ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
PG&E Corporation is a holding company, based in San Francisco, California, which provides energy services throughout the United States and in Australia. Effective January 1, 1997, Pacific Gas and Electric Company and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. In the holding company reorganization, Pacific Gas and Electric Company's outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. Pacific Gas and Electric Company's debt securities and preferred stock were unaffected and remain securities of Pacific Gas and Electric Company. The consolidated financial statements of PG&E Corporation incorporated herein include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries (collectively, PG&E Corporation). The consolidated financial statements of Pacific Gas and Electric Company incorporated herein include the accounts of Pacific Gas and Electric Company and its wholly owned and controlled subsidiaries (sometimes referred to in this report as the "Company"). Because PG&E Corporation did not become the holding company for Pacific Gas and Electric Company until January 1, 1997, the 1995 and 1996 consolidated financial statements represent the accounts of Pacific Gas and Electric Company on a consolidated basis as predecessor of PG&E Corporation.
The principal executive offices of PG&E Corporation are located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and the principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and their telephone number is (415) 973-7000.
As of December 31, 1997, PG&E Corporation had $30.6 billion in assets. PG&E Corporation generated $15.4 billion in operating revenues for 1997. As of December 31, 1997, PG&E Corporation and its subsidiaries and affiliates had approximately 23,500 employees.
During 1997, PG&E Corporation expanded its energy-related business activities, which now include the gas and electric utility operations of Pacific Gas and Electric Company; the ownership and operation of natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest, Texas and Australia, through various subsidiaries of PG&E Corporation (PG&E Gas Transmission or PG&E GT); the development, construction, operation, ownership, and management of independent power generation facilities through U.S. Generating Company and its affiliates; the purchase and sale of energy commodities and financial instruments to PG&E Corporation's other businesses, unaffiliated utilities, marketers, municipalities, cooperatives, independent power producers, and large end-use customers through PG&E Energy Trading Corporation and its affiliates (PG&E Energy Trading or PG&E ET); and the provision to customers nationwide with competitively priced natural gas and electricity and services to manage and make more efficient their energy consumption through PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES).
Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in the business of providing electric and natural gas services throughout most of Northern and Central California. As of December 31, 1997, Pacific Gas and Electric Company had $25.1 billion in assets. The Company generated $9.5 billion in operating revenues for 1997. As of December 31, 1997, Pacific Gas and Electric Company had approximately 21,000 employees.
The gas and electric utility operations of Pacific Gas and Electric Company represent the principal component of PG&E Corporation's business, contributing 62% of PG&E Corporation's total revenues in 1997. Pacific Gas and Electric Company's utility operations contributed $1.77 of PG&E Corporation's total 1997 earnings per share of $1.75. (Pacific Gas and Electric Company's earnings were offset by losses at some of PG&E Corporation's other businesses: PG&E Energy Services, PG&E Energy Trading, and U.S. Generating Company.)
Pacific Gas and Electric Company's utility service territory covers 70,000 square miles with an estimated population of approximately 12 million and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, financial services, food processing, petroleum refining, agriculture, and tourism.
At December 31, 1997, Pacific Gas and Electric Company served approximately 4.5 million electric customers. In 1997, Pacific Gas and Electric Company served its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, two nuclear power reactor units at Diablo Canyon Nuclear Power Plant (Diablo Canyon), 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. (In connection with the ongoing California electric industry restructuring, Pacific Gas and Electric Company has entered into agreements to sell three fossil-fueled power plants and has announced plans to sell an additional four power plants plus its geothermal facilities in 1998. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below.) Pacific Gas and Electric Company also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal, and cogeneration. In addition, Pacific Gas and Electric Company is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling, and transmitting power.
Pacific Gas and Electric Company served approximately 3.7 million gas customers at December 31, 1997. To ensure a diverse and competitive mix of natural gas supplies, Pacific Gas and Electric Company purchases gas from both Canadian and United States suppliers. In 1997, about 66% of Pacific Gas and Electric Company's gas supply came from fields in Canada, about 3% came from fields in California, and about 31% came from fields in other states (substantially all from the U.S. Southwest). In 1997, the CPUC approved the Gas Accord Settlement (Gas Accord), a comprehensive multi-party settlement agreement to restructure Pacific Gas and Electric Company's gas services and its role in the gas market, establish gas transmission rates for the period from March 1, 1998 through December 2002, and resolve various gas regulatory issues.
On July 31, 1997, a wholly owned subsidiary of PG&E Corporation merged with Valero Energy Corporation, (Valero) in Texas (now known as PG&E Gas Transmission, Texas Corporation). As a result of the merger, PG&E Corporation acquired Valero's natural gas and natural gas liquids pipelines, natural gas storage facilities, natural gas processing plants, and various gas marketing companies. Through its January 1997 acquisition of Teco Pipeline Company (Teco) in Texas (now known as PG&E Gas Transmission, Teco, Inc.), PG&E Corporation also acquired interests in various natural gas pipelines, natural gas processing facilities, and an operation in Houston, Texas, involved in the purchase and sale of energy commodities and related financial instruments. PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas Transmission Company or PGT) owns and operates an interstate natural gas pipeline in the Pacific Northwest. See "PG&E Corporation's Gas Transmission Operations" below.
Also in 1997, PG&E Corporation established PG&E Energy Services Corporation (formerly Vantus Energy Corporation) to compete in the direct access market in California and to provide customers nationwide with competitively priced natural gas and electricity services to manage and make more efficient their energy consumption. See "PG&E Corporation's Energy Services and Commodities" below. Although the direct access market was scheduled to begin in California on January 1, 1998, in late December 1997, the Independent System Operator (ISO) and the Power Exchange (PX) announced that there would be a delay in the commencement of a direct access market until certain operational and logistical issues are resolved, and that they expected direct access to begin by March 31, 1998. The ISO is the corporation proposed by California electric industry restructuring legislation to operate and control the state's electric transmission facilities and to provide comparable open access to electric transmission service. The PX is the corporation proposed by the California Public Utilities Commission (CPUC) to provide a competitive auction process to establish the price of electricity. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below.
In August 1997, PG&E Corporation announced plans to acquire, through affiliates of U.S. Generating Company (USGen), a portfolio of electric generating assets and power supply contracts from the New England Electric System for approximately $1.59 billion plus $85 million for certain employee- related costs. In September 1997, PG&E Corporation acquired full ownership of USGen, originally formed as a joint venture with Bechtel Enterprises, Inc. (Bechtel). PG&E Corporation also acquired full ownership of certain other partnerships affiliated with USGen, as well as all or a portion of Bechtel's interests in various power projects affiliated with USGen. See "PG&E Corporation's Independent Power Generation Operations" below.
The following information includes forward-looking statements that involve a number of risks, uncertainties, and assumptions. Words such as "estimates," "expects," "intends," "anticipates," "plans," and similar expressions identify those statements which are forward-looking. A number of factors that could cause actual results to differ materially from those indicated in the forward- looking statements include, but are not limited to, the ongoing restructuring of the electric and gas industries and the outcome of regulatory proceedings related to that restructuring, and other factors which are described in more detail below. The ultimate impacts of both increased competition and the changing regulatory environment on future results are uncertain, but are expected to fundamentally change how PG&E Corporation's utility operations are conducted. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by PG&E Corporation.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.
Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies have challenged the utilities' exclusive relationship with their customers and have sought to replace certain utility functions with their own. Customers, too, have asked for choice in their energy provider. These pressures have caused a move from the existing regulatory framework to a framework under which competition is allowed in certain segments of the gas and electric industries.
For several years, Pacific Gas and Electric Company has been working with its regulators to achieve an orderly transition to competition and to ensure that the Company has an opportunity to recover investments made under traditional regulatory policies. Beginning in 1998, a significant portion of Pacific Gas and Electric Company's business will be transformed from the current utility monopoly to a competitive operation. During the transition period, the return on Diablo Canyon and certain other generation assets will be significantly lower than historical levels. See "Electric Utility Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. These changes will affect PG&E Corporation's financial results and may result in greater earnings volatility.
ELECTRIC INDUSTRY
In 1995, the CPUC issued a decision that provides a plan to restructure California's electric industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called transition costs, through a nonbypassable charge, called the competition transition charge or CTC, to be collected over a period of years.
In 1996, legislation adressing electric industry restructuring, Assembly Bill 1890 (AB 1890), was signed into law in California. AB 1890 adopts the basic tenets of the CPUC's restructuring decision and establishes the operating framework for a competitive electric generation market. Key features of AB 1890 include:
--mandatory unbundling of transmission, distribution, and generation services;
--formation of the PX to provide a competitive auction process to establish the price of electricity in California;
--establishment of the ISO to ensure system reliability and provide electric generators and energy service providers with open and comparable access to transmission services;
--an electric rate freeze at 1996 levels until the earlier of March 31, 2002, or when the particular utility has recovered its generation-related transition costs (the transition period);
--a 10% rate reduction on January 1, 1998, for residential and small commercial customers, financed through "rate reduction bonds;"
--nonbypassable charges (the competition transition charge or CTC) to provide the opportunity for utilities to recover their transition costs and accelerated recovery of transition costs associated with utility- owned generation facilities;
--direct access to competitive generation resources for all retail electric customers to start no later than January 1, 1998;
--market valuation for utility-owned fossil generation assets by 2001, followed by an end to cost-of-service ratemaking for most plants; and
--continued support for renewable generation resources, conservation, and other public purpose programs.
Under AB 1890, Pacific Gas and Electric Company and other utilities will continue to own transmission and distribution facilities and must continue to offer bundled electric service to customers who wish to continue receiving it. Although ownership of transmission facilities will be retained, utilities will relinquish control of the facilities to the ISO.
As required by AB 1890, electric rates were frozen on January 1, 1997 at 1996 levels, and on January 1, 1998, rates for residential and small commercial customers were reduced by 10% and will be held at the reduced level. The rate freeze will continue until the end of the transition period.
During 1997, the CPUC issued many decisions to establish the ratemaking and accounting mechanisms necessary to implement AB 1890. Many of the key features of AB 1890 were implemented by January 1, 1998, such as the rate freeze, the 10% rate reduction for residential and small commercial customers, formation of the ISO and PX, and commencement of the market valuation process. However, direct access for all retail electric customers has been delayed. In December 1997, the ISO and the PX announced that they were unable to commence operations on January 1, 1998, and that they expected to be operational by March 31, 1998, at which time direct access would begin. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below.
At the federal level, the ISO is regulated by the Federal Energy Regulatory Commission (FERC). In October 1997, the FERC granted conditional authority for the California ISO to commence operations and for the California PX to charge market-based rates for electricity. See "Electric Utility Operations--Electric Transmission" below.
Additional information concerning electric industry restructuring, the expected operating framework for a competitive generation market, and the financial impact of these changes on PG&E Corporation is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders.
GAS INDUSTRY
Restructuring of the natural gas industry on both the national and state levels has given customers greater options in meeting their gas supply needs. Currently, Pacific Gas and Electric Company's customers may buy gas directly from competing suppliers and purchase transmission- and distribution-only services from Pacific Gas and Electric Company. Pacific Gas and Electric Company's transmission and distribution services have historically been "bundled," or sold together at a combined rate, within California. Most of Pacific Gas and Electric Company's industrial and larger commercial (noncore) customers now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers buy gas as well as transmission and distribution services from Pacific Gas and Electric Company as a bundled service. Customer rates for gas are updated on a monthly basis in order to reflect changes in Pacific Gas and Electric Company's gas procurement costs.
In 1995 and 1996, Pacific Gas and Electric Company actively pursued changes in the California gas industry in an effort to promote competition and increase options for all customers, as well as to position the Company for the competitive marketplace. In 1996, Pacific Gas and Electric Company submitted to the CPUC the Gas Accord, a multi-party settlement agreement which resulted from an extensive negotiation process begun in 1995 among a broad coalition of customer groups and industry participants. On August 1, 1997, the CPUC unanimously approved the Gas Accord.
The Gas Accord separates, or "unbundles," Pacific Gas and Electric Company's gas transmission services from its distribution services and changes the terms of service and rate structure for gas transportation. Unbundling gives noncore customers the opportunity to select from a menu of services offered by Pacific Gas and Electric Company and enables them to pay only for the services they use. Unbundling also makes access to the transmission system possible for all gas marketers and shippers, as well as noncore end-users. As a result, the transmission system is now more accessible to a greater number of customers.
The Gas Accord increases opportunities for Pacific Gas and Electric Company's core customers to purchase gas from competing suppliers and, therefore, will reduce the Company's role in procuring gas for such customers. However, Pacific Gas and Electric Company will continue to procure gas as a regulated utility supplier for those customers who do not obtain gas supplies from an alternative provider.
Under the Gas Accord, the CPUC's traditional after-the-fact reasonableness review of Pacific Gas and Electric Company's core gas procurement costs for the period 1994 to 2002 are replaced by a core procurement incentive mechanism (CPIM), a form of incentive regulation. Under the CPIM, Pacific Gas and Electric Company is able to recover its gas commodity and interstate transportation costs and receives benefits or incurs penalties depending on whether its actual core procurement costs are within, below, or above a "tolerance band" constructed around market benchmarks. Actual core procurement costs measured for the period June 1, 1994, through December 31, 1997, have generally been within the CPIM "tolerance band."
The Gas Accord establishes gas transmission and storage rates for the period from March 1, 1998, through December 2002. During the Gas Accord period, Pacific Gas and Electric Company is at risk for revenue fluctuations resulting from variances in demand for noncore gas transmission throughput. Rates for distribution service continue to be set by the CPUC and are designed to provide the Company an opportunity to recover its costs of service and include a return on investment.
In January 1998, the CPUC opened a rule-making proceeding to expand market- oriented policies in the natural gas industry, including the further unbundling of services to promote competition, streamlining regulation for noncompetitive services, mitigating the potential for anti-competitive behavior, and establishing appropriate consumer protections. The CPUC will be studying various new alternative market structures for the California natural gas industry with the goal of encouraging competition and customer choice, while maintaining a high standard of consumer protection.
Additional information concerning gas industry restructuring, and the financial impact of these changes on PG&E Corporation, is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 24, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 46 of the 1997 Annual Report to Shareholders.
REGULATION OF PACIFIC GAS AND ELECTRIC COMPANY
STATE REGULATION
The CPUC consists of five members appointed by the Governor and confirmed by the State Senate for six-year terms. The CPUC regulates Pacific Gas and Electric Company's rates and conditions of service, sales of securities, dispositions of utility property, rate of return, rates of depreciation, uniform systems of accounts, long-term resource procurement, and transactions between Pacific Gas and Electric Company and its subsidiaries and affiliates. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition, and the environment, to determine its future policies.
The California Energy Commission (CEC) has the responsibility to make electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California. Under electric industry restructuring legislation, the CEC also administers funding for public purpose research and development, and renewable technologies programs. The funding will be collected from ratepayers through a nonbypassable public benefits charge. See "Electric Utility Operations-- Electric Industry Restructuring Legislation--Public Purpose Programs" below.
FEDERAL REGULATION
The FERC regulates electric transmission rates and access, compliance with the uniform systems of accounts, and electric contracts involving sales of electricity for resale. After the ISO and PX commence operations, the FERC will have jurisdiction over Pacific Gas and Electric Company's electric transmission revenue requirements and rates, which previously were included in CPUC-authorized bundled rates. The FERC also regulates the interstate transportation of natural gas. Further, most of Pacific Gas and Electric Company's hydroelectric facilities are subject to licenses issued by the FERC.
The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including Diablo Canyon. NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities.
LICENSES AND PERMITS
Pacific Gas and Electric Company obtains a number of permits, authorizations, and licenses in connection with the construction and operation of its generating plants and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, FERC hydroelectric facility licenses, and NRC licenses are the most significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements imposed by the granting agency.
REGULATION OF PG&E CORPORATION AND OTHER SUBSIDIARIES
PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding Company Act) on the basis that PG&E Corporation and Pacific Gas and Electric Company are incorporated in the same state and their business is predominantly intrastate in character and carried on substantially in the state of incorporation. At present, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing Pacific Gas and Electric Company to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that Pacific Gas and Electric Company is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, Pacific Gas and Electric Company's dividend policy shall continue to be established by Pacific Gas and Electric Company's Board of Directors as though Pacific Gas and Electric Company were a comparable stand-alone utility company, and the capital requirements of Pacific Gas and Electric Company, as determined to be necessary to meet Pacific Gas and Electric Company's service obligations, shall be given first priority by the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company. The conditions also provide that Pacific Gas and Electric Company shall maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition in the event an adverse financial event reduces the utility's equity ratio by 1% or more.
A further condition of the CPUC's approval of the holding company formation was that an audit of affiliate transactions from 1994 to 1996 be conducted and supervised by the CPUC's Office of Ratepayer Advocates (ORA). The audit report, completed in November 1997, was critical of Pacific Gas and Electric Company's affiliate transaction internal controls and compliance. The report contained numerous recommendations for additional conditions to be imposed on the holding company. Pacific Gas and Electric Company will be responding to the audit report, and the CPUC will hold hearings to determine if the additional recommended conditions should be imposed on the holding company. A final CPUC decision is expected in early 1999.
On December 16, 1997, the CPUC issued a decision that adopted rules governing transactions between California's natural gas local distribution and electric utility companies and their non-regulated affiliates. This decision permits non-regulated affiliates of regulated utilities (such as PG&E Energy Services Corporation, the non-regulated energy marketing subsidiary of PG&E Corporation) to compete in the affiliated utility's service territory. The decision permits non-regulated affiliates to use the same name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC.
The decision also adopts complex and detailed rules requiring the separation of regulated utilities and their non-regulated affiliates, through the maintenance of separate books and records, physical separation of facilities, and the separation of certain functions, such as energy-related purchases and sales, and marketing, among others. The decision also contains rules regarding disclosure and use of information among the affiliates and prohibits the utility from engaging in certain practices which would discriminate against energy service providers which compete with the utility's non-regulated affiliates. As required by the decision, Pacific Gas and Electric Company filed a comprehensive plan to comply with the affiliate transaction rules on December 31, 1997.
In addition to Pacific Gas and Electric Company, certain of PG&E Corporation's other subsidiaries which conduct interstate gas transmission and electric wholesale power marketing operations are subject to FERC jurisdiction. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce.
In addition, the power generation projects that USGen and its affiliates develop, manage or own, are subject to differing types of federal regulation depending on the regulatory status of the particular project. Some of these projects are exempt wholesale generators (EWG) under the National Energy Policy Act of 1992, which status exempts the project from the Public Utility Holding Company Act of 1935. EWG status is granted by FERC upon application by the project. Some projects have received authority from FERC to charge market-
based rates for the power they sell, rather than traditional cost-based rates. Many of USGen's affiliated projects are qualifying facilities (QF) under the Public Utility Regulatory Policies Act of 1978. QF status exempts the project from regulation under various federal and state laws concerning the electric industry. USGen's projects are also subject to various federal, state, and local regulations concerning siting and environmental matters.
The Railroad Commission of Texas (RRC) regulates gas utilities including those owned by PG&E Corporation through PG&E Gas Transmission, Texas Corporation, PG&E Gas Transmission Teco, Inc., and other affiliates operating in Texas. The RRC gas proration rules govern the wellhead production and purchase of gas. Intrastate pipelines can provide intrastate gas transportation at negotiated rates which are presumed just and reasonable. If the criteria for negotiated rates cannot be met, the RRC may assess a cost-of- service-based rate. The RRC may also regulate certain sales of gas. Currently, the price of natural gas sold under a majority of PG&E Gas Transmission, Texas Corporation's gas sales contracts is not regulated by the RRC. All transportation and gathering of gas is subject to the RRC Code of Conduct which prohibits undue discrimination among similarly situated shippers. Further, all transportation of gas, processing of gas, and transportation of natural gas liquids are subject to safety regulations enforced by the RRC and the Texas Natural Resource Conservation Commission.
Other regulatory matters are described throughout this report.
PACIFIC GAS AND ELECTRIC COMPANY RATE MATTERS
CALIFORNIA RATEMAKING MECHANISMS
The CPUC authorizes an amount, known as "base revenues," to be collected from ratepayers to recover Pacific Gas and Electric Company's basic business and operational costs for its gas and electric operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, are currently authorized by the CPUC in general rate case (GRC) proceedings before the CPUC. Pacific Gas and Electric Company's next scheduled GRC will establish base revenues effective January 1, 1999.
During the GRC, which occurs every three years, the CPUC examines Pacific Gas and Electric Company's costs and operations to determine the amount of base revenue requirement Pacific Gas and Electric Company is authorized to collect from customers through base revenues. The revenue requirement is forecasted on the basis of a specified test year. (The return component of Pacific Gas and Electric Company's revenue requirement is computed using the overall cost of capital authorized in other proceedings.) Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase, which allocates revenue requirements and establishes rate levels for the different classes of customers.
On December 12, 1997, Pacific Gas and Electric Company filed its Test Year 1999 GRC application with the CPUC, requesting increases in electric and gas base revenues of $693 million and $501 million, respectively, over base revenues authorized in 1997. The requested increase in base revenues reflects increasing levels of electric and gas demand as well as customer growth in the service territory, the costs of continued and enhanced maintenance activities, and increased capital expenditures. If granted by the CPUC, the requested increase would be effective January 1, 1999.
The requested increase of $693 million in electric base revenues as compared to 1997 will not increase customer electric rates because these rates will continue to be frozen. Under the frozen electric rates, the portion of total actual revenue which exceeds authorized base revenues and certain other authorized revenue requirements is available to recover transition costs. Therefore, increases in base revenues would reduce the amount of revenue available to recover transition costs.
The GRC electric revenue request includes proposed funding for distribution services, including system reliability and safety projects, increased distribution capacity (poles, wires, substations, etc.), equipment inspection
and maintenance, a continuation of tree-trimming programs, and enhanced customer service and information technology systems. Since the FERC will authorize the rates to be collected from customers for electric transmission services once direct access begins, the GRC application does not seek approval of base revenues to recover the cost of transmission services. The requested increase in electric base revenues is in addition to increases for system safety and reliability provided by AB 1890, as discussed in "1998 Revenues" below.
Gas customers would experience an increase in gas distribution rates if the CPUC approves the requested gas base revenue increase. The GRC gas base revenue request includes proposed funding for distribution system safety and reliability improvements, increased depreciation costs of the gas pipeline system, expanded customer service, and expanded customer and other information systems. The requested increase in gas base revenues will not result in an increase in customer gas transmission and storage rates, since the Gas Accord has set gas transmission and storage rates for the period from implementation of the Gas Accord through December 2002.
ELECTRIC RATEMAKING
In 1996, the CPUC issued a "roadmap" decision outlining the necessary steps to accomplish electric industry restructuring. During 1997, the CPUC issued many decisions to implement AB 1890 and the new market structure beginning in 1998, including decisions related to unbundling of rates, transition costs, performance based ratemaking (PBR), and other activities that affect rates and revenue requirements.
In its roadmap decision, the CPUC established a separate annual proceeding to consider ratemaking issues related to each electric utility's revenues, which will consolidate all pending revenue changes and track utility revenues at present rate levels for the purpose of comparison with authorized amounts. Beginning in 1998, this annual Revenue Adjustment Proceeding (RAP) will review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and will make any necessary adjustments or updates due to authorized revenues for alternative ratemaking mechanisms, various power purchase contracts, public purpose programs, nuclear facilities, nuclear decommissioning, transition costs, and other proceedings.
Pacific Gas and Electric Company has filed numerous regulatory applications and proposals that detail its transition cost recovery plan during the transition period. Pacific Gas and Electric Company's recovery plan includes (1) separating or unbundling of its previously approved cost-of-service revenue requirement for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) determining revenues available to recover transition costs, and (3) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period.
In August 1997, the CPUC adopted Pacific Gas and Electric Company's proposed unbundling of its 1998 authorized electric revenue requirements with some exceptions. The decision enables Pacific Gas and Electric Company to separate revenues provided by frozen rates into transmission, distribution, PPPs, and generation based upon their respective costs of service. The generation category includes energy costs, generation operating costs, nuclear decommissioning costs, and transition costs. When direct access begins, bills for all customers will describe what portion of the bill is attributable to transmission, distribution, PPPs, energy, and transition costs and other nonbypassable charges.
Under the restructuring legislation, most transition costs must be recovered by March 31, 2002. The CPUC believes that the shorter amortization period reduces risks associated with recovery of generation facilities, including Diablo Canyon. As a result, in November 1997 (but retroactive to July 28, 1997), the CPUC reduced the authorized rate of return on common equity for Pacific Gas and Electric Company's non-nuclear electric generation-related assets including hydroelectric and geothermal facilities, to 90% of the Company's embedded cost of debt, for a reduced rate of return on common equity equal to 6.77%, as compared to the previously authorized 1997 rate of return on common equity of 11.6%. Effective January 1, 1997, the rate of return on common equity on Diablo Canyon was reduced to 90% of Pacific Gas and Electric Company's embedded cost of long-term debt, for a return on common equity of 6.77%. See "Electric Utility Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. The reduced rate of return for the Company's non-nuclear electric generation-related assets and for Diablo Canyon will be in effect for the duration of the transition period.
Before 1998, the Electric Revenue Adjustment Mechanism (ERAM) allowed rate adjustments to offset the effect on base revenues of differences between actual electric sales volumes and the forecasted volumes used to set electric rates. The ERAM eliminated the impact on earnings of sales fluctuations, including those resulting from conservation and weather conditions. Base revenue differences resulting from the disparity between actual and forecasted electric sales accumulated in a balancing account, with interest. In connection with electric industry restructuring, the CPUC eliminated the ERAM effective January 1, 1998. Until direct access begins, ERAM-related revenues will be recorded in a separate memorandum account established in connection with the delay of direct access.
Before 1998, most of Pacific Gas and Electric Company's fuel, purchased- power, and energy-related costs of providing electric service, as well as revenues attributable to Diablo Canyon generation, were recovered through a balancing account mechanism called the Energy Cost Adjustment Clause (ECAC). Under the ECAC balancing account procedure, actual costs were compared with revenues designated for recovery of such costs, and the difference was recorded as either an undercollection or overcollection. In prior years, rates would be adjusted such that the amount of overcollections would be returned to ratepayers through lower rates and undercollections would be recovered through higher rates. However, as part of the electric industry restructuring, the CPUC eliminated the ECAC balancing account effective January 1, 1998.
In December 1996, the CPUC issued a decision establishing an electric deferred refund account (EDRA). The CPUC ordered Pacific Gas and Electric Company to place into the EDRA credits for CPUC-ordered electric disallowances, the utility electric generation share of CPUC-ordered gas disallowances, amounts resulting from reasonableness disputes, and fuel- related cost refunds made to Pacific Gas and Electric Company based on regulatory agency decisions, plus interest charges. The CPUC ordered Pacific Gas and Electric Company to file advice letters by January 31 of each year, setting forth its annual refund plans for directly refunding to electric customers the amounts accumulated in the EDRA. The CPUC also ordered Pacific Gas and Electric Company to include initially in the EDRA any such credits already recorded in ECAC and ERAM but not yet amortized in rates. The effect of this was to reduce the amount available to offset Pacific Gas and Electric Company's transition costs by approximately $75 million. In February 1998, Pacific Gas and Electric Company refunded approximately $61 million of EDRA funds to customers.
The ISO will designate certain electric generation facilities as necessary to remain available and operational to maintain the reliability of the electric transmission system. These facilities are called "must-run" facilities. In general, sunk costs and on-going operating costs of must-run facilities are recoverable through different types of FERC-authorized contracts between must-run facilities and the ISO and, in some cases, also through PX revenues. For an initial three-month period, all must-run facilities will be under the same type of contract. Thereafter, the type of contract for a particular must-run facility may change based upon the ISO's evaluation of facility operating factors and system reliability needs. Subject to CPUC approval, the type of contract and generation (i.e., fossil, hydroelectric, or geothermal) will determine whether (1) all of the facility's sunk costs and ongoing operating costs are eligible for transition cost recovery, (2) the portion of the facility's sunk costs and ongoing operating costs, which are not recovered through ISO or PX revenues, are eligible for transition cost recovery, (3) differences between authorized and actual revenues for the facility will be included in the transition cost recovery mechanism, and (4) the facility may participate in the PX.
In December 1997, the CPUC adopted a cost-of-service based ratemaking mechanism for determining Pacific Gas and Electric Company's revenue requirement for its hydroelectric and geothermal generation facilities. Under this mechanism, the revenue requirements for these facilities (including the Helms pumped storage facility) will be calculated as the sum of the capital- related revenue requirement (based on recorded capital costs), the expense revenue requirement (based on the current General Rate Case adopted expenses), and actual fuel expenses. A reduced rate of return on common equity of 6.77% will apply to these facilities. This alternative revenue requirement mechanism will be in place through 2001, unless the CPUC determines otherwise.
Additional information concerning Pacific Gas and Electric Company's transition cost recovery plan, and the financial impact of electric industry restructuring is provided in "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders.
GAS RATEMAKING
As noted above (see "Competition and the Changing Regulatory Environment-- Gas Industry"), the CPUC approved the Gas Accord in 1997. Additional information concerning the potential financial impact of the Gas Accord is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 24, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 46 of the 1997 Annual Report to Shareholders.
As part of the Gas Accord, the CPUC's traditional reasonableness reviews of Pacific Gas and Electric Company's core gas costs have been be replaced with a CPIM (which is also discussed above in "Competition and the Changing Regulatory Environment-Gas Industry") for the period June 1, 1994, through 2002.
The Biennial Cost Allocation Proceeding (BCAP) remains the proceeding in which distribution costs and balancing account balances are allocated to customers. The BCAP normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. Balancing accounts for natural gas costs accumulate differences between the actual recovery of gas costs and the revenues designed for recovery of such costs. Balancing accounts for sales volumes accumulate differences between authorized and actual base revenues.
In 1997, the CPUC also authorized Pacific Gas and Electric Company to set its natural gas rates for core customers each month rather than annually. Because Pacific Gas and Electric Company's gas costs are passed through to customers, this change will better align customer prices with actual gas costs.
1998 REVENUES
Under frozen rates, any change in Pacific Gas and Electric Company's electric revenue requirements resulting from the items discussed below will not change electric customer rates. Decreases in electric revenue requirements will increase revenue from frozen rates available for collection from customers as the competition transition charge (CTC) for recovery of transition costs. Conversely, increases in electric revenue requirements will decrease revenue from frozen rates available for collection from customers as CTC for recovery of transition costs.
AB 1890-Electric Base Revenue Increase. AB 1890 provides for an increase in Pacific Gas and Electric Company's electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. In January 1998, the CPUC authorized a 1998 base revenue increase of $86 million in addition to the 1997 authorized base revenue increase of $164 million.
Recovery of Transition Costs. In June 1997, the CPUC issued a decision adopting CTC ratemaking and accounting mechanisms to enable the utilities to measure their transition costs and track the recovery of transition costs. Revenues collected under frozen electric rates will be allocated to distribution, transmission, and generation services and PPPs based upon their respective cost-of-service, and to nuclear decommissioning, rate reduction bond debt service (for residential and small commercial customers), and transition cost recovery at levels authorized by the CPUC.
Elimination of ECAC and ERAM. Effective January 1, 1998, the ECAC and ERAM balancing accounts were eliminated and the December 31, 1997, balances in these accounts were transferred to the Interim Transition Cost Balancing Account (ITCBA). The ECAC was undercollected by $468 million, and the ERAM was overcollected by $309 million. On January 1, 1998, the ITCBA balance of $160 million undercollection was transferred to the Transition Cost Balancing Account (TCBA). Until direct access begins, fuel and fuel-related costs which would otherwise have been included in an ECAC adjustment will be recorded in a memorandum account to be later transferred to the ITCBA. Costs recorded in the ITCBA are subject to a subsequent
reasonableness review, in which the CPUC determines whether those costs were reasonably incurred. Costs found to be unreasonable may be disallowed, or deducted, from the amount to be recovered in rates. When direct access begins, costs will be recovered from the market price, the TCBA, the Transition Revenue Account (TRA), or any other cost recovery mechanism approved by the CPUC.
Cost of Capital. The CPUC's decision in the 1998 Cost of Capital proceeding authorized a utility return on common equity of 11.20%, a decrease from the 1997 level of 11.60%. The decision authorizes a utility capital structure for Pacific Gas and Electric Company of 48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. The combined authorized costs of debt, preferred stock, and the 11.20% return on common equity result in an overall return on utility rate base of 9.17%, a decrease from the 9.45% authorized for 1997. Since (i) the CPUC separately reduced the rate of return on Pacific Gas and Electric Company generation-related assets including Diablo Canyon, (ii) the FERC will authorize the rate of return for electric transmission assets at a later date, and (iii) transmission and storage rates have been set in the Gas Accord, the reduced rate of return of 11.20% adopted in the 1998 Cost of Capital Proceeding only applies to Pacific Gas and Electric Company's electric and gas distribution assets. The authorized cost of capital will decrease 1998 authorized electric and gas revenue by $25 million and $9 million, respectively. Pacific Gas and Electric Company has requested a rehearing of this decision.
BCAP. In 1997, Pacific Gas and Electric Company filed its 1998 BCAP application. The Company is requesting an overall annual revenue requirement for the two-year BCAP period of approximately $1.5 billion of which approximately $107 million will be allocated for the collection of balancing accounts. The current annual revenue requirement is approximately $1.8 billion of which approximately $303 million has been allocated for the collection of balancing accounts. No rate changes resulting from the BCAP are expected to be implemented before August 1, 1998.
AEAP. The 1997 Annual Earnings Assessment Proceeding (AEAP), which determines shareholder incentives earned for Pacific Gas and Electric Company's demand side management (DSM) programs, was submitted in December 1997. All of the parties to the proceeding agree that Pacific Gas and Electric Company is entitled to an incentive payment of approximately $32 million for Pacific Gas and Electric Company's 1996 DSM programs, to be collected in installments over a 10-year period. After consolidating the adjusted incentive payment installments from prior years, the net revenue change in 1998 from DSM shareholder incentives should be an electric decrease of approximately $4 million and a gas decrease of approximately $2 million. A CPUC decision adopting the shareholder incentives is expected during the first quarter of 1998.
Electric Transmission Revenues. Prior to 1998, most electric transmission revenues were authorized by the CPUC as part of the GRC. In 1998, electric transmission revenues are expected to be authorized by the FERC. In 1997, Pacific Gas and Electric Company filed an application with the FERC requesting electric transmission revenues of $305 million. This requested revenue requirement is comparable to electric transmission revenues in CPUC-authorized 1997 electric rates.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
PG&E Corporation and Pacific Gas and Electric Company continue to require capital for improvements to facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. PG&E Corporation's expenditures for these purposes, including the allowance for funds used during construction (AFUDC), were approximately $1,829 million for 1997. New investments totaled $41 million in 1997.
The following table sets forth PG&E Corporation's estimated total capital requirements, consisting of capital expenditures for Pacific Gas and Electric Company's utility functions, including Diablo Canyon, as well as capital requirements for PG&E Corporation's other lines of business, and amounts for maturing debt and sinking funds for the years 1998 through 2000. These are forward-looking statements which involve a number of assumptions and uncertainties. Actual amounts may differ materially from the estimated amounts shown below.
PG&E CORPORATION CAPITAL REQUIREMENTS (IN MILLIONS)
- -------- (1) Utility expenditures including Pacific Gas and Electric Company's electric and gas operations, are shown net of reimbursed capital, and include AFUDC. (2) Other expenditures include those of PG&E GT, PG&E ES, PG&E ET, and USGen. In August 1997, PG&E Corporation announced plans to acquire, through USGen, a portfolio of electric generating assets and power supply contracts from the New England Electric System for $1.59 billion. Including fuel and other inventories and transaction costs, financing requirements are expected to total approximately $1.75 billion, which amount is included in the table above.
Most of the capital expenditures for Pacific Gas and Electric Company for 1998 through 2000 are associated with short lead time, capital expenditure projects aimed at the replacement and enhancement of existing facilities, and compliance with environmental laws and regulations. Also included are expenditures to improve the safety and reliability of Pacific Gas and Electric Company's electric transmission and distribution system consistent with AB 1890, as well as major projects associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years 1998 through 2000 will include approximately $2 billion for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt, as indicated above.
The funds necessary for 1998-2000 capital requirements of PG&E Corporation and its subsidiaries will be obtained from (i) internal sources, principally net income before noncash charges for depreciation and deferred income taxes, and (ii) external sources, including short-term financing, such as bank loans and the sale of short-term notes, and long-term financing, such as sales of equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing review of their capital expenditures and financing programs. The programs and estimates above are subject to revision and actual amounts may vary based upon changes in assumptions as to system load growth, rates of inflation, receipt of adequate and timely rate relief, availability and timing of regulatory approvals, total cost of major projects, availability and cost of suitable nonregulated investments, and availability and cost of external sources of capital, as well as the outcome of the ongoing restructuring in both the electric and gas industries.
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for approximately $378 million, consisting of the purchase of a $61 million note, and $317 million of PG&E Corporation common stock. On July 31, 1997, PG&E Corporation acquired Valero's natural gas and natural gas liquids business. In the Valero acquisition, approximately 31 million shares of PG&E Corporation common stock were issued and approximately $780 million in long term debt was assumed.
PRICE RISK MANAGEMENT PROGRAMS
PG&E Corporation established an officer-level price risk management committee, and adopted a price risk management policy approved by the PG&E Corporation Board of Directors, for trading and risk management activities. The price risk management committee oversees implementation of the policy, approves the trading and price risk management policies of subsidiaries, and monitors compliance with the policy.
The price risk management policy allows derivatives to be used for both hedging and non-hedging purposes. (A derivative is a contract whose value is dependent on or derived from the value of some underlying asset.) PG&E Corporation uses derivatives for hedging purposes primarily to offset underlying commodity price risks. PG&E Corporation also participates in markets using derivatives to create liquidity, and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. The price risk management policy and the trading and risk management policies of PG&E Corporation's subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset.
In 1997, PG&E Corporation approved and implemented trading and risk management policies for PG&E ET, and continued to seek approval from the CPUC to manage commodity price risks in Pacific Gas and Electric Company's business.
The fair value of the market risk sensitive instruments (which includes the hedging and non-hedging instruments described above) as of December 31, 1997, is immaterial for financial instruments subject to commodity price risk. Additionally, as of December 31, 1997, PG&E Corporation calculated value-at- risk based on a 95 percent confidence level using five-day holding periods. Using this methodology, the potential for near-term losses in future earnings, fair values, and cash flows from reasonably possible near-term changes in market prices for financial instruments subject to commodity price risk is immaterial.
PG&E Corporation anticipates an increase in the level of trading and risk management activity in 1998 due to expected growth in its national energy businesses and a continuing effort to manage anticipated price risks in Pacific Gas and Electric Company's business. Pacific Gas and Electric Company manages price risk independently from the activities of PG&E Corporation's other subsidiaries.
ELECTRIC UTILITY OPERATIONS
ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION
In 1997, the relevant regulatory authorities took steps to implement AB 1890, including establishing the ISO and PX, and implementing direct access. AB 1890 also provides for the financing of the 10 percent rate reduction through rate reduction bonds, recovery of transition costs, and the funding of public purpose programs.
INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE
AB 1890 requires the CPUC to facilitate the development of an ISO and a PX, and establishes a five-member Oversight Board to oversee the ISO and PX and appoint the members of the ISO and PX Governing Boards. In May 1997, the ISO and PX were formed as California non-profit corporations. The ISO and PX Governing Boards include representatives of investor-owned utility transmission systems, publicly owned utility transmission systems, non-utility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives. In March 1997, the trustee for the development of the ISO and PX, filed the documents with FERC that explained the structure, rates, terms and conditions applicable to the new market structure. While those documents have been subsequently revised and clarified in more recent filings by the duly constituted governing boards of the ISO and PX, on October 30, 1997, the FERC granted conditional authority for the ISO to begin operations and for the PX to charge market-based rates for electricity.
Under AB 1890, it is intended that both California's investor-owned utilities and its publicly owned utilities relinquish control, but not ownership, of their transmission facilities to the ISO. The ISO is required to ensure reliable transmission services consistent with planning and operating reserve criteria no less stringent than those established by the Western Systems Coordinating Council and the North American Electric Reliability Council. Oversight responsibility for reliability of utility distribution systems remains with the CPUC. In December 1997, the ISO announced a delay of its operations and its formal assumption of control of the utilities' transmission systems. The PX also announced a delay in the commencement of its operations. Both the ISO and the PX announced that they expected to begin operations by March 31, 1998, at which time direct access will begin. The FERC requires that it be given at least 15 days notice before ISO and PX operations commence.
VOLUNTARY GENERATION ASSET DIVESTITURE
In 1997, California utilities produced a significant portion of the state's electric generation needs. In a competitive market, the CPUC is concerned that this level of generation may give existing utilities undue influence on the PX price. To alleviate this concern, Pacific Gas and Electric Company has indicated that it is willing to proceed with voluntary economic divestiture of at least 98% of its fossil-fueled power plants and all of its geothermal facilities. In December 1997, the CPUC approved Pacific Gas and Electric Company's sale of three electric generating plants with a combined capacity of 2,645 megawatts (MW) to Duke Energy Power Services, Inc. (Duke Energy) in Pacific Gas and Electric Company's first power plant auction. The aggregate bid was $501 million for these three fossil-fueled plants: the Morro Bay Power Plant located in San Luis Obispo County, the Moss Landing Power Plant located in Monterey County, and the Oakland Power Plant located in Alameda County. The combined book value for these three fossil-fueled plants is approximately $370 million as of December 31, 1997. Pacific Gas and Electric Company will retain liability for required environmental remediation of any preclosing soil or groundwater contamination at these plants. Subject to various conditions, including regulatory approval of the transfer of various permits and licenses, and the commencement of direct access, Pacific Gas and Electric Company expects the sale to close in 1998.
In 1997 Pacific Gas and Electric Company announced plans to conduct the second auction of four of its five remaining fossil-fueled power plants (the Hunters Point and Potrero Power Plants, both located in San Francisco County, and the Contra Costa and Pittsburg Power Plants, both located in Contra Costa County) and all of its geothermal facilities (The Geysers located in Lake and Sonoma counties) in 1998, subject to CPUC approval. These
plants have a combined generating capacity of 4,718 MW and a combined book value at December 31, 1997 of approximately $790 million. In January 1998, Pacific Gas and Electric Company filed its application to seek CPUC approval for the sale of these plants. In its application, Pacific Gas and Electric Company indicated that the auction for these plants would begin on March 16, 1998.
Together, the eight power plants represent 98% of Pacific Gas and Electric Company's fossil-fueled generating capacity and all of its geothermal generating capacity. The facilities generate approximately 22% of Pacific Gas and Electric Company's total electric energy sold to customers. Pacific Gas and Electric Company is evaluating its options related to its remaining generation facilities and may decide not to retain its economic investments in those facilities. Any gain from the sale of power plants would be used to offset Pacific Gas and Electric Company's transition costs.
As required by the California electric industry restructuring legislation, Pacific Gas and Electric Company employees will continue to operate and maintain the power plants that are sold under a two-year operations and maintenance agreement with the new owner. To the extent that payments to Pacific Gas and Electric Company under these agreements exceed the Company's cost of operating the plants, the Company would offset other transition costs. Conversely, to the extent Pacific Gas and Electric Company's operating costs exceed the revenues from these agreements, the Company would have lower earnings.
DIRECT ACCESS
AB 1890 authorizes direct transactions between electricity suppliers and customers, beginning January 1, 1998. As described above, direct access has been delayed due to the delay in the start of operations of the ISO and PX. The ISO and PX expect to commence operations by March 31, 1998.
In May 1997, the CPUC issued a decision which authorizes full implementation of direct access for all electric customers. In October 1997, the CPUC approved implementing tariffs, rate schedules, and service agreements. Customers participating in direct access would purchase their electric power directly either through (1) competing non-utility retail electric providers such as brokers, marketers, aggregators, or other retailers, or (2) direct negotiated contracts with electric generators. All customers (with limited exceptions), whether they choose direct access or not, must pay the nonbypassable CTC, which will be collected by their distribution utility in connection with recovery of the utilities' transition costs. Utilities began accepting requests for direct access in November 1997, to become effective after direct access begins. As of February 19, 1998 Pacific Gas and Electric Company had accepted over 11,781 direct access requests. The CPUC requires that electric customers with an electricity demand, or load, of 50 kilowatts (kW) or more must have meters that are capable of providing hourly data in order to participate in direct access. Those customers with a load less than 50 kW may participate in direct access either through "load profiling" or by installing an hourly meter. (Load profiling approximates the pattern of electricity usage for a given customer class.) The customer will be responsible for the cost of the meter and the meter installation.
Also in May 1997, the CPUC issued a decision addressing the separation, or unbundling, of utility revenue cycle services, which include metering and billing. Under this decision, when direct access begins, energy service providers supplying the direct access market will be able to choose one of three billing options: (1) consolidated energy supplier billing, under which the utility would bill the energy supplier for the services provided directly by the utility to the customer and the supplier, in turn, would provide a consolidated bill to the customer; (2) Consolidated distribution company billing, under which the utility would place the supplier's energy charge on a distribution bill; or (3) dual billing, under which the energy supplier and the utility would bill separately for their own services. In December 1997, the CPUC adopted procedures and standards for non-utility performance of unbundled metering and meter data management services. Beginning January 1, 1998, energy service providers have been allowed to provide metering services to their customers with a demand greater than 20 kW, and beginning January 1, 1999, energy service providers may provide metering to all of their customers.
RATE LEVELS AND RATE REDUCTION BONDS
To achieve the 10% rate reduction for residential and eligible small commercial customers, effective January 1, 1998, AB 1890 authorized utilities to finance a portion of their transition costs with "rate reduction bonds." On December 8, 1997, a special purpose entity established by the California Infrastructure and Economic Development Bank issued $2.9 billion of rate reduction bonds on behalf of a wholly owned subsidiary of Pacific Gas and Electric Company. The bonds were issued in eight classes with maturities ranging from ten months to ten years, and bearing interest at rates ranging from 5.94% to 6.48%. Pacific Gas and Electric Company will collect a separate nonbypassable charge on behalf of the bondholders to recover principal, interest, and related costs over the life of the bonds from residential and small commercial customers. The bond proceeds were used by the wholly owned subsidiary to purchase from Pacific Gas and Electric Company the right to be paid the revenues from this separate charge. The bonds are secured by the future revenue from the separate charge and not by Pacific Gas and Electric Company's assets. While the bonds are reflected as long-term debt on Pacific Gas and Electric Company's balance sheet, creditors of Pacific Gas and Electric Company do not have any recourse to the revenues from the separate charge.
Various consumer groups filed a voter initiative with the California Attorney General which seeks among other things, to (i) require investor-owned California utilities to provide an additional 10% rate reduction to residential and small commercial customers; (ii) eliminate transition cost recovery for nuclear investments by utilities (other than reasonable decommissioning costs); (iii) restrict transition cost recovery for non- nuclear investments (other than costs associated with QFs), unless the CPUC finds that the utility would be deprived of the opportunity to earn a fair rate of return; (iv) and prohibit the collection of any customer charges for rate reduction bonds, or alternatively, require the utility to offset such charges with an equal credit to customers. In February 1998, the California Secretary of State released the title and summary prepared for the proposed initiative by the California Attorney General's office. The sponsors of the initiative are now seeking sufficient signatures to qualify the initiative for the November 1998, statewide ballot. If the proposed initiative were voted into law, costly and time-consuming litigation may ensue. The Company believes that under applicable federal and state constitutional principles relating to the impairment of contracts, the State of California through such an initiative, could not repeal or amend the Company's authorization to collect principal, interest, and related costs for the rate reduction bonds if such repeal or amendment would substantially impair the rights of the bondholders.
RECOVERY OF TRANSITION COSTS
AB 1890 authorizes utilities to recover their transition costs--the utilities' costs of their generation-related assets and obligations which prove to be uneconomic in the new competitive framework. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above- market sunk costs (sunk costs are costs associated with utility generating facilities that are fixed and unavoidable and currently included in customer rates), and future sunk costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from QFs and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods). Transition costs are eligible for recovery from all customers (with certain exceptions) through a nonbypassable competition transition charge or CTC included as part of rates. Transition costs that are disallowed by the CPUC for collection from customers will be written off.
As a prerequisite to any consumer obtaining direct access services, the consumer must agree to pay its applicable nonbypassable CTC. Further, nuclear decommissioning costs are being recovered through a separate CPUC-authorized charge. Most transition costs must be recovered by March 31, 2002, although certain transition costs may be recovered after March 31, 2002. These costs include certain employee-related transition costs, costs
that are unrecovered as result of the implementation of direct access and creation of the PX and ISO, and above-market costs associated with power- purchase agreements. In addition, costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds.
The total amount of sunk costs to be included as transition costs will be based on the aggregate of above-market and below-market values of utility- owned generation assets and obligations. Under AB 1890, valuation of generation-related assets through appraisal or sale must be completed by December 31, 2001. In 1997, the value of three of Pacific Gas and Electric Company's electric facilities was established through the auction process. Pacific Gas and Electric Company has also announced plans to conduct the second auction of four of its five remaining fossil-fueled power plants and its geothermal facilities in 1998, subject to CPUC approval.
In September 1997, the CPUC adopted a decision addressing transition cost recovery for capital additions to Pacific Gas and Electric Company's non- nuclear generating facilities. The decision allows Pacific Gas and Electric Company to recover costs of capital additions made in 1996 and 1997 (and in 1998 for fossil-fueled plants completely divested by March 31, 1998) based upon an after-the-fact reasonableness review. All capital additions found reasonable by the CPUC through this process will be recoverable as transition costs. Capital additions made in 1998 and thereafter to non-nuclear generation-related assets and capital additions made to fossil-fueled generating assets which are not completely divested by March 31, 1998, must be recovered either through revenues from the ISO agreements for "must-run" plants or from sales of electricity to the PX. The CPUC decision allows Pacific Gas and Electric Company to seek an after-the-fact reasonableness review of post 1997 capital addition expenditures for collection as transition costs in certain limited circumstances.
In November and December 1997, the CPUC issued two decisions confirming the eligibility of Pacific Gas and Electric Company's various categories of non- nuclear generation-related costs for accelerated recovery as transition costs and adopting tariffs associated with enforcement of the nonbypassable CTC. The CPUC reduced the authorized rate of return on common equity to 6.77% for all Pacific Gas and Electric Company's non-nuclear generation-related assets, including hydroelectric and geothermal facilities, for a total rate of return of 7.13% for these assets. The reduced rate of return was retroactive to July 28, 1997, and will be effective for the duration of the transition period.
The CPUC has ordered the utilities to file applications by June 1, 1998, to request recovery of transition costs in 1999. The annual transition cost proceeding will be used to develop a record to establish the guidelines for computing the transition costs on an ongoing basis and a mechanism for tracking the amount of transition costs and revenues recovered each year for the nuclear facilities based on actual recorded data. This proceeding will establish the reasonableness of accelerating recovery of transition costs and of estimating the market value of the assets subject to market valuation, and review actual employee transition costs, review all costs and revenues related to the PX and ISO revenues, and transition cost balancing account entries. In February 1998, Pacific Gas and Electric Company, along with the other California utilities, requested that the June 1, 1998, filing date be postponed to September 1, 1998, to reflect the delay of the commencement of direct access.
PUBLIC PURPOSE PROGRAMS
On January 1, 1998, and continuing through December 31, 2001, energy efficiency, research and development, and low-income programs are being funded through a separate nonbypassable charge included in frozen electric rates, in compliance with AB 1890. Low-income programs are funded at the level of need, but are not to be funded at less than the 1996 level of expenditures. Under this provision of AB 1890, Pacific Gas and Electric Company is obligated to fund through electric rates energy efficiency and conservation programs in an amount not less than $106 million per year, public interest research and development programs at not less than $30 million per year, renewable technologies at not less than $48 million per year, low-income energy efficiency programs at not less than $14 million per year, and the low-income rate discount program at approximately $38 million per year.
In February 1997, the CPUC adopted a decision that turns over administration of the funding for public interest research and development, and renewable technologies programs to the CEC, beginning January 1, 1998.
The decision also changed the way some programs are administered. Before 1998, Pacific Gas and Electric Company and other utilities administered public purpose programs for energy efficiency and conservation, and low-income customer assistance. Under the CPUC's decision, the CPUC will appoint independent boards to oversee energy efficiency and low-income assistance programs. These boards will solicit competitive bids to determine who will administer the programs from January 1, 1998, through 2001. In December 1997, the CPUC approved Pacific Gas and Electric Company's continuing to act as interim administrator of energy efficiency programs until October 1, 1998. Thereafter, an open-bidding process is expected to be completed to select energy efficiency program administrators.
Additional information concerning AB 1890 and its financial impact on PG&E Corporation is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders.
ELECTRIC OPERATING STATISTICS
The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
- -------- (1) Includes energy supplied through Pacific Gas and Electric Company's system by the City and County of San Francisco for San Francisco's own use and for sale by San Francisco to its customers, by the Department of Energy for government use and sale to its customers, and by the State of California for California Water Project pumping, as well as energy supplied by QFs and purchases from other utilities. (2) Includes energy output from Modesto and Turlock Irrigation Districts' own resources. (3) Represents energy required for pumping operations. (4) Includes use by business units other than the electric utility business units.
- -------- (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 described above in "Electric Industry Restructuring Legislation-- Voluntary Generation Asset Divestiture," in 1997, Pacific Gas and Electric Company entered into an agreement for the sale of three fossil-fueled power plants and announced plans to sell an additional four fossil-fueled power plants and its geothermal facilities. As of December 31, 1997, Pacific Gas and Electric Company owned and operated the following generating plants, all located in California, listed by energy source:
- -------- (1) In 1997, Pacific Gas and Electric Company announced plans to sell these power plants and its geothermal facilities in connection with electric industry restructuring. (2) In 1997, Pacific Gas and Electric Company entered into an agreement to sell these power plants in connection with electric industry restructuring. (3) Listed to show capability; subject to relocation within the system as required. (4) The Geysers Power Plant net operating capacity is based on adequate geothermal steam supply conditions. Any decrease in capacity, at peak, is included as unavailable capacity in the control area net capacity table below.
The following table sets forth the available capacity for the control area (the area served by Pacific Gas and Electric Company and various publicly owned systems in Northern California) at the date of peak (including reduction for scheduled and forced outages and based on actual water conditions) by various sources of generation available to the control area and the total amount of generation provided by these sources during the year ended December 31, 1997.
- -------- (1) The maximum control area peak demand to date was 21,862,000 kW which occurred in August 1997. (2) The reserve capacity margin at the time of the 1996 control area peak, taking into account short-term firm capacity purchases from utilities located outside Pacific Gas and Electric Company's service area: Pacific Gas and Electric Company's load responsibility for spinning reserve (capability already connected to the system and ready to meet instantaneous changes in demand) to the control area peak was 6.4% of the peak demand and total reserve (spinning reserve and capability available within a short period of time) was 7.4%. (3) Represents actual year net generation from sources shown. Generation received from others is based on the best available information at the publication date of this document.
DIABLO CANYON
DIABLO CANYON OPERATIONS
Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. The operating license expiration dates for Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively. As of December 31, 1997, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 80.3% and 82.7%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next five years. In the past, Diablo Canyon refueling outages typically have occurred every 18 months. Beginning in 1996, Pacific Gas and Electric Company schedules refueling outages every 20 to 21 months, and it has been seeking NRC licensing authority to schedule such outages once every 24 months beginning in 2001. Though nominal 20-month cycles are firm, achieving a 24-month cycle is uncertain and its implementation could be delayed. The schedule below assumes
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.
DIABLO CANYON RATEMAKING
Prior to 1997, ratemaking for Diablo Canyon was determined by basing revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. Under the prior ratemaking treatment, revenues were based on a pre-established price per kWh of electricity generated by the plant. That price consisted of a fixed component (3.15 cents per kWh) and a separate component that declined until 2000, at which point the variable component would have begun to escalate. For example, the total price per kWh for the year 1996 was 10.50 cents. Under this "performance-based" approach, Pacific Gas and Electric Company assumed a significant portion of the operating risk of the plant because the extent and timing of the recovery of actual operating costs, depreciation, and a return on the investment in the plant primarily depended on the amount of power produced and the level of costs incurred. Pacific Gas and Electric Company's earnings were affected directly by plant performance and costs incurred. Under this ratemaking treatment, earnings relating to Diablo Canyon could fluctuate significantly as a result of refueling or other extended plant outages, plant expenses, and the effects of a peak-period pricing mechanism.
In connection with electric industry restructuring, in 1996, Pacific Gas and Electric Company proposed to price electric generation from Diablo Canyon at market prices and to complete recovery of its investment in Diablo Canyon by the end of 2001. Pacific Gas and Electric Company proposed to replace the Diablo Canyon performance-based ratemaking mechanism described above with: (1) a sunk cost revenue requirement to recover net investment in plant, including a return on this net investment, and (2) a performance-based Incremental Cost Incentive Price (ICIP) mechanism to recover the facility's variable and other operating costs and capital addition costs. As proposed by Pacific Gas and Electric Company, the sunk cost revenue requirement would be set to accelerate recovery of Diablo Canyon sunk costs from a period ending in 2016 to a five- year period ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90 percent of Pacific Gas and Electric Company's long-term cost of debt. Pacific Gas and Electric Company's proposed ICIP mechanism would establish a rate per kWh generated by the facility. This rate would be based upon a fixed forecast of ongoing costs, capital additions, and capacity factors for the period 1997 through 2001.
In May 1997, the CPUC issued a decision on Pacific Gas and Electric Company's proposal with an effective date of January 1, 1997. Under the decision, Pacific Gas and Electric Company's sunk costs will be recovered through a sunk cost revenue requirement, at a reduced return on common equity equal to 90 percent of Pacific Gas and Electric Company's embedded cost of debt, for a reduced total return of 7.17% which will be effective through 2001. The CPUC decision substantially reduces the level of Pacific Gas and Electric Company's proposed ICIP pricing through which ongoing operating costs and capital additions will be recovered.
The CPUC decision adopts a fixed forecast of ICIP for 1997-2001, as shown below. The revenues are based on an assumed capacity factor of 83.6 percent.
INCREMENTAL COST INCENTIVE PRICES AND ESTIMATED TOTAL CPUC REVENUE REQUIREMENT
The CPUC decision excluded several items totaling $160 million from the sunk cost revenue requirement, including out-of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The CPUC decision requires that the costs of materials, supplies and nuclear fuel be recovered through the ICIP mechanism as these items are used. The CPUC also disallowed about $70 million in plant costs from the sunk cost revenue requirement. Pacific Gas and Electric Company has sought a rehearing of the CPUC decision.
The CPUC decision also ordered that a financial verification audit of Diablo Canyon plant accounts be performed by an independent accounting firm, and that the CPUC hold a proceeding to review the results of the audit, including any proposed adjustments to Diablo Canyon accounts, following the completion of the audit.
More information concerning the financial impact of Diablo Canyon ratemaking is included in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders.
NUCLEAR FUEL SUPPLY AND DISPOSAL
Pacific Gas and Electric Company has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well as one contract for fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, the conversion of uranium to uranium hexaflouride, and the enrichment of the uranium hexaflouride to enriched uranium will be satisfied by a combination of existing contracts and inventories through 2000, 1999, and 2002, respectively. The fuel fabrication contract for the two units will supply their requirements for the next eight operating cycles of each unit. These contracts are intended to ensure long- term fuel supply, but permit Pacific Gas and Electric Company the flexibility to take advantage of short-term supply opportunities. In most cases, Pacific Gas and Electric Company's nuclear fuel contracts are requirements-based, with the Company's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, Pacific Gas and Electric Company has signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Company's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has officially acknowledged that it will not be able to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted by the DOE for interim or permanent storage before 2012, at the earliest. At the projected level of operation for Diablo Canyon, Pacific Gas and Electric Company's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. It is likely that an interim or
permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2006. Pacific Gas and Electric Company is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility.
In July 1988, the NRC gave final approval to Pacific Gas and Electric Company's plan to store radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the unit. The license amendment issued by the NRC allows storage of spent fuel rods at Humboldt until a federal repository is established. Pacific Gas and Electric Company has agreed to remove all nuclear waste as soon as possible after the federal disposal site is available.
INSURANCE
Pacific Gas and Electric Company has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). The company, which is owned by utilities with nuclear generating facilities, provides insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. Under Pacific Gas and Electric Company's policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Company may be subject to maximum retrospective premium assessments of $23 million (property damage) and $7 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NEIL.
Pacific Gas and Electric Company has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $8.7 billion of coverage is provided by secondary financial protection required by federal law and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, Pacific Gas and Electric Company may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident.
DECOMMISSIONING
Pacific Gas and Electric Company's estimated total obligation to decommission and dismantle its nuclear power facilities is $1.4 billion in 1997 dollars ($5.1 billion in future dollars). This estimate, which includes labor, materials, waste disposal charges, and other costs, is based on a 1997 decommissioning cost study. A contingency to capture engineering, regulatory, and business environment changes is included in the total estimated obligation. Actual decommissioning costs are expected to vary from this estimate because of changes in the assumed dates of decommissioning, regulatory requirements, and technology, as well as differences in the amount of labor, materials, and equipment needed to complete decommissioning. The estimated total obligation needed to complete decommissioning is recognized proportionately over the license term of each facility.
Nuclear decommissioning costs recovered in rates are placed in external trust funds. These funds, along with accumulated earnings, will be used exclusively for decommissioning. The trust funds maintain substantially all of their investments in debt and equity securities. All earnings on the trust fund are reinvested. Monies may not be released from the external trust funds until authorized by the CPUC. As of December 31, 1997, Pacific Gas and Electric Company had accumulated external trust funds with an estimated fair value of $1 billion, based on quoted market prices, to be used for the decommissioning of the Company's nuclear facilities.
In the past, the amount recovered in rates for nuclear decommissioning costs through an annual allowance has been reviewed by the CPUC as part of the GRC. The CPUC considers the trusts' asset levels, together with revised earnings and decommissioning cost assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trusts. The monies contributed to the decommissioning trusts, together with existing trust fund balances and projected earnings, are intended to satisfy the estimated future obligation for decommissioning costs. For the year ended December 31, 1997, nuclear decommissioning costs recovered in rates were $33 million.
In compliance with AB 1890, effective on January 1, 1998, nuclear decommissioning costs, which are not transition costs, are being recovered through a nonbypassable charge which will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. In its roadmap decision, the CPUC established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and establish the annual revenue requirement and attrition factors over three-year periods when and if GRCs are discontinued.
OTHER ELECTRIC RESOURCES
QF GENERATION AND OTHER POWER-PURCHASE CONTRACTS
By federal law, Pacific Gas and Electric Company is required to purchase electric energy and capacity provided by independent power producers. The CPUC established a series of power-purchase contracts and set the applicable terms, conditions, price options, and eligibility requirements.
Under these contracts, Pacific Gas and Electric Company is required to make payments only when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. Pacific Gas and Electric Company's contracts with these power producers expire on various dates through 2028. Total energy payments are expected to decline in the years 1998 through 2001. Total capacity payments are expected to remain at current levels during this period. Deliveries from these power producers accounted for approximately 18% of Pacific Gas and Electric Company's 1997 electric energy requirements and no single contract accounted for more than 5% of the Company's energy needs.
Pacific Gas and Electric Company has negotiated early termination or suspension of certain power-purchase contracts. These amounts are expected to be recovered in rates and as such are reflected as deferred charges on the Company's balance sheet. At December 31, 1997, the total discounted future payments remaining under early termination or suspension contracts is $53 million.
Pacific Gas and Electric Company also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, Pacific Gas and Electric Company must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the provider's retention of the FERC's authorization) and variable payments for operation and maintenance costs are incurred by the providers. These contracts expire on various dates from 2004 to 2031. The total cost of these payments is recoverable in rates. At December 31, 1997, the undiscounted future minimum payments under these contracts are $34 million for each of the years 1998 through 2002 and a total of $349 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 4% of Pacific Gas and Electric Company's 1997 electric energy requirements.
The amount of energy received and the total payments made under all these power-purchase contracts were:
As of December 31, 1997, Pacific Gas and Electric Company had commitments to purchase approximately 5,400 megawatts (MW) of capacity under CPUC-mandated power-purchase agreements. Of the 5,400 MW, approximately 4,600 MW were operational. Development of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 4,600 MW of operational capacity consists of 2,900 MW from cogeneration projects, 700 MW from wind projects, and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric.
GEOTHERMAL GENERATION
Pacific Gas and Electric Company's geothermal units at The Geysers Power Plant (Geysers) are forecast to operate at reduced capacities because of declining geothermal steam supplies and curtailment of the Geysers due to the existence of more economic sources of electric generation. Pacific Gas and Electric Company's agreements with several of its steam suppliers permit the Company to curtail generation at The Geysers at the Company's discretion. The consolidated Geysers capacity factor is forecast to be approximately 48% of installed capacity in 1998, which includes economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 45% in 1997.
In connection with electric industry restructuring, in January 1998, Pacific Gas and Electric Company filed an application with the CPUC seeking approval to sell The Geysers, subject to CPUC and other regulatory approvals. See "Electric Utility Operations--Electric Industry Restructuring Legislation-- Voluntary Generation Asset Divestiture" above.
HELMS PUMPED STORAGE PLANT
Helms is a three-unit hydroelectric combined generating and pumped storage facility, completion of which was delayed due to a water conduit rupture in September 1982 and various start-up problems related to the plant's generators. Helms became commercially operable in June 1984. As a result of the damage caused by the rupture and the delay in the operational date, Pacific Gas and Electric Company incurred additional costs which were not initially included in rate base, and lost revenues during the period the plant was under repair. In September 1996, the CPUC approved a settlement resolving the treatment of remaining unrecovered Helms costs.
As part of the 1996 GRC decision issued in December 1995, the CPUC directed Pacific Gas and Electric Company to perform a cost-effectiveness study of Helms. The CPUC indicated the study should consider changes in rate recovery for the plant including, among other things, the option of retirement with recovery of the investment without a return. The cost-effectiveness study submitted by Pacific Gas and Electric Company in July 1996 concluded that the continued operation of Helms is cost-effective. Pacific Gas and Electric Company recommended that the CPUC take no action based on the study, but address Helms along with other generating plants in the context of electric industry restructuring. Pacific Gas and Electric Company's net investment in Helms at December 31, 1997 was $691 million. Under electric industry restructuring, the uneconomic above-market portion of the Company's net investment in Helms is eligible for recovery as a transition cost. However, Pacific Gas and Electric Company will be placed at risk to recover its future operating costs in the newly restructured electric generation market. Because the CPUC has not specifically addressed the cost-effectiveness study, Pacific Gas and Electric Company is currently unable to predict whether there will be further changes in rate recovery resulting from the study. See "Pacific Gas and Electric Company Rate Matters--Electric Ratemaking" above.
ELECTRIC TRANSMISSION AND DISTRIBUTION
To transport energy to load centers, Pacific Gas and Electric Company as of December 31, 1997, owned and operated approximately 18,516 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 33,814,855 kilovolt-amperes (kVa), excluding power plant interconnection facilities. Energy is distributed to customers through approximately 108,170 circuit miles of distribution system and distribution substations having a capacity of approximately 23,000,000 kVa.
Under AB 1890, it is intended that California's investor-owned utilities and its publicly owned utilities relinquish control, but not ownership, of their transmission facilities to the ISO. In 1997, the FERC issued various decisions to implement the formation and operation of the ISO and the PX as contemplated by AB 1890. The ISO will control the operation of the transmission system and provide open access transmission service on a nondiscriminatory basis. The FERC approved the various forms of agreements for must-run facilities that will be entered into between the utilities and the ISO to ensure grid reliability. The FERC also granted conditional
authority for operation of the ISO and the PX. After the ISO and the PX announced a delay in commencement of their operations, the FERC issued an order requiring the ISO and the PX to provide the FERC 15 days notice before the intended commencement date of operations and the ISO's assumption of operational control of certain transmission facilities.
The FERC has also approved a proposal from Pacific Gas and Electric Company and the other California utilities that distinguishes between local distribution facilities and transmission facilities. The order defines jurisdiction for the CPUC over local distribution and retail power customers. The FERC will have jurisdiction over the transmission facilities as defined in the order and over the transmission aspects of retail direct access. Most of Pacific Gas and Electric Company's distribution services will remain subject to CPUC jurisdiction.
GAS UTILITY OPERATIONS
Pacific Gas and Electric Company owns and operates an integrated gas transmission, storage, and distribution system in California. At December 31, 1997, Pacific Gas and Electric Company's system, including the PG&E Expansion (Line 401), consisted of approximately 5,700 miles of transmission pipelines, three gas storage facilities, and approximately 36,700 miles of gas distribution lines.
GAS OPERATIONS
Pacific Gas and Electric Company's peak day send-out of gas on its integrated system in California during the year ended December 31, 1997, was 4,145 million cubic feet (MMcf). The total volume of gas throughput during 1997 was approximately 888,000 MMcf, of which 262,000 MMcf was sold to direct end-use or resale customers, 173,000 MMcf was used by Pacific Gas and Electric Company primarily for its fossil-fueled electric generating plants, and 452,000 MMcf was transported as customer-owned gas.
The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities as a result of a CPUC order. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years.
The 1997 Supplemental Report updates Pacific Gas and Electric Company's annual gas requirements forecast (excluding bypass volumes) for the years 1997 through 2010 forcasting growth in gas throughput served by Pacific Gas and Electric Company of 2% per year. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching, and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing Pacific Gas and Electric Company's system entirely. The 1997 Supplemental Report forecasts a total bypass volume of 133,600 MMcf for 1998.
GAS OPERATING STATISTICS
The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries except where indicated) for gas, including the classification of sales and revenues by type of service.
- -------- (1) Primarily includes fuel for Pacific Gas and Electric Company's fossil- fueled generating plants. (2) Does not include on-system transportation volumes transported on the PG&E Expansion of 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and 7,205 MMcf for 1997, 1996, 1995, 1994 and 1993, respectively. (3) In January 1997, a Pacific Gas and Electric Company subsidiary--Pacific Gas Transmission Company (PGT) became a subsidiary of PG&E Corporation and is now known as PG&E Gas Transmission, Northwest Corporation.
- -------- (1) Over 100% indicates colder than normal. (2) The net plant investment per customer figure for 1997 is lower than in previous years because it excludes subsidiaries.
NATURAL GAS SUPPLIES
The objective of Pacific Gas and Electric Company's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs, and fosters competition among suppliers.
Under current CPUC regulations, Pacific Gas and Electric Company purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 1997, approximately 66% of Pacific Gas and Electric Company's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by Canadian pipeline companies and PG&E Gas Transmission, Northwest Corporation; approximately 3% was purchased from various California producers; and approximately 31% was purchased in other states (substantially all from U.S. Southwest sources and transported by the El Paso Natural Gas Company or Transwestern Pipeline Company pipelines). The following table shows the volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by Pacific Gas and Electric Company from these sources during each of the last five years.
- -------- (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. The average prices for California gas include only commodity gas prices delivered to Pacific Gas and Electric Company's gas system.
GAS REGULATORY FRAMEWORK
In August 1997, the CPUC approved the Gas Accord which restructures Pacific Gas and Electric Company's gas services and its role in the gas market. As discussed above (see "Competition and the Changing Regulatory Environment--Gas Industry"), the Gas Accord separates, or "unbundles," the rates for Pacific Gas and Electric Company's gas transmission services from its distribution services, increases the opportunities for core customers
to purchase gas from competing suppliers, establishes a form of incentive regulation to measure the reasonableness of core procurement costs, and establishes gas transmission and storage rates from March 1998 through December 2002. The Gas Accord also settled various issues pending in certain regulatory proceedings.
The CPUC is considering further changes in California's natural gas industry. See "Competition and the Changing Regulatory Environment--Gas Industry" above.
TRANSPORTATION COMMITMENTS
Pacific Gas and Electric Company has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that Pacific Gas and Electric Company will pay each year may change due to changes in tariff rates. The total demand and volumetric transportation charges paid by Pacific Gas and Electric Company under these agreements were approximately $255 million in 1997. This amount includes payments made to PG&E Gas Transmission, Northwest Corporation of approximately $49 million in 1997, which payments are eliminated in the consolidated financial statements of PG&E Corporation.
As a result of regulatory changes, Pacific Gas and Electric Company no longer procures gas for most of its noncore customers, resulting in a decrease in the Company's need for firm transportation capacity for its gas purchases. Pacific Gas and Electric Company continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers). Pacific Gas and Electric Company is continuing its efforts to broker or assign any of its remaining contracted-for but unused interstate transportation capacity, including unused capacity held for its core and core subscription customers.
Under a firm transportation agreement with PG&E Gas Transmission, Northwest Corporation that runs through October 31, 2005, Pacific Gas and Electric Company currently retains approximately 600 million cubic feet per day (MMcf/d) on the PG&E Gas Transmission, Northwest Corporation system to support its core and core subscription customers. Although this capacity commitment exceeds the amount needed to support Pacific Gas and Electric Company's core and core subscription customers, the Company has been able to assign substantially all of its unused capacity on PG&E Gas Transmission, Northwest Corporation's system to other shippers.
In general, any shortfall resulting from the difference between the fixed demand charges Pacific Gas and Electric Company pays under gas transportation contracts with interstate pipeline companies for the reservation of interstate pipeline capacity that the Company no longer uses to serve noncore customers, and the revenues Pacific Gas and Electric Company obtains from brokering that capacity, is eligible for rate recovery through the Interstate Transition Cost Surcharge (ITCS), subject to a reasonableness review. Various groups had challenged Pacific Gas and Electric Company's recovery of these amounts, including amounts which arose in connection with firm transportation commitments that the Company had entered into with PG&E Gas Transmission, Northwest Corporation and El Paso Natural Gas Company. (The agreement with El Paso terminated as of December 31, 1997.) Under the Gas Accord, these challenges were resolved through Pacific Gas and Electric Company's agreement to forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated for collection from its core and noncore customers, respectively.
In 1992, Pacific Gas and Electric Company entered into a firm transportation agreement with Transwestern Pipeline Company (Transwestern), which expires in 2007, to meet core gas sales demands and electric generation needs. The demand charges associated with the entire Transwestern capacity are currently approximately $29 million per year. Pacific Gas and Electric Company was not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account, although the Company was authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings. In 1995, the CPUC determined that it was unreasonable for Pacific Gas and Electric Company to commit to transportation capacity with Transwestern and disallowed recovery of the costs of capacity for 1992. It indicated that it would disallow costs through the term of the contract unless Pacific Gas
and Electric Company could demonstrate on an annual basis that the benefit of the commitment outweighed the costs in a particular year. As part of the Gas Accord, Pacific Gas and Electric Company agreed to resolve this issue by forgoing the recovery of costs associated with capacity originally subscribed to in order to serve core customers through 1997 and to limit its recovery of demand charges through the CPIM during the period 1998 through 2002.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through Pacific Gas and Electric Company's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were incurred reasonably. Before June 1, 1994, annual reasonableness proceedings were conducted by the CPUC on a historic calendar year basis. As discussed above (see "Competition and the Changing Regulatory, Environment-- Gas Industry"), the annual reasonableness proceedings have been replaced by the CPIM.
1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on Pacific Gas and Electric Company's Canadian gas procurement activities during 1988 through 1990. The CPUC found that Pacific Gas and Electric Company could have saved its customers money if it had bargained more aggressively with its existing Canadian suppliers or bought less expensive gas from other Canadian sources. The decision ordered a disallowance of $90 million of gas costs, plus accrued interest estimated at approximately $25 million through December 31, 1993. Although Pacific Gas and Electric Company had challenged this decision by the CPUC in federal court, as part of the Gas Accord, the Company has agreed to forgo recovery of the $90 million disallowance ordered in the 1988-1990 reasonableness proceeding. In November 1997, Pacific Gas and Electric Company's federal lawsuit was dismissed with prejudice.
PGT/PACIFIC GAS AND ELECTRIC COMPANY PIPELINE EXPANSION
In November 1993, PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas Transmission Company or PGT) and Pacific Gas and Electric Company placed in service the Pipeline Expansion, an expansion of their interconnected natural gas transmission systems from the Canadian border into California. The 840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern and Southern California.
The conditions of the CPUC's approval of the construction of Pacific Gas and Electric Company's portion of the Pipeline Expansion (PG&E Expansion or Line 401) placed Pacific Gas and Electric Company at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross-over" ban under which volumes delivered from the incremental portion owned by PG&E Gas Transmission, Northwest Corporation (PGT Expansion) of the Pipeline Expansion must be transported at an incremental PG&E Expansion rate. The costs of PG&E Expansion operations were recovered only from PG&E Expansion customers, through rates established in separate PG&E Expansion rate proceedings.
Under the Gas Accord, Pacific Gas and Electric Company remains at risk for cost recovery of the PG&E Expansion through rates; however, a portion of the PG&E Expansion will be combined with other Pacific Gas and Electric Company transmission assets (specifically, a portion of Pacific Gas and Electric Company's Line 400) for ratemaking purposes. This new ratemaking treatment for gas transmission assets allows all shippers supplying noncore customers to transport Canadian gas in California at a single rate, and obviates the need for the "cross-over" ban, which was eliminated under the Gas Accord. Further, in the Gas Accord, the CPUC adopted a rule under which Pacific Gas and Electric Company is required, whenever it discounts service for a shipper on its Line 400/401 delivering primarily Canadian gas within the Company's service territory, to contemporaneously offer a commensurate discount to all shippers delivering Southwest or California source gas on Line 300 within the Company's service territory.
In 1994, Pacific Gas and Electric Company filed its application in the Pipeline Expansion Project Reasonableness case (PEPR) requesting that the CPUC find reasonable the full capital costs of the PG&E Expansion (estimated to be $810 million). In that proceeding, the ORA recommended a minimum of $100 million in capital costs be disallowed, while two intervenors jointly recommended a $237 million disallowance or reallocation of costs among customers. In addition, in 1996, a CPUC administrative law judge (ALJ) ordered consolidation of the market impact phase of the PEPR and the ITCS proceeding described above. An ALJ also ordered reopening of the 1993 PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding the decision to construct the PG&E Expansion. The CPUC's 1997 decision approving the Gas Accord affirms the CPUC's 1994 finding that the decision to construct the PG&E Expansion was reasonable based on Pacific Gas and Electric Company management's knowledge at the time. The Gas Accord decision accepts the Gas Accord's proposal to set rates for Line 401 during the Gas Accord period based on total capital costs of $736 million.
PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS
During 1997, PG&E Corporation expanded its operations in the "midstream" portion of the gas business, which includes (1) the gas gathering, processing, storage, and transportation of natural gas, (2) the marketing of natural gas to gas distribution companies, electric utilities, municipalities, marketers, independent power producers, and end-use customers, and (3) the transportation of natural gas for these customers, producers and other pipelines.
Through its January 1997 acquisition of Teco in Texas (now known as PG&E Gas Transmission Teco, Inc.), PG&E Corporation acquired various interests in natural gas pipeline systems in Texas, various investments in gas gathering and processing facilities, and a gas marketing operation in Houston, Texas.
On July 31, 1997, PG&E Corporation completed its acquisition of Valero's natural gas and related businesses, including its gas gathering, transportation, and storage facilities, and its facilities relating to the processing, transportation, and marketing of natural gas liquids (NGLs). Valero's NGL business includes the gathering of natural gas, the extraction of NGLs from natural gas, the fractionation of mixed NGLs into component products (e.g., ethane, propane, butane, and natural gasoline), and the transportation and marketing of NGLs. PG&E Corporation acquired approximately 6,400 miles of natural gas pipeline and Valero's joint ownership or leasehold interests in approximately 1,100 miles of pipeline, including the Valero-Teco West Texas pipeline from Waha in west Texas to the San Antonio area. This pipeline system has the capacity to transport more than 3 bcf of gas per day. PG&E Corporation acquired a long-term lease of 7.2 bcf of storage capacity, approximately 536 miles of NGL pipelines and eight natural gas processing plants with a combined capacity of approximately 1.5 bcf per day of gas throughput, capable of producing approximately 93,000 barrels per day of NGLs.
PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas Transmission Company or PGT) owns and operates gas transmission pipelines and associated facilities which extend over 612 miles from the Canada-U.S. border to the Oregon-California border and are capable of transporting 2.4 billion cubic feet (bcf) per day of natural gas. It also owns two smaller diameter pipeline extensions within Oregon, totaling 106 miles. A subsidiary of PG&E Corporation also owns the PG&E Queensland Gas Pipeline, an approximately 389- mile of mostly 12-inch pipeline in Queensland, Australia, which provides natural gas transportation service to customers in the vicinity of the pipeline.
In September 1996, the FERC approved a settlement of PG&E Gas Transmission, Northwest Corporation's 1994 rate case. The major issue in this proceeding was whether PG&E Gas Transmission, Northwest Corporation's mainline transportation rates should be equalized through the use of rolled-in cost allocations, or whether they should continue to reflect the use of incremental cost allocation to determine the rates to be paid by firm shippers. (Under incremental rates, a pipeline would generally charge higher rates to shippers contracting for capacity on newly-added expansion facilities as compared to shippers using depreciated pre-expansion facilities.) The settlement provides for rolled-in rates effective November 1996. To mitigate the impact of the higher rolled-in rates on shippers who were paying lower rates under contracts executed prior to construction of the PGT Expansion, most of the firm shippers who took service prior to such time receive a reduction from the rolled-in rate for a six-year period, while PGT Expansion firm shippers pay a surcharge in addition to the rolled-in rates to offset the effect of the mitigation. See "Gas Utility Operations--PGT/Pacific Gas and Electric Company Pipeline Expansion" above. The settlement also provides for rates based on a return on equity of 12.2%. Several parties are seeking rehearing of the FERC order approving the settlement, but PG&E Gas Transmission, Northwest Corporation currently expects the settlement to be upheld.
PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS
Through USGen and its affiliates, PG&E Corporation participates in the development, construction, operation, ownership, and management of non-utility electric generating facilities that compete in the United States power generation market. As of December 31, 1997, USGen, headquartered in Bethesda, Maryland, and its affiliates had ownership interests in 15 operating plants in eight states. The total generating capacity of these 15 plants is 3,249 MW. PG&E Corporation's combined net equity ownership in these plants as of December 31, 1997, represented 1,457 MW. The plants were largely financed with a combination of equity or equity commitments from the project sponsors and non-recourse debt. USGen, through its affiliate, U.S. Operating Services Company (USOSC), provides contract operations and maintenance services to many of these facilities. Nationwide, USGen's power plant development activities exceed 4,400 MW in eight states. Together with its power marketing affiliate, USGen Power Services, L.P. (now PG&E Energy Trading--Power, L.P.), USGen and its affiliated or managed facilities sold 38.4 million megawatt-hours (MWh) of electricity into the wholesale electric market in 1997.
In a series of transactions commencing in September 1997 and ending in January 1998, subsidiaries of PG&E Corporation acquired Bechtel Enterprises' interests in USGen, USOSC, and USGen Power Services, L.P. (now PG&E Energy Trading--Power, L.P.). PG&E Corporation also acquired all or a portion of Bechtel's interests in six independent power generating facilities which were jointly owned by PG&E Corporation and Bechtel, or by PG&E Corporation, Bechtel, and various third parties.
On August 6, 1997, PG&E Corporation announced that it had agreed to acquire a portfolio of non-nuclear electric generating assets and power supply contracts from the New England Electric System (NEES) for $1.59 billion. These assets will be held by an affiliate of USGen. The $1.59 billion purchase price includes $225 million to be paid to NEES when customer choice of energy power suppliers is broadly available in New England. This amount will decline in accordance with a prorated schedule if the implementation of customer choice of energy power suppliers in New England occurs after January 1, 1999. In addition to the purchase price, NEES will also receive $85 million from USGen or its affiliates to pay for employee retraining, early retirement, and severance for NEES' employees affected by industry restructuring. USGen or one of its affiliates will also assume certain existing collective bargaining agreements between NEES and its labor unions.
Including fuel and other inventories and transaction costs, financing requirements are expected to reach approximately $1.75 billion, of which approximately $1 billion will be funded through a combination of project level debt as well as debt of affiliates of USGen. In addition, up to $750 million of equity will be contributed over two years and will be financed initially using short-term debt of PG&E Corporation.
The NEES facilities to be acquired consist of two hydroelectric systems with 14 stations, three fossil-fuel stations with 11units, and a pumped storage facility, with a combined generating capacity of approximately 4,000 MW. USGen or its affiliates will also assume the purchase obligations under 23 multi- year power purchase agreements between NEES' subsidiary, New England Power, and other utility and non-utility wholesale suppliers representing an additional 1,100 MW of production capacity. The terms of the acquisition call for New England Power to make annual support payments ranging approximately from $150 million to $170 million through early 2008 to offset the cost of power associated with these above-market contracts. The annual payment is a fixed obligation and is not dependent on the actual costs under the agreements, market prices, or NEES' regulatory status.
As part of the electric industry deregulation in Massachusetts and Rhode Island, NEES' retail customers in those states may choose to continue receiving power from NEES (the "Standard Offer") at a fixed price or may choose a new power supplier. NEES' retail customers may make this choice through the year 2004 in Massachusetts and through the year 2009 in Rhode Island. It is expected that in the first half of 1998 NEES will auction its wholesale supply obligations under the Standard Offer to third parties. NEES' remaining supply obligation for these customers will be assigned to USGen, or one or more of its affiliates.
NEES will also assign to USGen or one or more of its affiliates its rights to supply power under several long-term power supply agreements, totaling approximately 100 MW. The acquisition also includes 100 million cubic feet per day of long-term natural gas supply and pipeline commitments, as well as a twelve-year lease on a self-unloading coal transportation vessel.
PG&E Corporation's acquisition of NEES' assets, which is expected to be completed in 1998, is subject to a number of conditions, including approval of the FERC and state regulators.
NEES' sale of these generating facilities and power supply contracts was prompted, in part, by the anticipated deregulation of the electric industry in several New England states. In Massachusetts, electric industry restructuring legislation took effect on March 1, 1998. A referendum will be voted on in November 1998, to repeal this legislation.
The financial impact of the acquisition of the NEES assets on PG&E Corporation is subject to a number of risks and uncertainties, including future market prices of power in the region where the NEES assets are located, future fuel prices, the development of a competitive market in the states in which the NEES assets are located, the extent to which operating efficiencies at the NEES plants can be attained, changes in legislation affecting electric industry restructuring and in the regulatory environment in the states where the NEES assets are located, the extent of the obligation to provide electricity under the Standard Offer at prices below cost or market, the extent to which a liquid, well-structured trading market develops for wholesale electric power in the states in which the NEES assets are located, and generating capacity expansion and retirements by others.
In the second quarter of 1997, Bechtel acquired PG&E Corporation's partnership interest in International Generating Company, Ltd. (InterGen), a company formed to develop, own, and operate international electric generation projects. PG&E Corporation realized an after-tax gain of $120 million on the sale.
PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES
PG&E Energy Services Corporation provides gas and electric energy services and commodities nationwide where permitted under applicable laws. PG&E Energy Services also provides commercial, industrial, and institutional customers with a wide range of services, including competitively priced electric and gas commodities, billing and information management services, energy management services, regulatory and rate analysis, and power quality solutions. PG&E Energy Services targets primarily industrial, commercial, and institutional customers. In 1997, PG&E Energy Services embarked on an aggressive campaign to open new offices in the United States, primarily to support its direct sales efforts and to establish a presence and market its services in emerging energy markets. It now has over 20 offices nationwide.
PG&E Energy Services will compete with other non-utility electric retailers in California when direct access begins. See "Electric Utility Operations-- Electric Industry Restructuring Legislation" above.
PG&E Energy Trading, headquartered in Houston, Texas, purchases bulk volumes of power and natural gas from PG&E Corporation affiliates; USGen and PG&E Gas Transmission, and from the wholesale market. PG&E Energy Trading then schedules, transports, and resells these commodities, either directly or through PG&E Energy Services--repackaging them to meet customers' individual delivery, price, and reliability needs. PG&E Energy Trading also provides price risk management services to PG&E Corporation's other businesses (except Pacific Gas and Electric Company) and to wholesale customers. Additionally, PG&E Energy Trading supports PG&E Energy Services Corporation with a broad portfolio of energy products and services for the retail market.
For more information, see "Price Risk Management Programs" above.
ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS
The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection and the possible future impact of environmental compliance. This information reflects Pacific Gas and Electric Company's current estimates which are periodically evaluated and revised. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of Pacific Gas and Electric Company's responsibility, and the availability of recoveries or contributions from third parties. Future estimates and actual results may differ materially from those indicated below.
PG&E Corporation, Pacific Gas and Electric Company, and other PG&E Corporation subsidiaries and affiliates, are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. Pacific Gas and Electric Company has undertaken major compliance efforts with specific emphasis on its purchase, use, and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Company's bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations have generally been recovered in rates.
ENVIRONMENTAL PROTECTION MEASURES
Pacific Gas and Electric Company's estimated expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements.With the sale of the Morro Bay, Moss Landing, and Oakland power plants, and the planned sale of the Contra Costa, Pittsburg, Hunters Point, Potrero, and Geysers power plants, Pacific Gas and Electric Company no longer expects to incur significant oxides of nitrogen (NOx) emission reduction compliance costs. See "Electric Utility Operations--Electric Industry Restructuring Legislation--Voluntary Generation Asset Divestiture" above.
AIR QUALITY
Pacific Gas and Electric Company's thermal electric generating plants are subject to numerous air pollution control laws, including the California Clean Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air Act, three of the local air districts in which Pacific Gas and Electric Company operates fossil-fueled generating plants have adopted final rules that require a reduction in NOx emissions from the power plants of approximately 90% by 2004 (with numerous interim compliance deadlines).
Following divestiture of the Company's fossil-fueled generating plants in connection with electric industry restructuring, the new owners will bear NOx retrofit costs. Under AB 1890, NOx retrofit costs would be eligible for recovery as transition costs but only to the extent that those costs are found by the CPUC to be both reasonable and necessary to maintain the unit in operation through 2001.
The Gas Accord authorizes $42 million to be included in rates through 2002, for gas NOx retrofit projects related to natural gas compressor stations on Pacific Gas and Electric Company's Line 300 which delivers Southwest gas. Other air districts are considering NOx rules which would apply to Pacific Gas and Electric Company's other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at these natural gas compressor stations. Pacific Gas and Electric Company currently estimates that the total cost of complying with these rules will be up to $34 million over four years.
WATER QUALITY
Pacific Gas and Electric Company's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Pacific Gas and Electric Company's fossil-fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast Regional Water Quality Control Board (Central Coast Board). The Central Coast Board did not make a final decision on the report and requested that Pacific Gas and Electric Company continue its thermal effects monitoring program. In 1995, the Central Coast Board requested that Pacific Gas and Electric Company prepare an updated comprehensive assessment of Diablo Canyon's thermal effects and approved a reduced environmental monitoring program. The new comprehensive assessment is scheduled for submission to the Central Coast Board in the first quarter of 1998. In the unlikely event that the Central Coast Board finds that Diablo Canyon's existing thermal limits are not protective of beneficial uses of the marine waters and that major modifications are required (e.g., cooling towers), significant additional construction expenses could be required.
Pursuant to the federal Clean Water Act, Pacific Gas and Electric Company is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. Pacific Gas and Electric Company has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. Pacific Gas and Electric Company is currently preparing a new study for Diablo Canyon. The study is scheduled to be submitted to the Central Coast Board for review in 1999. In the event that the Central Coast Board finds that Diablo Canyon's cooling water intake structure does not meet the BTA requirements, significant additional expenses for construction or mitigation could be required. In addition, the promulgation or modification of statutes, regulations, or water quality control plans, at the federal, state, or regional level may impose increasingly stringent cooling water discharge requirements on Pacific Gas and Electric Company power plants in the future. Costs to comply with renewed permit conditions required to meet any more stringent requirements that might be imposed cannot be estimated at the present time.
Several fish species listed or proposed for listing as endangered species may be found in the waters near Pacific Gas and Electric Company's Delta power plants. To address the impacts of operation and maintenance activities at the Delta plants on sensitive species, Pacific Gas and Electric Company has developed a Habitat Conservation Plan (HCP) pursuant to the requirements of Section 10(a) of the federal Endangered Species Act. The HCP is designed to minimize and mitigate any incidental "take" (e.g., harassing, wounding, or killing) of listed species that may occur from the operation, maintenance, and repair of the power plants, in order to support the issuance of a Section 10(a) incidental take permit necessary for continued operation of the plants.
HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
Pacific Gas and Electric Company assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. Pacific Gas and Electric Company has a comprehensive program to comply with the many hazardous waste storage, handling, and disposal requirements promulgated by the United States Environmental Protection Agency (EPA) under the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with California's hazardous waste laws and other environmental requirements.
One part of this program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plants produced lampblack and tar residues, byproducts of a process that Pacific Gas and Electric Company, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), Pacific Gas
and Electric Company's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. Pacific Gas and Electric Company has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which operated in Pacific Gas and Electric Company's service territory. Pacific Gas and Electric Company owns all or a portion of 29 of these manufactured gas plant sites. Pacific Gas and Electric Company has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which the Company owns. Pacific Gas and Electric Company currently estimates that this program may result in expenditures of approximately $8 million to $11 million over the period 1998 through 1999. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if Pacific Gas and Electric Company is found to be responsible for cleanup at sites it does not currently own.
Pacific Gas and Electric Company has been designated as a potentially responsible party (PRP) under the California Hazardous Substance Account Act (California Superfund) with respect to several manufactured gas plant sites.
In addition to the manufactured gas plant sites, Pacific Gas and Electric Company may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the environment because of an actual or potential release of hazardous substances. Pacific Gas and Electric Company has been designated as a PRP under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales site is a former used oil recycling facility at which Pacific Gas and Electric Company is one of nine PRPs named in an EPA order requiring groundwater remediation at the site. Pacific Gas and Electric Company has also entered into an Administrative Order with the EPA to address soil contamination at the site. With respect to the Casmalia site near Santa Maria, California, Pacific Gas and Electric Company and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires these generators to perform certain site investigation and mitigation measures, and provides a release from liability for certain other site cleanup obligations. Although Pacific Gas and Electric Company has not been formally designated a PRP with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed Pacific Gas and Electric Company and other parties to initiate measures with respect to the study and remediation of that site.
In addition to the sites discussed above, Pacific Gas and Electric Company has also been identified as a PRP at certain disposal sites under the California Superfund. Pacific Gas and Electric Company has also been sued for reimbursement of cleanup costs incurred by the State of California at Pacific Gas and Electric Company's former Jibboom Street Station B power plant in Sacramento, California. In addition, Pacific Gas and Electric Company has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Company is responsible for performing or paying for remedial action at sites the Company no longer owns or never owned.
The cost of hazardous substance remediation ultimately undertaken by Pacific Gas and Electric Company is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning Pacific Gas and Electric Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. Pacific Gas and Electric Company had an accrued liability at December 31, 1997, of $232 million for hazardous waste remediation costs at those sites, including fossil-fueled power plants, where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $442 million if, among other things, other PRPs are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which Pacific Gas and Electric Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to Pacific Gas and Electric
Company based upon a range of reasonably possible, outcomes. Costs may be higher if Pacific Gas and Electric Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.
POTENTIAL RECOVERY OF HAZARDOUS WASTE COMPLIANCE AND REMEDIATION COSTS
In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs (HWRC). That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. However, under the proposed mechanism, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. Under the mechanism, 70% of the ratepayer portion of Pacific Gas and Electric Company's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. Pacific Gas and Electric Company can seek to recover hazardous substance cleanup costs under the new mechanism in the rate proceeding it deems most appropriate.
In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related clean-up costs for contamination caused by events occurring after January 1, 1998.
Pacific Gas and Electric Company will retain liability for certain required environmental remediation of pre-closing soil or groundwater contamination for fossil and geothermal generation facilities which are sold in connection with electric industry restructuring. In 1997, the CPUC approved Pacific Gas and Electric Company's proposal, with respect to certain generation plants to be divested, to prepare a forecast of environmental remediation costs for plants to be divested and use the forecast to adjust the current plant decommissioning cost estimate which will be recovered through the CTC ratemaking mechanism. Pacific Gas and Electric Company's revised estimate of costs to remediate environmental contamination for which it will remain liable at the Morro Bay, Moss Landing, and Oakland power plant is $39 million.
Pacific Gas and Electric Company expects to recover $157 million of the $232 million accrued liability, discussed above, in future rates. The liability also includes $58 million related to power plant decommissioning for environmental clean-up, which is recovered through depreciation. Additionally, Pacific Gas and Electric Company is seeking recovery of costs from insurance carriers and from other third parties.
In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. Pacific Gas and Electric Company had previously notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, Pacific Gas and Electric Company's carriers neither admitted nor denied coverage, but requested additional information from the Company. Although Pacific Gas and Electric Company has received some amounts in settlements with certain of its insurers (approximately $55 million through December 31, 1997), the ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time.
COMPRESSOR STATION LITIGATION
Several cases have been brought against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Company's Hinkley, Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings-- Compressor Station Chromium Litigation" below, for a description of the pending litigation.
ELECTRIC AND MAGNETIC FIELDS
In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks which may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from
contact with EMF but went on to state that a body of evidence has been compiled which raises the question of whether adverse health impacts might exist.
In November 1993, the CPUC adopted an interim EMF policy for California energy utilities which, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services.
As part of its effort to educate the public about EMF, Pacific Gas and Electric Company provides interested customers with information regarding the EMF exposure issue. Pacific Gas and Electric Company also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
Pacific Gas and Electric Company and other utilities are involved in litigation concerning EMF. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. Pacific Gas and Electric Company is a defendant in civil litigation in which plaintiffs allege personal injuries resulting from exposure to EMF. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMF, and barring plaintiffs' personal injury claims. Plaintiffs have filed an appeal of this decision with the California Supreme Court.
In the event that the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility- related EMF exposures can be isolated from other exposures, Pacific Gas and Electric Company may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant depending on the particular mitigation measures undertaken, especially if relocation of existing power lines is ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding which approved approximately $36 million in funding for Pacific Gas and Electric Company's LEV program for the six-year period beginning in 1996. The CPUC's decision on electric industry restructuring finds that the costs of utility LEV programs should continue to be collected by the utility for the duration of the six-year period. Pacific Gas and Electric Company continues to run its LEV program as funded.
ITEM 2.
ITEM 2. PROPERTIES.
Information concerning Pacific Gas and Electric Company's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of Pacific Gas and Electric Company are subject to the lien of an indenture which provides security to the holders of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds.
Information concerning properties and facilities owned by other PG&E Corporation subsidiaries is included in the discussion under the headings of this report entitled "PG&E Corporation's Gas Transmission Operations," "PG&E Corporation's Independent Power Generation Operations," and "PG&E Corporation's Energy Services and Commodities."
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
See Item 1, Business, for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, PG&E Corporation and Pacific Gas and Electric Company are subject to routine litigation incidental to their business.
COMPRESSOR STATION CHROMIUM LITIGATION
Pacific Gas and Electric Company has been named as a defendant in several civil actions filed in California courts on behalf of more than 3,000 plaintiffs, and claims by approximately 2,800 plaintiffs are still pending. These cases are Aguayo v. Betz, Pacific Gas and Electric Company, et al., filed March 15, 1995, in Los Angeles County Superior Court; Aguilar v. Pacific Gas and Electric Company, Betz, et al., filed October 4, 1996, in Los Angeles County Superior Court; Adams v. Betz, filed September 21, 1994, in Los Angeles County Superior Court; Acosta, et al. v. Betz, Pacific Gas and Electric Company, et al., filed November 27, 1996, in Los Angeles Superior Court; Riep, et al. v. Pacific Gas and Electric Company, Betz, et al., filed February 14, 1997, in San Francisco Superior Court; Petitt, et al. v. Pacific Gas and Electric Company, Betz, et al., filed May 6, 1997, in Los Angeles Superior Court; Little and Mustafa v. Pacific Gas and Electric Company and PG&E Corporation, filed September 10, 1997, in San Bernardino Superior Court; and Whipple, et al. v. Pacific Gas and Electric Company and PG&E Corporation, filed September 10, 1997, in San Bernardino Superior Court. (Plaintiffs have agreed to dismiss PG&E Corporation in these last two suits.) These eight cases are collectively referred to as the "Aguayo Litigation."
Each of the complaints in the Aguayo Litigation, except Little described below, alleges personal injuries and seeks compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of Pacific Gas and Electric Company's gas compressor stations at Kettleman, Hinkley and Topock, California. The plaintiffs in the Aguayo Litigation include Pacific Gas and Electric Company employees, former Pacific Gas and Electric Company employees, relatives of Pacific Gas and Electric Company employees or former employees, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations, alleging exposure to chromium at or near the compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim only loss of consortium or injury through the alleged exposure of their parents.
In the Adams case, the claims remaining against Pacific Gas and Electric Company arise from a cross-claim filed by Betz Chemical Company, the supplier of water treatment products containing chromium used at the gas compressor stations.
In the Whipple case, pending in San Bernardino Superior Court, plaintiffs, four members of one family, allege personal injuries, injury to a business enterprise, and injury to real property based upon causes of action for (1) actual fraud and deceit, (2) negligence, (3) negligence per se, (4) strict liability, (5) battery, (6) intentional misrepresentation, (7) negligent misrepresentation, (8) fraudulent concealment, and (9) intentional spoliation of evidence. In the Little case, also pending in San Bernardino Superior Court, two plaintiffs allege injury to real property based upon causes of action for (1) actual fraud and deceit, (2) negligence, and (3) negligence per se. Plaintiffs in each action are seeking unspecified compensatory and punitive damages, as well as civil penalties pursuant to Proposition 65.
All discovery and discovery motion practice in four of the five cases brought in Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas and Electric Company, Aguayo v. Pacific Gas and Electric Company, and Adams v. Betz) has been referred by the judge to a discovery referee. Test plaintiffs have been chosen in the Aguayo matter, and discovery is ongoing. During 1997, more than 300 plaintiffs were dismissed from Aguayo v. Pacific Gas and Electric Company for failure to respond to discovery or otherwise pursue their claims. Discovery is beginning in the Acosta and Aguilar matters. Pacific Gas and Electric Company has a motion for good faith settlement pending in the Adams matter, as that case involves the same plaintiffs as a matter that Pacific Gas and Electric Company previously settled. The fifth case brought in Los Angeles Superior Court by eight plaintiffs (Pettit v. Pacific Gas and Electric Company) was not served on Pacific Gas and Electric Company until December 1997, and Pacific Gas and Electric Company filed an answer in January 1998.
In Riep v. Pacific Gas and Electric Company, pending in San Francisco Superior Court, a trial date has been set for August 3, 1998.
Pacific Gas and Electric Company is responding to the complaints and asserting affirmative defenses. Pacific Gas and Electric Company will pursue appropriate legal defenses including statute of limitations, inability of certain plaintiffs to state a claim for alleged preconception exposure, or exclusivity of workers' compensation laws, and factual defenses including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged, and Pacific Gas and Electric Company is attempting to gather information concerning the alleged type and duration of exposure, the nature of injuries alleged by individual plaintiffs, and the additional facts necessary to support its legal defenses, in order to better evaluate and defend this litigation.
PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or Pacific Gas and Electric Company's financial position or results of operations.
TEXAS FRANCHISE FEE LITIGATION
In connection with PG&E Corporation's acquisition of Valero Energy Corporation, now known as PG&E Gas Transmission, Texas Corporation (GTT), PG&E Corporation entities succeeded to the litigation described below.
City of San Benito, City of Primera, and City of Port Isabel v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as GTT), Southern Union Company, et al., 107th State District Court, Cameron County, Texas.
On December 31, 1996, a petition was filed by the Texas cities of San Benito, Primera, and Port Isabel against Rio Grande Valley Gas Company (RGVG), Valero (now known as PG&E Gas Transmission, Texas Corporation), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as Valero Gas Marketing Company), Reata Industrial Gas L.P. (now known as PG&E Reata Energy, L.P.), Valero Transmission L.P. (now known as PG&E Texas Pipeline, L.P.), and Valero Transmission Company (now known as VT Company), and two Southern Union entities: Southern Union Company ("SU") and Mercado Gas Services, Inc. On November 4, 1997, the cities of San Benito, Primera, and Port Isabel filed an amended petition and an amended motion for class action certification, and dismissed RGVG and the other SU entities. The amended petition named as defendants PG&E Gas Transmission, Texas Corporation and most of its subsidiaries (excluding the Canadian gas trading company and power trading company), PG&E Gas Transmission Teco, Inc. and most of its subsidiaries, and PG&E Energy Trading Corporation.
In the amended petition, plaintiffs allege, among other things, that (1) the defendants that own or operate pipelines (in their capacities as merchants or transporters) have occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities for use of the cities' properties and (2) the defendants that are gas marketers have failed to pay cities for accessing and utilizing pipelines located in the cities to flow gas under city streets to end-use gas customers. The petition also alleges various tort and statutory claims against defendants for failure to secure the consents.
On November 5, 1997, orders were signed certifying a class, setting an opt out deadline of December 31, 1997, and ordering notice to all potential class members. The class certified consists of every incorporated municipality in Texas (excepting the cities of Edinburg, Mercedes, and Weslaco, which have filed separate actions) where any of the defendants engaged in business activities related to natural gas or natural gas liquids. The court named the cities of San Benito, Primera, and Port Isabel as class representatives. Fewer than 20 cities had opted out by the deadline. Some of the cities which opted out include Austin, Brownsville, Houston, Pharr, and San Antonio. One purported class member has filed a notice to vacate the class certified.
Defendants' motion to transfer venue of this case to Bexar County, Texas, is currently pending.
City of Edinburg v. Rio Grande Valley Gas Co., Valero Energy Corporation (now known as GTT), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Southern Union Gas Co., and Southern Union Gas Co., 92nd State District Court, Hidalgo County, Texas.
On August 31, 1995, the City of Edinburg (City) filed a lawsuit against certain Valero and Southern Union companies. The City's pleadings assert various contract and tort actions, but all such claims are based on the theory that when Rio Grande Valley Gas Company (RGVG), as the local distribution company (LDC), was granted a franchise to sell gas and construct, maintain, own, and operate gas pipelines in city streets, such authorization extended to RGVG only and to no other entity. (On September 30, 1993, Valero sold the common stock of RGVG to Southern Union.) The City seeks monetary damages and injunctive relief on the theory that non-LDC owned pipelines were not authorized under the franchise with RGVG and were otherwise unlawful without the consent of, and the payment of compensation to, the City. The City also claims that when RGVG began to operate pipelines it did not own, such activities were not within the franchise and not otherwise consented to by the City. Consequently, the City contends that all non-LDC owned pipelines (which includes all of Valero Transmission, L.P.'s (now known as PG&E Texas Pipeline, L.P.) transmission and gathering lines in City rights-of-way) are "trespassing," and the Valero defendants must agree to a franchise or face removal by injunction.
Further, the City contends that it is entitled to compensation for the past presence of such pipelines in city property without consent, and for the use of such pipelines to facilitate the past and present sales of gas, both for resale and to direct end-users, by any person or entity other than the LDC. Additionally, the City contends that RGVG has breached the franchise agreement by failing to pay all franchise fees owed because it did not include in the "gross sales" figure such incidental revenues as bad check fees, late payment charges, hook-up and disconnect fees, and transportation revenues. The City seeks to assert against the Valero defendants derivative liability for all of RGVG's acts and omissions.
The latest pleading seeks actual damages in excess of $15 million, unspecified punitive damages, and injunctive relief against six Valero entities: Valero Energy Corporation (now known as GTT), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Natural Gas Company), Reata Industrial Gas Company (now known as Valero Gas Marketing Company), Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), and two SU entities.
Trial was originally set in the Edinburg matter for September 9, 1996, but did not commence due to the disqualification on August 21, 1996, of the original judge. The new judge has set a jury trial for June 15, 1998.
City of Mercedes v. Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.) and Reata Industrial Gas Company (now known as Valero Gas Marketing Company), 92nd State District Court of Hidalgo County, Texas.
A lawsuit filed by the City of Mercedes on April 16, 1997, is currently pending against Valero Gas Marketing Company and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.). On September 4, 1997, Mercedes amended its petition to include class action claims and requested to be named as class representative for a statewide class consisting of all Texas municipal corporations, municipalities, towns, and villages, excluding the cities of Edinburg and Weslaco (both of which filed separate actions), in which any of the defendants have sold or supplied gas, or used public rights-of-way to transport gas.
The defendants, gas marketers, have never owned or operated any pipelines. Plaintiff asserts these marketing companies have operated as "ghost pipelines" that have "used" public property without consent or franchise from the cities in which the defendants have sold gas. Plaintiff alleges that state law requires the defendants to have specific prior city consent by ordinance in order to transact business within or through city limits. The plaintiff alleges various tort and statutory claims against the defendants for failure to secure such consent. Plaintiff has requested a damage award, but has not specified an amount.
Defendants' motion to transfer venue to Bexar County, Texas, is currently pending. On September 10, 1997, defendants also filed a motion to disqualify or recuse the presiding judge of the 92nd State District Court. This motion was granted on November 26, 1997. A new judge has not been appointed yet. If a class is certified, defendants anticipate that they will challenge such certification.
Other Texas Franchise Fee Litigation
In addition to the three cases described above, involving the cities of Edinburg, Mercedes, San Benito, Primera, and Port Isabel, there are five lawsuits involving claims of a similar nature.
In 1996, the South Texas cities of Alton and Donna also independently intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd State District Court in Hidalgo County. Subsequently, in July 1996, these lawsuits were severed from the Edinburg lawsuit. The claims asserted by the cities of Alton and Donna are substantially similar to the Edinburg litigation claims. Damages are not quantified.
In December 1996, two additional lawsuits were filed in South Texas making allegations substantially similar to those in the City of Edinburg litigation: City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 92nd State District Court, Hidalgo County, Texas (filed December 27, 1996), and City of San Juan, City of La Villa, City of Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 93rd State District Court, Hidalgo County, Texas (filed December 27, 1996).
The City of La Joya filed its lawsuit on its own behalf and as a putative class representative on behalf of all similarly situated cities against the same defendants sued in the Edinburg case. The same Southern Union entities in the Edinburg suit have also been named in this suit.
The factual allegations and claims asserted in the lawsuit filed by the city of La Joya, and in the lawsuit filed by the cities of San Juan, Lavilla, Penitas, Edcouch, and Palmview, are similar to the claims made in the lawsuit filed by the cities of San Benito, Primera, and Port Isabel. Defendants' motion to transfer venue of both cases to Bexar County, Texas, is also currently pending.
Finally, on April 17, 1997, a petition was filed by the South Texas city of Weslaco. (City of Weslaco v. Reata Industrial Gas, L.P., et al., 92nd State District Court, Hidalgo County, Texas). Weslaco sued Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as Valero Gas Marketing Company), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) The causes of action alleged are identical to those alleged in the City of Mercedes case. Defendants' motion to transfer venue to Bexar County, Texas is currently pending. Defendants have also filed a motion to disqualify or recuse the presiding judge, which is also pending.
In 1996, the Texas city of Pharr sought and obtained class certification in a lawsuit styled City of Pharr, on behalf of itself and other Similarly Situated Entities v. Rio Grande Valley Gas Company, et al, 92nd Judicial District Court, Hidalgo County, Texas. By definition, the Pharr class consists only of those Texas cities, excluding Edinburg and McAllen, that have, or have had, natural gas franchises with RGVG or SU. The Pharr class was certified as to only two claims: breach of contract and declaratory relief dealing with the rights, status and legal relationship between plaintiff, the class members and the LDC regarding payment of franchise fees and use of granted easements. On December 30, 1997, the Pharr class certification order was affirmed on interlocutory appeal. In conjunction with this appeal, the appellate court specifically considered whether any of the Valero entities (now PG&E Gas Transmission, Texas Corporation entities) is a party to the Pharr class action and expressly found that such entities are not parties to that class action. Recently, however, Pharr class counsel has represented to various Texas courts that these entities were added to the Pharr class action as of December 9, 1997. As of February 25, 1998, none of these entities has been formally served in the Pharr class action, nor has counsel to these entities been furnished with a copy of the pleadings. However, the court's docket sheet shows a supplemental pleading was filed on or about December 12, 1997, which purports to add as defendants to the Pharr class action the same twenty-nine PG&E Corporation entities that are defendants in the San Benito litigation described above. The PG&E Corporation entities intend to defend vigorously against any attempt to add them as defendants in the Pharr class action, as well as against any attempt to modify the Pharr class definition in an effort to assert claims against the PG&E Corporation entities.
PG&E Corporation believes that the ultimate outcome of the Texas franchise fee cases described above will not have a material adverse impact on its financial position.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS
"Executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation are as follows:
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
"Executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and Electric Company are as follows:
All officers of Pacific Gas and Electric Company serve at the pleasure of the Board of Directors. During the past five years, the executive officers of Pacific Gas and Electric Company had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth on page 60 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 1997 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company has made no sales of unregistered equity securities in the last three years. PG&E Corporation has made the following sales of unregistered equity securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common stock. The shares were issued to nine former shareholders of Teco in connection with the acquisition of Teco by PG&E Corporation. PG&E Corporation owns all the outstanding shares of Teco as a result of the acquisition. The shares were issued in reliance upon the exemption from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the former shareholders of Teco represented that they were "accredited investors" as defined in Rule 501(a) under the Securities Act of 1933 and made other representations establishing the basis for the exemption. A legend as provided for by Rule 501(d)(3) was placed on each of the stock certificates representing the shares of PG&E Corporation common stock received by the former shareholders of Teco.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
A summary of selected financial information for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years is set forth on page 16 under the heading "Selected Financial Data" in the 1997 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company's earnings to fixed charges ratio for the year ended December 31, 1997, was 3.19. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the year ended December 31, 1997, was 2.96. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959, relating Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated results of operations and financial condition is set forth on pages 17 through 30 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information concerning PG&E Corporation's and Pacific Gas and Electric Company's market risk is set forth on page 28 in the table providing information about debt obligations and rate reduction bonds under the heading "Cash Flows From Financing Activities--Utility," and on page 30 under the heading "Price Risk Management" in the 1997 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information responding to Item 8 is contained in the 1997 Annual Report to Shareholders on pages 31 through 61 under the respective headings for each of PG&E Corporation and Pacific Gas and Electric Company, "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement
of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities," "Notes to Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," and "Report of Independent Public Accountants," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned "Executive Officers of the Registrant" contained on pages 50 through 52 in Part I of this report. Other information responding to Item 10 is included on pages 2 through 5 under the heading "Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and page 35 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 1998 Joint Proxy Statement relating to the 1998 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on page 8 under the heading "Compensation of Directors" and on pages 28 through 33 under the heading "Executive Compensation" (excluding the sections thereunder entitled "Nominating and Compensation Committee Report on Compensation," "Comparison of One-Year Total Shareholder Return," and "Comparison of Five-Year Cumulative Total Shareholder Return") in the 1998 Joint Proxy Statement relating to the 1998 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 10 and 11 under the heading "Security Ownership of Management" and on page 34 under the heading "Principal Shareholders" in the 1998 Joint Proxy Statement relating to the 1998 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on page 9 under the heading "Certain Relationships and Related Transactions" in the 1998 Joint Proxy Statement relating to the 1998 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, supplemental information, and report of independent public accountants contained in the 1997 Annual Report to Shareholders, are incorporated by reference in this report:
Statements of Consolidated Income for the Years Ended December 31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas and Electric Company.
Statements of Consolidated Cash Flows for the Years Ended December 31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1997, and 1996, for each of PG&E Corporation and Pacific Gas and Electric Company.
Statements of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities for the Years Ended December 31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas and Electric Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 60 of this Form 10-K.
3. Consolidated financial statement schedules:
I--Condensed Financial Information of Parent for the Year Ended December 31, 1997.
II--Consolidated Valuation and Qualifying Accounts of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 1997, 1996 and 1995.
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.
4. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation effective as of January 1, 1998.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 28, 1997 (Pacific Gas and Electric Company's Form 10-Q for quarter ended June 30, 1997 (File No. 1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company as of January 1, 1998.
4. First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2- 1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Asset Purchase Agreement by and among New England Power Company, The Narragansett Electric Company, and USGen Acquisition Corporation, dated as of August 5, 1997 (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609.
10.2 The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055.
*10.3 Agreement regarding certain payments between U.S. Generating Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609), Exhibit 10.2.) Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609. Confidential treatment of information omitted from this exhibit has been granted by the Commission until December 31, 1999. Omitted information has been filed separately with the Commission.
*10.4 PG&E Corporation Deferred Compensation Plan for Directors.
*10.5 PG&E Corporation Deferred Compensation Plan for Officers.
*10.6 The Pacific Gas and Electric Company Savings Fund Plan for Non-Union Employees, as amended and restated effective as of October 1, 1997.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and Electric Company, effective January 1, 1996 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1995 (File No. 1- 2348), Exhibit 10.7).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended October 15, 1997, effective January 1, 1998.
*10.9 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, as amended through October 16, 1991 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.11 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Pacific Gas and Electric Company's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.12 The Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (Pacific Gas and Electric Company's Form 10- K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.13 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998.
*10.14 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.15 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of January 1, 1998, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan.
*10.16 PG&E Corporation Executive Stock Ownership Program, effective January 1, 1998. - -------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1997 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company (portions of the 1997 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," and for each of PG&E Corporation and Pacific Gas and Electric Company, "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data (Unaudited)" included only) (except for those portions which are expressly incorporated herein by reference, such 1997 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein).
21. Subsidiaries of the Registrant (incorporated by reference from PG&E Corporation's Statement by Holding Company Claiming Exemption from the Public Utility Holding Act of 1935 under Rule 2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through 33 (File No. 1-12609).
23. Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1997, for PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1997, for Pacific Gas and Electric Company.
The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission as indicated and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1997, and through the date hereof:
1. October 16, 1997 Item 5. Other Events -- Performance Incentive Plan--Year-to-Date Financial Results
2. November 24, 1997 Item 5. Other Events A. Electric Industry Restructuring B. Gas Accord
3. December 19, 1997 Item 5. Other Events A. Electric Industry Restructuring B. CPUC Regulatory Proceedings C. Common Stock Repurchase Authorization
4. January 22, 1998 (As amended by Form 8-K/A dated February 5, 1998.) Item 5. Other Events A. Performance Incentive Plan--Year-to-Date Financial Results B. 1997 Consolidated Earnings (unaudited) C. Accelerated Stock Repurchase Program - -------- (1) Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and Electric Company) and Commission File Number 1-12609 (PG&E Corporation)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANTS HAVE DULY CAUSED THIS REPORT TO BE SIGNED ON THEIR BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND COUNTY OF SAN FRANCISCO, ON THE 5TH DAY OF MARCH, 1998.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant)
/s/ GARY P. ENCINAS /s/ GARY P. ENCINAS By _________________________________ By _________________________________ (Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in- Fact)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANTS AND IN THE CAPACITIES AND ON THE DATES INDICATED.
/s/ GARY P. ENCINAS *By ________________________________ (Gary P. Encinas, Attorney-in-Fact)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors of PG&E Corporation and Pacific Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in the PG&E Corporation and Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Annual Report on Form 10-K, and have issued our report thereon dated February 9, 1998. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in Part IV, Item 14. (a)(3) of this Annual Report on Form 10-K are the responsibility of the management of PG&E Corporation and of Pacific Gas and Electric Company and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP _______________________ ARTHUR ANDERSEN LLP
San Francisco, California February 9, 1998
(1) Deductions consist principally of write-offs. Reserve for deferred project costs and reserve for land costs are classified on the balance sheet in other noncurrents assets.
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
(3) Deductions consist principally of write-offs of expired leaseholds on reserved property. Deduction in 1995 results from sale of oil and gas properties.
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
(1) Deductions consist principally of write-offs. Reserve for deferred project costs and reserve for land costs are classified on the balance sheet in other noncurrent assets.
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
(3) Deductions consist principally of write-offs of expired leaseholds on reserved property. Deduction in 1995 results from sale of oil and gas properties.
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation effective as of January 1, 1998.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 28, 1997 (Pacific Gas and Electric Company's Form 10-Q for quarter ended June 30, 1997 (File No. 1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company as of January 1, 1998.
4. First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2- 1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Asset Purchase Agreement by and among New England Power Company, The Narragansett Electric Company, and USGen Acquisition Corporation, dated as of August 5, 1997 (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609.
10.2 The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055.
*10.3 Agreement regarding certain payments between U.S. Generating Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609), Exhibit 10.2.) Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609. Confidential treatment of information omitted from this exhibit has been granted by the Commission until December 31, 1999. Omitted information has been filed separately with the Commission.
*10.4 PG&E Corporation Deferred Compensation Plan for Directors.
*10.5 PG&E Corporation Deferred Compensation Plan for Officers.
*10.6 The Pacific Gas and Electric Company Savings Fund Plan for Non-Union Employees, as amended and restated effective as of October 1, 1997.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and Electric Company, effective January 1, 1996 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1995 (File No. 1- 2348), Exhibit 10.7).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended October 15, 1997, effective January 1, 1998.
*10.9 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, as amended through October 16, 1991 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.11 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Pacific Gas and Electric Company's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.12 The Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (Pacific Gas and Electric Company's Form 10- K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.13 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998.
*10.14 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.15 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of January 1, 1998, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan.
*10.16 PG&E Corporation Executive Stock Ownership Program, effective January 1, 1998. - -------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1997 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company (portions of the 1997 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," and for each of PG&E Corporation and Pacific Gas and Electric Company, "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data (Unaudited)" included only) (except for those portions which are expressly incorporated herein by reference, such 1997 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein).
21. Subsidiaries of the Registrant (incorporated by reference from PG&E Corporation's Statement by Holding Company Claiming Exemption from the Public Utility Holding Act of 1935 under Rule 2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through 33 (File No. 1-12609).
23. Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1997, for PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1997, for Pacific Gas and Electric Company.
The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission as indicated and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1997, and through the date hereof:
1. October 16, 1997 Item 5. Other Events -- Performance Incentive Plan--Year-to-Date Financial Results