze, the $560 million net revenue requirement decrease resulting from the consolidation of the ECAC decision and the revenue requirement increase contemplated in the cost recovery plan would be available for transition cost recovery. The proposed accelerated recovery of Diablo Canyon would absorb an estimated $400 million of this available revenue requirement. The remaining revenue requirement would be available to recover other transition costs. Accounting for the Effects of Regulation: As a result of applying the provisions of SFAS No. 71 (discussed in Note 1 above), PG&E has accumulated approximately $1.6 billion of regulatory assets attributable to electric generation at December 31, 1996. The net investments in Diablo Canyon and the other generation assets were $4.5 and $2.7 billion, respectively, at December 31, 1996. The net present value of above-market QF power purchase obligations is estimated to be $5.3 billion at January 1, 1998, at an assumed market price of $0.025 per kilowatt-hour (kWh) beginning in 1997 and escalating at 3.2 percent per year. PG&E believes that the restructuring legislation establishes a definitive transition to market-based pricing for electric generation. Incorporating the effects of the competitive auction pricing of electricity and customer direct access, this transition includes cost-of-service based ratemaking. In addition, PG&E's generation-related transition costs will be collected through a nonbypassable charge. Based on this structure, PG&E believes it will continue to meet the requirements of SFAS No. 71 throughout the transition period. At the conclusion of the transition period, PG&E believes it will be at risk to recover its generation costs through market-based revenues. At that time, PG&E expects to discontinue the application of SFAS No. 71 for the electric generation portion of its business. Since PG&E anticipates it will have recovered all transition costs required to be recovered during the transition period, including generation-related regulatory assets and above-market investments in net plant, PG&E does not expect a material adverse impact on its financial position or results of operations from discontinuing the application at that time. As a result of the CPUC's restructuring decision and California's electric industry restructuring legislation, the Securities and Exchange Commission (SEC) has begun inquiries regarding the appropriateness of the continued application of 30 SFAS No. 71 by California utilities to their electric generation businesses. As discussed above, PG&E believes it currently meets and will continue to meet the requirements to apply SFAS No. 71 during the transition period. In the event that the SEC concludes that the current regulatory and legal framework in California no longer meets the requirements to apply SFAS No. 71 to the generation business, the Company would reevaluate the financial impact of electric industry restructuring and a material write-off could occur. Given the current regulatory environment, PG&E's electric transmission and distribution businesses are expected to remain regulated and, as a result, will continue application of the provisions of SFAS No. 71. Note 3: Natural Gas Matters The Gas Accord Settlement (Accord): In an effort to promote competition and to give all residential and smaller commercial (core) customers the same options that exist for industrial and larger commercial (noncore) customers, PG&E submitted the Accord to the CPUC in 1996. In addition to offering increased customer choice, the Accord would establish gas transmission rates for the period July 1997 through December 2002 and resolve various pending regulatory issues. The Accord must be approved by the CPUC before it can be implemented. A CPUC decision is expected in 1997. The major outstanding gas regulatory issues that the Accord would resolve include the 1988 through 1995 gas reasonableness proceedings, the initial capital costs for the PG&E Pipeline Expansion, the interstate transition cost surcharge (ITCS) recovery, and the PG&E pipeline transportation commitments, all of which are discussed in further detail below. As of December 31, 1996, PG&E has reserved approximately $527 million, including $182 million reserved during 1996, relating to its gas regulatory issues and gas capacity commitments, the majority of which are addressed by the Accord. The Company believes the ultimate resolution of these matters, whether through approval of the Accord or otherwise, will not have a material adverse impact on its financial position or future results of operations. Gas Reasonableness Proceedings: Recovery of gas costs through PG&E's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were reasonable. Under the current regulatory framework, annual reasonableness proceedings are conducted by the CPUC on a historic calendar year basis. In 1994, the CPUC issued a decision which ordered a disallowance of approximately $90 million of gas costs plus accrued interest of approximately $25 million through 1993 for PG&E's Canadian gas procurement activities from 1988 through 1990. PG&E has filed a lawsuit in a federal district court challenging the CPUC's decision on Canadian gas costs. PG&E expects this issue to be resolved as part of the Accord discussed above. Under the Accord, PG&E would agree to forgo recovery of the $90 million disallowance ordered in the 1988 through 1990 gas reasonableness proceeding, irrespective of the outcome of the lawsuit. A number of other reasonableness issues related to PG&E's gas procurement practices, transportation capacity commitments, and supply operations for periods dating from 1988 to 1994 were resolved when the CPUC accepted a settlement in December 1996 between PG&E and the Office of Ratepayer Advocates (ORA) of the CPUC. Under the terms of that settlement, PG&E will return $67 million plus interest to ratepayers in 1997. PG&E has previously recorded reserves for this settlement. PGT/PG&E Pipeline Expansion: In November 1993, the Company expanded its natural gas transmission system providing additional firm transportation capacity from the Canadian border to Northern and Southern California and the Pacific Northwest. PG&E has filed an application with the CPUC requesting that capital costs of $810 million and ongoing operating costs for the PG&E, or California, portion of the Pipeline Expansion be found reasonable. Revenues are currently being collected under interim rates approved by the CPUC, subject to adjustment. In 1996, a CPUC Administrative Law Judge (ALJ) ordered consolidation of the market impact phase of the PG&E Pipeline Expansion reasonableness proceeding and the ITCS proceeding discussed below. An ALJ also ordered reopening of the 1993 PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding the decision to construct the PG&E Pipeline Expansion. Were the CPUC to reverse its previous decision, which found that PG&E was reasonable in constructing the PG&E Pipeline Expansion, the ultimate outcome could have an adverse impact on PG&E's ability to recover its cost for unused 31 PG&E Corporation Notes to Consolidated Financial Statements capacity on other pipelines as well as on its own intrastate facilities. PG&E expects these issues to be resolved as part of the Accord discussed above. Under the Accord, PG&E would agree to set rates for the PG&E Pipeline Expansion based on total capital costs of $736 million. Transportation Commitments: PG&E 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 PG&E will pay each year may change due to changes in tariff rates. The total demand and transportation charges paid by PG&E under these agreements (excluding agreements with PGT) were approximately $212, $175, and $225 million in 1996, 1995, and 1994, respectively. The following table summarizes the approximate capacity held by PG&E on various pipelines (excluding PGT) and the related annual demand charges at December 31, 1996:
Total Annual Firm Gross Capacity Demand Pipeline Held Charges Contract Company (MMcf/d) (in millions) Expiration --------------- --------------- --------------- El Paso 1,140 $163 Dec. 1997 Transwestern 200 $ 29 Mar. 2007 NOVA 600 $ 20 Oct. 2001 ANG 600 $ 13 Oct. 2005
As a result of regulatory changes, PG&E no longer procures gas for its noncore customers, resulting in a decrease in PG&E's need for firm transportation capacity for its gas purchases. PG&E continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers). To serve these customers, PG&E holds approximately 600 million cubic feet per day (MMcf/d) of firm capacity for its core and core subscription customers on each of the pipelines owned by El Paso Natural Gas Company (El Paso), NOVA Corporation of Alberta (NOVA), Alberta Natural Gas Company Ltd (ANG), and PGT. PG&E is continuing its efforts to broker or assign any remaining unused capacity, including unused capacity held for its core and core subscription customers. Due to relatively low demand for Southwest pipeline capacity, PG&E cannot predict the volume or price of the capacity on El Paso and Transwestern Pipeline Company (Transwestern) that will be brokered or assigned. Substantially all demand charges incurred by PG&E for pipeline capacity are eligible for rate recovery, subject to a reasonableness review. These demand charges include capacity that was formerly used to serve noncore customers but which at present cannot be brokered or which is brokered at a discount. However, certain groups, including the ORA and intervenors, have challenged the recovery of these unrecovered demand charges. In December 1995, the CPUC issued a decision on the reasonableness of PG&E's 1992 operations, concluding that it was unreasonable for PG&E to commit to transportation capacity with Transwestern. The decision orders that costs for the capacity in subsequent years of the contract, which expires in 2007, be disallowed unless PG&E can demonstrate that the benefits of the commitment outweigh the costs. The recovery of demand charges associated with capacity which was formerly used to serve PG&E's noncore customers will be decided by the CPUC in the ITCS proceeding, unless otherwise resolved as part of the Accord. Pending a final decision in the ITCS proceeding, the CPUC has approved collection (subject to refund) in rates of approximately 50 percent of the demand charges for unbrokered or discounted El Paso and PGT capacity which was formerly used to serve PG&E's noncore customers. Under the Accord, PG&E would not recover costs through 1997 associated with Transwestern capacity originally subscribed to in order to serve core customers and would have limited recovery during the period 1998 through 2002. Also as part of the Accord, PG&E would forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated to its core and noncore customers, respectively. The Company believes ultimate resolution of its capacity commitments and the ITCS proceeding, either through approval of the Accord or otherwise, will not have a material adverse impact on its financial position or future results of operations. Note 4: Diablo Canyon The Diablo Canyon rate case settlement as adopted in 1988 and modified in 1995 (Diablo Settlement) bases revenues primarily on the amount of electricity generated by Diablo Canyon. The Diablo Settlement provides that Diablo Canyon costs and operations are not subject to CPUC reasonableness reviews. Only certain Diablo Canyon costs may be recovered 32 through base revenues over the term of the Diablo Settlement, including a full return on such costs. The revenues to recover all Diablo Canyon costs are included in Diablo Canyon operating revenues reported below. Other than for these and decommissioning costs, Diablo Canyon discontinued the application of SFAS No. 71 in July 1988. Under the pricing provisions of the existing Diablo Settlement, the price for power produced by Diablo Canyon for 1997 is 10.0 cents per kWh effective January 1. PG&E has the right to reduce the price below the amount specified. Under the existing settlement, at full operating power, each Diablo Canyon unit would contribute approximately $2.6 million in revenues per day in 1997. The prices per kWh of electricity generated by Diablo Canyon for 1996, 1995, and 1994 were 10.50, 11.00, and 11.89 cents per kWh, respectively. Selected financial information for Diablo Canyon is shown below:
Year ended December 31, 1996 1995 1994 -------- --------- --------- (in millions) Operating revenues $1,789 $1,845 $1,870 Operating income before income taxes 998 1,029 956 Net income 497 507 461
In determining operating results of Diablo Canyon, operating revenues and the majority of operating expenses were specifically identified pursuant to the Diablo Settlement. Administrative and general expenses, principally labor costs, are allocated based on a study of labor costs. Interest is charged to Diablo Canyon based on an allocation of PG&E debt. In conjunction with electric industry restructuring, PG&E filed in March 1996 a proposal for pricing Diablo Canyon generation at market prices and completing recovery of the investment in Diablo Canyon by the end of 2001. If this proposal is adopted, there would be a significant change to the manner in which Diablo Canyon earns revenues. Under its proposal, PG&E would replace the existing settlement prices with: (1) a sunk cost revenue requirement to recover fixed costs, including a return on these costs, and (2) a performance-based ratemaking (PBR) mechanism to recover the facility's variable costs and capital addition costs. As proposed, the sunk cost revenue requirement would accelerate recovery of Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five-year period beginning in 1997 and ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90 percent of pg&e's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. The reduced rate of return combined with a shorter recovery period would result in an estimated $4 billion decrease in the net present value of PG&E's future revenues from Diablo Canyon operations. If the proposed cost recovery plan for Diablo Canyon were adopted during 1996, Diablo Canyon's 1996 reported net income would have been reduced by $350 million ($0.85 per share). Note 5: Preferred Stock and Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely PG&E Subordinated Debentures (See the Statement of Consolidated Capitalization for additional information.) Preferred Stock: PG&E's nonredeemable preferred stock at December 31, 1996, has rights to annual dividends per share ranging from $1.25 to $1.50. PG&E's redeemable preferred stock without mandatory redemption provisions is subject to redemption at PG&E's option, in whole or in part, if PG&E pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. Annual dividends and redemption prices per share at December 31, 1996, range from $1.09 to $1.86 and from $25.75 to $27.25, respectively. PG&E's redeemable preferred stock with mandatory redemption provisions consists of the 6.30% and 6.57% series at December 31, 1996. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. They may be redeemed at PG&E's option, beginning in 2004 and 2002, respectively, at par value plus accumulated and unpaid dividends through the redemption date. The estimated fair value of PG&E's preferred stock with mandatory redemption provisions at December 31, 1996, and 1995, was approximately $135 and $139 million, respectively, based on quoted market prices. In 1995, PG&E redeemed all of its series 7.84%, 8%, and 8.20% redeemable preferred stock. In addition, PG&E repurchased partial amounts of its series 67/8%, 7.04%, and 7.44% redeemable 33 PG&E Corporation Notes to Consolidated Financial Statements preferred stock through a tender offer. The aggregate par value of these redemptions and repurchases was $331 million. Dividends on all preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Upon liquidation or dissolution of PG&E, 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. Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely PG&E Subordinated Debentures: During 1995, PG&E through its wholly-owned subsidiary, PG&E Capital I (Trust), completed a public offering of 12 million shares of 7.90% cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to PG&E 371,135 shares of common securities with an aggregate liquidation value of approximately $9 million. The Trust in turn used the net proceeds from the QUIPS offering and issuance of the common securities to purchase subordinated debentures issued by PG&E with a face value of approximately $309 million, an interest rate of 7.90 percent, and a maturity date of 2025. These subordinated debentures are the only assets of the Trust. Proceeds to PG&E from the sale of the subordinated debentures were used to redeem and repurchase higher-cost preferred stock. PG&E's guarantee of the QUIPS, considered together with the other obligations of PG&E with respect to the QUIPS, constitutes a full and unconditional guarantee by PG&E of the Trust's obligations under the QUIPS issued by the Trust. The subordinated debentures may be redeemed at PG&E's option beginning in 2000 at par plus accrued interest through the redemption date. The proceeds of any redemption will be used by the Trust to redeem QUIPS in accordance with their terms. Upon liquidation or dissolution of PG&E, holders of these QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. The estimated fair value of PG&E's QUIPS at December 31, 1996, and 1995, was approximately $291 and $311 million, respectively, based on quoted market prices. Note 6: Long-term Debt (See the Statement of Consolidated Capitalization for additional information.) Mortgage Bonds: PG&E had $5.4 and $5.7 billion of mortgage bonds outstanding at December 31, 1996, and 1995, respectively. Additional mortgage bonds may be issued, subject to CPUC approval, up to a maximum total amount outstanding of $10 billion. All real properties and substantially all personal properties of PG&E are subject to the lien of the mortgage, and PG&E is required to make semi- annual sinking fund payments for the retirement of the bonds. PG&E redeemed or repurchased $182 and $114 million of mortgage bonds in 1996 and 1995, respectively, with interest rates ranging from 5.375 to 12.75 percent. Included in the total of outstanding mortgage bonds at December 31, 1996, and 1995, are $705 and $768 million, respectively, of mortgage bonds held in trust for the California Pollution Control Financing Authority (CPCFA) with interest rates ranging from 5.85 to 8.875 percent and maturity dates from 2007 to 2023. In addition to these mortgage bonds, PG&E holds long-term loan agreements with the CPCFA as described below. Pollution Control Loan Agreements: In 1996, PG&E refinanced $925 million of variable interest rate pollution control loan agreements with variable interest rate pollution control loan agreements to extend certain maturities and achieve cost savings. These loan agreements from the CPCFA totaled $988 and $925 million, respectively, at December 31, 1996, and 1995. Interest rates on the loans vary with average annual interest rates for 1996 ranging from 3.24 to 3.54 percent. These loans are subject to redemption by the holder under certain circumstances. These loans are secured by irrevocable letters of credit which mature as early as 1999. Long-term Debt of PGT: In 1996, PGT borrowed $92 million of long-term debt to finance the acquisition of PGT Queensland Gas Pipeline. In 1995, PGT issued $470 million of long-term debt, the proceeds of which were used to refinance $600 million of outstanding PGT debt. 34 Additionally, in 1995, PGT issued commercial paper classified as long-term debt based upon the availability of committed credit facilities expiring in 2000 and management's intent to maintain such amounts in excess of one year. The commercial paper outstanding was $108 and $109 million at December 31, 1996, and 1995, respectively. Repayment Schedule: At December 31, 1996, the Company's combined aggregate amounts of maturing long-term debt and sinking fund requirements, for the years 1997 through 2001, are $210, $660, $270, $413, and $376 million, respectively. Fair Value: The estimated fair value of the Company's total long-term debt of $8.0 and $8.4 billion at December 31, 1996, and 1995, respectively, was approximately $8.0 and $8.7 billion, respectively. The estimated fair value of long-term debt was determined based on quoted market prices, where available. Where quoted market prices were not available, the estimated fair value was determined using other valuation techniques (e.g., the present value of future cash flows). Note 7: Short-term Borrowings Substantially all short-term borrowings consist of commercial paper, having a maturity of one to ninety days. Commercial paper outstanding and the associated weighted average interest rate at December 31, 1996, and 1995, were $681 million and 5.86 percent and were $796 million and 5.92 percent, respectively. The carrying amount of short-term borrowings approximates fair value. PG&E maintains a $1 billion revolving credit facility which expires in 2001; however, it may be extended annually for additional one-year periods upon mutual agreement between PG&E and the banks. This credit facility primarily provides support for PG&E's commercial paper issuance. At maturity, commercial paper can be either reissued or replaced with borrowings from this credit facility. There were no borrowings under this facility in 1996 or 1995. In January 1997, PG&E Corporation established a $500 million revolving credit facility in order to provide for corporate short-term liquidity needs and other purposes. Note 8: Investments in Debt and Equity Securities All of PG&E's investments in debt and equity securities are held in external trust funds and are reported at fair value. These investments, which are included in Nuclear Decommissioning Funds, cannot be released from the trust funds until authorized by the CPUC. The proceeds received during 1996 and 1995 from sales were approximately $1.5 billion in each year. During 1996 and 1995, the gross realized gains on sales of securities held as available-for-sale were $14 and $9 million, respectively, and the gross realized losses on sales of securities held as available-for-sale were $20 and $22 million, respectively. The cost of debt and equity securities sold is determined by specific identification. The following table provides a summary of amortized cost and fair value of these investments:
Year ended December 31, 1996 1995 ------------ ------------ (in thousands) Amortized Cost: U.S. government and agency issues $374,931 $322,838 Equity securities 281,532 269,117 Municipal bonds and other 32,952 63,061 Gross unrealized holding gains 198,875 117,673 Gross unrealized holding losses (5,361) (2,860) ------------ ------------ Fair value $882,929 $769,829 ============ ============
Note 9: Employee Benefit Plans Retirement Plan: The Company provides noncontributory defined benefit pension plans covering substantially all employees. Pension benefits are based on an employee's years of service and base salary. The Company's policy is to fund each year not more than the maximum amount deductible for federal income tax purposes and not less than the minimum legal funding requirement. 35 PG&E Corporation Notes to Consolidated Financial Statements The following schedule reconciles the plans' funded status to the pension liability recorded on the Consolidated Balance Sheet:
December 31, 1996 1995 ------------ ------------ (in thousands) Actuarial present value of benefit obligations Vested benefits $(3,486,136) $(3,464,782) Nonvested benefits (177,782) (182,503) ------------ ------------ Accumulated benefit obligation (3,663,918) (3,647,285) Effect of projected future compensation increases (529,045) (548,743) ------------ ------------ Projected benefit obligation (4,192,963) (4,196,028) Plan assets at market value 5,526,247 4,935,267 ------------ ------------ Plan assets in excess of projected benefit obligation 1,333,284 739,239 Unrecognized prior service cost 82,756 90,496 Unrecognized net gain (1,559,281) (1,074,347) Unrecognized net transition obligation 85,895 97,348 ------------ ------------ Accrued pension liability $ (57,346) $ (147,264) ============ ============
Plan assets consist primarily of common stocks and fixed-income securities. Unrecognized prior service costs and net gains are amortized on a straight-line basis over the average remaining service period of active plan participants. The transition obligation is being amortized over 17.5 years from 1987. Using the projected unit credit actuarial cost method, net pension income consisted of the following components:
Year ended December 31, 1996 1995 1994 ----------- ----------- ----------- (in thousands) Service cost for benefits earned $ (99,946) $ (82,814) $(109,132) Interest cost (301,631) (290,563) (272,932) Actual return (loss) on plan assets 811,130 968,126 (20,358) Net amortization and deferral (353,195) (586,350) 412,547 ----------- ----------- ----------- Net pension income $ 56,358 $ 8,399 $ 10,125 =========== =========== ===========
The following actuarial assumptions were used in determining the plans' funded status and net pension income. Year-end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net pension income.
December 31, 1996 1995 1994 -------- -------- -------- Discount rate 7.5% 7.25% 8% Rate of future compensation increases 5% 5% 5% Expected long-term rate of return on plan assets 9% 9% 9%
Net pension income or cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future net pension income or cost. In 1996 and 1995, actual return on plan assets exceeded expected return. In 1994, the plan experienced a negative investment return due to weak performance in domestic equities and bonds. In conformity with SFAS No. 71, regulatory adjustments have been recorded in the income statement and balance sheet for the difference between utility pension income or cost determined for accounting purposes and that for ratemaking, which is based on a funding approach. Postretirement Benefits Other Than Pensions: The Company provides contributory defined benefit medical plans for retired employees and their eligible dependents and noncontributory defined benefit life insurance plans for retired employees. Substantially all employees retiring at or after age 55 are eligible for these benefits. The medical benefits are provided through plans administered by an insurance carrier or a health maintenance organization. Certain retirees are responsible for a portion of the cost based on past claims experience of the Company's retirees. The CPUC has authorized PG&E to recover these benefits for 1993 and beyond. Recovery is based on the lesser of the annual accounting costs or annual contributions on a tax-deductible basis to appropriate trusts. The Company's policy is to fund each year an amount consistent with the basis for rate recovery. 36 The following schedule reconciles the medical and life insurance plans' funded status to the postretirement benefit liability recorded on the Consolidated Balance Sheet:
December 31, 1996 1995 ------------- ------------ (in thousands) Accumulated postretirement benefit obligation Retirees $(444,782) $(528,367) Other fully eligible participants (132,797) (123,615) Other active plan participants (343,864) (309,405) ------------- ------------ Total accumulated postretirement benefit obligation (921,443) (961,387) Plan assets at market value 666,287 538,905 ------------- ------------ Accumulated postretirement benefit obligation in excess of plan assets (255,156) (422,482) Unrecognized prior service cost 21,946 23,761 Unrecognized net gain (226,753) (104,167) Unrecognized transition obligation 419,617 449,647 ------------- ------------ Accrued postretirement benefit liability $ (40,346) $ (53,241)
Plan assets consist primarily of common stocks and fixed-income securities. Unrecognized prior service costs are amortized on a straight-line basis over the average remaining years of service to full eligibility of active plan participants. Unrecognized net gains are amortized on a straight-line basis over the average remaining years of service of active plan participants. The transition obligation is being amortized over 20 years from 1993. Using the projected unit credit actuarial cost method, net postretirement medical and life insurance cost consisted of the following components:
Year ended December 31, 1996 1995 1994 ---------- ----------- ----------- (in thousands) Service cost for benefits earned $ 21,954 $ 17,004 $ 23,617 Interest cost 65,629 64,776 64,872 Actual return on plan assets (91,050) (108,932) (1,232) Amortization of unrecognized prior service cost 1,602 1,616 1,711 Amortization of transition obligation 26,314 26,533 28,913 Net amortization and deferral 38,329 70,070 (29,804) ---------- ---------- ---------- Net postretirement benefit cost $ 62,778 $ 71,067 $ 88,077 ========== ========== ==========
The discount rate, rate of future compensation increases, and expected long- term rate of return on plan assets used in accounting for the postretirement benefit plans for 1996, 1995, and 1994 were the same as those used for the pension plan. The assumed health care cost trend rate for 1997 is approximately 10.0 percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent. The effect of a one-percentage-point increase in the assumed health care cost trend rate for each future year would increase the accumulated postretirement benefit obligation at December 31, 1996, by approximately $75 million and the 1996 aggregate service and interest costs by approximately $8 million. The decrease in net postretirement benefit cost in 1995 compared to 1994 was primarily due to a reduction in workforce and an increase in discount rate. Net postretirement benefit cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future postretirement benefit cost. In 1996 and 1995, actual return on plan assets exceeded expected return. In 1994, actual return on plan assets was less than expected. Workforce Reductions: The effects of workforce reductions announced by PG&E in 1994 are reflected in the pension and postretirement benefits funded status tables above, and the costs are discussed in Note 10. Long-term Incentive Program: PG&E Corporation maintains a Long-term Incentive Program (Program) which provides for grants of stock options to eligible participants with or without associated stock appreciation rights and dividend equivalents. The Program also grants performance-based units to eligible participants. As of December 31, 1996, 24.5 million shares of common stock have been authorized for award under the program. At December 31, 1996, stock options on 3,461,733 shares, granted at option prices ranging from $16.75 to $34.25, were outstanding, of which 1,655,450 were exercisable. In 1996, 877,900 options were granted at an option price of $28.25, which was the market price per share on the date of grant. Outstanding stock options expire ten years and one day after the date of grant and become exercisable on a cumulative 37 PG&E Corporation Notes to Consolidated Financial Statements basis at one-third each year commencing two years from the date of grant. In 1996, 1995, and 1994, stock options on 72,960, 235,568, and 52,143 shares, respectively, were exercised at option prices ranging from $16.75 to $33.13, $16.75 to $33.13, and $24.75 to $32.13, respectively. Effective January 1, 1996, the Company adopted SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123 requires the Company to disclose stock option costs based on the fair value of options granted. For the years ended December 31, 1996, and 1995, the fair value of options granted was not material to the Company's results of operations or earnings per share. Note 10: Workforce Reductions In 1994, PG&E expensed the total cost of its planned 1994-1995 workforce reductions of $249 million and recorded a corresponding liability for benefits to be funded or paid. This amount consisted of $136 million for additional pension benefits, $52 million for other postretirement benefits, and $61 million for estimated severance costs. PG&E did not seek rate recovery for the cost of the 1994-1995 workforce reductions. In 1995, PG&E canceled approximately 800 of the 3,000 planned 1994-1995 reductions in response to the severity of the damage caused by the winter storms of 1995 and the identification of certain facilities that would benefit from a more extensive and accelerated maintenance program. As a result, the estimated severance costs accrued and expensed in 1994 were reduced by $18 million in 1995. Note 11: Income Taxes The Company files a consolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80 percent or more. Income tax expense includes current and deferred income taxes resulting from operations during the year. Tax credits are amortized over the life of the related property. The significant components of income tax expense were:
Year ended December 31, 1996 1995 1994 ------------ ------------ ---------- (in thousands) Current $ 704,984 $1,011,358 $821,455 Deferred (132,250) (97,864) 34,657 Tax credits--net (17,740) (18,205) (19,345) ------------ ------------- ---------- Total income tax expense $ 554,994 $ 895,289 $836,767 ============ ============= ==========
The significant components of net deferred income tax liabilities were:
December 31, 1996 1995 ------------ ------------ (in thousands) Deferred income tax assets $1,308,395 $1,203,981 ------------ ------------ Deferred income tax liabilities: Regulatory balancing accounts $ 294,494 $ 385,604 Plant in service 3,623,544 3,552,974 Income tax-related deferred charges /(1)/ 454,359 443,152 Other 1,034,497 983,798 ------------ ------------ Total deferred income tax liabilities $5,406,894 $5,365,528 ------------ ------------ Total net deferred income taxes $4,098,499 $4,161,547 ============ ============ Classification of net deferred income taxes: Included in current liabilities $ 157,064 $ 227,782 Included in deferred credits 3,941,435 3,933,765 ------------ ------------ Total net deferred income taxes $4,098,499 $4,161,547 ============ ============
/(1)/ Represents the portion of the deferred income tax liability related to the revenues required to recover future income taxes. The differences between income taxes and amounts determined by applying the federal statutory rate to income before income tax expense were:
Year ended December 31, 1996 1995 1994 -------- --------- -------- (in thousands) Federal statutory income tax rate 35.0% 35.0% 35.0% Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) 3.7 4.8 8.3 Effect of regulatory treatment of depreciation differences 5.9 3.2 3.7 Tax credits--net (1.4) (.8) (1.1) Other--net (.8) (2.1) (.5) -------- --------- -------- Effective tax rate 42.4% 40.1% 45.4% ======== ========= ========
Note 12: Commitments Capital Projects: Capital expenditures for 1997 are estimated to be $1,773 million for utility, $38 million for Diablo Canyon, and $211 million for diversified operations. At December 31, 1996, Enterprises had $67 million in firm commitments to make capital contributions for its equity share of generating facility projects. The contributions, payable upon commercial operation of the projects, are estimated to be 38 $52 million in 1997 (included in the expenditures above) and $15 million in 1998. Letters of Credit: PG&E utilizes approximately $247 million in standby letters of credit to secure future workers' compensation liabilities. Qualifying Facilities and Other Power-Purchase Contracts: Under the Public Utility Regulatory Policies Act of 1978, PG&E is required to purchase electric energy and capacity provided by QFs which are cogenerators and small power producers. The CPUC established a series of power-purchase contracts with certain QFs and set the applicable terms, conditions, and price options. Under these contracts, PG&E is required to purchase electric energy and capacity; however, payments are only required when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. PG&E's contracts with QFs expire on various dates from 1997 to 2028. Energy payments to QFs are expected to decline in the years 1997 through 2000. Capacity payments are expected to remain at current levels. In 1996, 1995, and 1994, PG&E negotiated early termination or suspension of certain QF contracts to be paid through 1999 at discounted costs of $25, $142, and $155 million for 1996, 1995, and 1994, respectively. These amounts are expected to be recovered in rates and as such are reflected as deferred charges on the accompanying balance sheet. At December 31, 1996, the total discounted future payments remaining under QF early termination or suspension contracts is $68 million. QF deliveries in the aggregate account for approximately 19 percent of PG&E's 1996 electric energy requirements, and no single contract accounted for more than 5 percent of PG&E's energy needs. PG&E also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, PG&E must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the provider's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the providers. These contracts expire on various dates from 2004 to 2031. The total cost of these payments is recoverable in rates. At December 31, 1996, the undiscounted future minimum payments under these contracts are $34 million for each of the years 1997 through 2001 and a total of $383 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately six percent of PG&E's 1996 electric energy requirements, and no single contract accounted for more than five percent of PG&E's energy needs. The amount of energy received and the total payments made under QF and other power-purchase contracts were:
Year ended December 31, 1996 1995 1994 ---------- ---------- ---------- (in millions) Kilowatt-hours received 26,056 26,468 23,903 QF energy payments $1,136 $1,140 $1,196 QF capacity payments $ 521 $ 484 $ 518 Other power purchase payments $ 52 $ 50 $ 49
Note 13: Contingencies Nuclear Insurance: PG&E has insurance coverage for property damage and business interruption losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). Under these policies, if a nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, PG&E may be subject to maximum assessments of $29 million (property damage) and $8 million (business interruption), in each case per policy period, in the event losses exceed the resources of NML or NEIL. PG&E has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $8.7 billion of coverage is provided by secondary financial protection which provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, PG&E may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: The Company may be required to pay for environmental remediation at sites where the Company has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or the California Hazardous Substance Account Act. These sites include former manufactured gas plant sites and sites used by PG&E for the storage or disposal of materials which may be determined to present a significant threat to human health or the environment because of an actual or potential release of hazardous 39 PG&E Corporation Notes to Consolidated Financial Statements substances. Under CERCLA, the Company's financial responsibilities may include remediation of hazardous substances, even if the Company did not deposit those substances on the site. The Company records a liability when site assessments indicate remediation is probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. Unless there is a better estimate within this range of possible costs, the Company records the lower end of this range (classified as other noncurrent liabilities). The cost of the hazardous substance remediation ultimately undertaken by the Company is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Company has an accrued liability at December 31, 1996, of $170 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $400 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs, or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to the Company, based upon a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. The Company will seek recovery of prudently incurred hazardous substance remediation costs through ratemaking procedures approved by the CPUC. The Company has recorded a regulatory asset at December 31, 1996, of $146 million for recovery of these costs in future rates. Additionally, the Company will seek recovery of costs from insurance carriers and from other third parties. The Company believes the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. Helms Pumped Storage Plant (Helms): Helms is a three-unit hydroelectric combined generating and pumped storage plant with a net investment of $710 million at December 31, 1996. The net investment is comprised of the pumped storage facility (including regulatory assets of $51 million), common plant, and dedicated transmission plant. As part of the 1996 General Rate Case decision in December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of Helms. In July 1996, PG&E submitted its study, which concluded that the continued operation of Helms is cost effective. As a result of the study, PG&E recommended that the CPUC take no action and address Helms along with other generating plants in the context of electric industry restructuring. PG&E is currently unable to predict whether there will be a change in rate recovery resulting from the study. As with its other hydroelectric generating plants, the Company expects to seek recovery of its net investment in Helms through PBR and transition cost recovery. The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. Helms became commercially operable in 1984, following delays due to a water conduit rupture in 1982 and various start-up problems related to the plant's generators. As a result of the rupture damage and the operational delay, PG&E incurred additional costs which were excluded from rate base and lost revenues during the period the plant was under repair. In 1994, PG&E submitted for CPUC approval a settlement with the ORA regarding recovery of such additional costs and lost revenues, amounting to approximately $98 million. In September 1996, the CPUC issued a final decision adopting the settlement which permits PG&E to recover that amount. Because PG&E's current rate recovery already reflects the anticipated settlement, adoption of the settlement will have no impact on rates. 40 Legal Matters: Cities Franchise Fees Litigation: In 1994, the City of Santa Cruz filed a class action suit in a state superior court (Court) against PG&E on behalf of itself and 106 other cities in PG&E's service area. The complaint alleges that PG&E has underpaid electric franchise fees to the cities by calculating those fees at different rates from other cities not included in the complaint. In September 1995, the Court certified the class of 107 cities in this suit and approved the City of Santa Cruz as the class representative. In January and March 1996, the Court made two rulings against certain cities effectively eliminating a major portion of the suit. The Court's rulings do not resolve the suit completely. The cities appealed both rulings. The trial has been postponed pending the cities' appeal. Should the cities prevail on the issue of franchise fee calculation methodology, PG&E's annual systemwide city electric franchise fees could increase by approximately $14 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $145 million (exclusive of interest). If the Court's January and March 1996 rulings become final, PG&E's annual systemwide city electric franchise fees for the remaining class member cities not subject to the Court's rulings could increase by approximately $4 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $39 million (exclusive of interest). The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. Hinkley: In 1996, PG&E settled a 1993 lawsuit seeking damages for personal injuries allegedly suffered as a result of exposure to chromium near PG&E's gas compressor station at Hinkley. This lawsuit was settled for the aggregate sum of $333 million, of which $50 million had been paid in 1994, with the remaining $283 million paid in 1996. PG&E had previously reserved $200 million for this litigation and in 1996 recorded an additional reserve of $133 million for this settlement. The settlement does not resolve other pending chromium litigation, described below. Chromium Litigation: In 1994 through 1996, several civil suits were filed against PG&E on behalf of more than 1,500 individuals. The complaints seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from exposure to chromium in the vicinity of PG&E's gas compressor stations at Hinkley, Kettleman, and Topock. PG&E is responding to the complaints and asserting affirmative defenses. PG&E 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. Given the uncertainty, the Company cannot predict the outcome of this litigation. However, the Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. 41 PG&E Corporation Quarterly Consolidated Financial Data (Unaudited) Quarterly Financial Data: Due to the seasonal nature of the utility business and the scheduled refueling outages for Diablo Canyon, operating revenues, operating income, and net income are not generated evenly every quarter during the year. All four quarters of 1996 reflected a decline in price per kilowatt-hours as provided in the modified pricing provisions of the Diablo Canyon rate case settlement, and revenue reductions authorized by the 1996 General Rate Case (GRC) and other related rate proceedings. In addition, maintenance and operating expenses exceeded levels authorized by the GRC. In the second quarter of 1996, the Company charged to earnings $133 million for the settlement of a litigation claim. Revenues were also reduced due to a greater number of scheduled refueling days and unscheduled outages. In the third quarter of 1996, the Company took charges against earnings of $182 million for contingencies related to gas transportation commitments. In the fourth quarter of 1996, the Company charged to earnings $59 million in write-downs of nonregulated investments. The Company recorded additional litigation reserves of $50 million in the first and third quarters of 1995. Diablo Canyon scheduled refueling days and unscheduled outages reduced earnings per common share in the fourth quarter of 1995. The Company's common stock is traded on the New York, Pacific, and Swiss stock exchanges. There were approximately 198,000 common shareholders of record at December 31, 1996. Dividends are paid on a quarterly basis, and net cash flows are sufficient to maintain the current payment of dividends.
Quarter ended December 31 September 30 June 30 March 31 -------------- --------------- ------------- ------------- (in thousands, except per share amounts) 1996 Operating revenues $2,700,686 $2,521,852 $2,138,666 $2,248,768 Operating income 508,970 524,846 288,375 573,394 Net income 149,030 233,695 111,780 260,704 Earnings per common share .34 .55 .25 .61 Dividends declared per common share .30 .49 .49 .49 Common stock price per share High 24.25 23.88 23.75 28.38 Low 20.88 19.50 21.50 22.38 1995 Operating revenues $2,227,224 $2,637,653 $2,448,641 $2,308,247 Operating income 451,674 781,912 820,370 709,029 Net income 227,085 377,593 405,520 328,687 Earnings per common share .48 .85 .92 .73 Dividends declared per common share .49 .49 .49 .49 Common stock price per share High 30.63 30.00 29.75 25.75 Low 27.13 28.38 24.75 24.25
42 PG&E Corporation Report of Independent Public Accountants To the Shareholders and the Board of Directors of PG&E Corporation: We have audited the accompanying consolidated balance sheet and the statement of consolidated capitalization of PG&E Corporation (a California corporation) and subsidiaries as of December 31, 1996, and 1995, and the related statements of consolidated income, cash flows, common stock equity, preferred stock and preferred securities, and the schedule of consolidated segment information for each of the three years in the period ended December 31, 1996. These financial statements and schedule of consolidated segment information are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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 consolidated financial statements and schedule of consolidated segment information referred to above present fairly, in all material respects, the financial position of PG&E Corporation and subsidiaries as of December 31, 1996, and 1995, and the results of their operations and cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP San Francisco, California February 10, 1997 43 PG&E Corporation Responsibility for Consolidated Financial Statements The responsibility for the integrity of the consolidated financial statements and related financial information included in this report rests with management. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles appropriate in the circumstances and are based on the Company's best estimates and judgments after giving consideration to materiality. The Company maintains systems of internal controls supported by formal policies and procedures which are communicated throughout the Company. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and to produce the records necessary for the preparation of consolidated financial statements. There are limits inherent in all systems of internal controls, based on the recognition that the costs of such systems should not exceed the benefits to be derived. The Company believes its systems provide this appropriate balance. In addition, the Company's internal auditors perform audits and evaluate the adequacy of and the adherence to these controls, policies, and procedures. Arthur Andersen LLP, the Company's independent public accountants, considered the Company's systems of internal accounting controls and conducted other tests as they deemed necessary to support their opinion on the consolidated financial statements. Their auditors' report contains an independent informed judgment as to the fairness, in all material respects, of the Company's reported results of operations and financial position. The financial data contained in this report have been reviewed by the Audit Committee of the Board of Directors. The Audit Committee is composed of six outside directors who meet regularly with management, the corporate internal auditors, and Arthur Andersen LLP, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The Company maintains high standards in selecting, training, and developing personnel to ensure that management's objectives of maintaining strong and effective internal controls and maintaining unbiased and uniform reporting standards are attained. The Company believes its policies and procedures provide reasonable assurance that operations are conducted in conformity with applicable laws and with its commitment to a high standard of business conduct. 44 EX-21 8 SUBSIDIARIES OF THE REGISTRANTS Exhibit 21 SUBSIDIARIES OF THE REGISTRANTS A. PG&E Corporation: 1. Pacific Gas and Electric Company, a California corporation. Pacific Gas and Electric Company has the following subsidiaries: 1.1 Alberta and Southern Gas Co. Ltd., incorporated under the laws of Alberta, Canada 1.1.1 Alberta and Southern Gas Marketing Inc., incorporated under the laws of Alberta, Canada 1.2 Mission Trail Insurance (Cayman) Ltd., incorporated under the laws of the Cayman Islands 1.3 Natural Gas Corporation of California, a California corporation 1.3.1. NGC Production Company, a California corporation 1.4 Pacific Conservation Services Company, a California corporation 1.5 Calaska Energy Company, a California corporation 1.6 Eureka Energy Company, a California corporation 1.7 Standard Pacific Gas Line Incorporated, a California corporation 1.8 Pacific California Gas System, Inc., California corporation 1.9 Pacific Energy Fuels Company, a California corporation 1.10 Pacific Gas Properties Company, a California corporation 2. Pacific Gas Transmission Company ("PGT"), a California corporation. PGT has the following subsidiaries: 2.1 PGT Australia Pty Limited, formed under the laws of New South Wales, Australia 2.2 Pacific Gas Transmission International, Inc., a California corporation 2.3 PGT Queensland Pty Limited, formed under the laws of New South Wales, Australia 2.4 PGT Victoria Pty Limited, formed under the laws of New South Wales, Australia 2.5 PGT Western Australia Pty Limited, formed under the laws of New South Wales, Australia 2.6 PGT Nominees Pty Limited, formed under the laws of New South Wales, Australia 2.7 Energy Source, Inc., a California corporation 2.7.1 PG&E Energy Source Canada, Inc., incorporated under the laws of Alberta, Canada B. Pacific Gas and Electric Company: Pacific Gas and Electric Company's subsidiaries, considered in the aggregate as a single subsidiary (as defined by Rule 1-02 (w) of Regulation S-X), would not constitute a significant subsidiary of Pacific Gas and Electric Company as of December 31, 1996. EX-23 9 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports dated February 10, 1997, included or incorporated by reference in this Form 10-K, into the previously filed registration statements as follows: (1) PG&E Corporation's Form S-3 Registration Statement File No.333- 16255 (relating to PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-64136 (relating to $2,000,000,000 aggregate principal amount of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds and Medium-Term Notes); (3) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal amount of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds); (4) PG&E Corporation's Form S-8 Registration Statement File No. 33-50601 (relating to the Pacific Gas and Electric Company's Savings Fund Plan for Employees); (5) PG&E Corporation's Form S-8 Registration Statement File No. 33-23692 (relating to PG&E Corporation's 1986 Stock Option Plan); (6) Pacific Gas and Electric Company's Form S-3 Registration Statement File No: 33-62488 (relating to 10,000,000 shares of Pacific Gas and Electric Company's Redeemable First Preferred Stock); (7) Form S-3 Registration Statement File No: 33-61959 (relating to $335,000,000 aggregate liquidation value of Cumulative Quarterly Income Preferred Securities); and (8) PG&E Corporation's Form S-8 Registration Statement File No: 333-16253 (relating to PG&E Corporation's Long-Term Incentive Program). ARTHUR ANDERSEN LLP San Francisco, California, March 4, 1997 EX-24.1 10 RESOLUTIONS OF THE BOARD OF DIRECTORS EXHIBIT 24.1 RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PG&E CORPORATION ---------------- February 19, 1997 ----------------- BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS, and JULIE C. GAVIN is hereby authorized to sign on behalf of this corporation and as attorneys in fact for the Chairman of the Board and Chief Executive Officer, Chief Financial Officer, and Controller of this corporation the Form 10-K Annual Report for the year ended December 31, 1996, 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, KATHLEEN RUEGER, do hereby certify that I am an Assistant Corporate Secretary of PG&E CORPORATION, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held at the office of said corporation on February 19, 1997, 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 20th day of February, 1997. KATHLEEN RUEGER --------------- Kathleen Rueger Assistant Corporate Secretary PG&E CORPORATION [CORPORATE SEAL] RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PACIFIC GAS AND ELECTRIC COMPANY -------------------------------- February 19, 1997 ----------------- BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS, and JULIE C. GAVIN, is hereby authorized to sign on behalf of this company and as attorneys in fact for the Chairman of the Board and Chief Executive Officer, Senior Vice President and Chief Financial Officer, and Vice President and Controller of this company the Form 10-K Annual Report for the year ended December 31, 1996, 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, KATHLEEN RUEGER, do hereby certify that I am an Assistant Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held at the office of said corporation on February 19, 1997, 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 20th day of February, 1997. KATHLEEN RUEGER Kathleen Rueger Assistant Corporate Secretary PACIFIC GAS AND ELECTRIC COMPANY [CORPORATE SEAL] EX-24.2 11 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, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, 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, 1996, 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 19th day of February, 1997. Stanley T. Skinner Richard B. Madden - ------------------ ----------------- Robert D. Glynn, Jr. John C. Sawhill - -------------------- --------------- Richard A. Clarke David M. Lawrence - ----------------- ----------------- H. M. Conger Alan Seelenfreund - ------------ ----------------- Mary S. Metz Samuel T. Reeves - ------------ ---------------- Rebecca Q. Morgan Carl E. Reichardt - ----------------- ----------------- C. Lee Cox - ---------- Barry Lawson Williams - --------------------- POWER OF ATTORNEY STANLEY T. SKINNER, the undersigned, Chairman of the Board and Chief Executive Officer of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Chairman of the Board and Chief Executive Officer (principal executive officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1996, 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 19th day of February, 1997. STANLEY T. SKINNER ------------------ STANLEY T. SKINNER POWER OF ATTORNEY GORDON R. SMITH, the undersigned, Chief Financial Officer of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, 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 Chief Financial Officer (principal financial officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1996, 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 19th day of February, 1997. GORDON R. SMITH --------------- GORDON R. SMITH POWER OF ATTORNEY CHRISTOPHER P. JOHNS, the undersigned, Controller of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, 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 Controller (principal accounting officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1996, 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 19th day of February, 1997. CHRISTOPHER P. JOHNS -------------------- CHRISTOPHER P. JOHNS POWER OF ATTORNEY Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, 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, 1996, 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 19th day of February, 1997. Stanley T. Skinner Richard B. Madden - ------------------ ----------------- Robert D. Glynn, Jr. John C. Sawhill - -------------------- --------------- Richard A. Clarke David M. Lawrence - ----------------- ----------------- H. M. Conger Alan Seelenfreund - ------------ ----------------- Mary S. Metz Samuel T. Reeves - ------------ ---------------- Rebecca Q. Morgan Carl E. Reichardt - ----------------- ----------------- C. Lee Cox - ---------- Barry Lawson Williams - --------------------- POWER OF ATTORNEY STANLEY T. SKINNER, the undersigned, Chairman of the Board and Chief Executive Officer of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Chairman of the Board and Chief Executive Officer (principal executive officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1996, 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 19th day of February, 1997. STANLEY T. SKINNER ------------------ STANLEY T. SKINNER POWER OF ATTORNEY GORDON R. SMITH, the undersigned, Senior Vice President and Chief Financial Officer of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Senior Vice President and Chief Financial Officer (principal financial officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1996, 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 19th day of February, 1997. GORDON R. SMITH --------------- GORDON R. SMITH POWER OF ATTORNEY CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, 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, 1996, 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 19th day of February, 1997. CHRISTOPHER P. JOHNS -------------------- CHRISTOPHER P. JOHNS EX-27 12 FINANCIAL DATA SCHEDULE
UT This schedule contains summary financial information extracted from PG&E CORPORATION and is qualified in its entirety by reference to such financial statements. 1,000 YEAR DEC-31-1996 JAN-01-1996 DEC-31-1996 PER-BOOK 19,007,880 1,834,459 2,671,433 2,616,153 0 26,129,925 2,017,521 3,709,893 2,635,887 8,363,301 437,500 402,056 7,770,067 0 0 680,900 209,867 0 0 0 8,266,234 26,129,925 9,609,972 554,994 7,714,387 7,714,387 1,895,585 54,441 1,950,026 639,823 755,209 33,113 722,096 728,727 0 2,610,876 1.75 1.75
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