ITEM 1. Business.
GENERAL
Corporate Structure and Business
PG&E Corporation is a holding company based in San Francisco, California, which provides energy services throughout North America. Effective January 1, 1997, Pacific Gas and Electric Company (sometimes referred to herein as the "Company") and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility primarily regulated by the California Public Utilities Commission (CPUC) and engaged principally in the business of providing electric and natural gas services throughout most of Northern and Central California. In the holding company reorganization, Pacific Gas and Electric Company's outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. Pacific Gas and Electric Company's debt securities and preferred stock were unaffected and remain securities of Pacific Gas and Electric Company.
The consolidated financial statements of PG&E Corporation incorporated herein include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries (collectively, PG&E Corporation). The consolidated financial statements of Pacific Gas and Electric Company incorporated herein include the accounts of Pacific Gas and Electric Company and its wholly owned and controlled subsidiaries. Because PG&E Corporation did not become the holding company for Pacific Gas and Electric Company until January 1, 1997, the 1996 consolidated financial statements represent the accounts of Pacific Gas and Electric Company on a consolidated basis as predecessor of PG&E Corporation.
The principal executive offices of PG&E Corporation are located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000.
As of December 31, 1998, PG&E Corporation had $33.2 billion in assets. PG&E Corporation generated $19.9 billion in operating revenues for 1998. As of December 31, 1998, PG&E Corporation and its subsidiaries and affiliates had approximately 23,300 employees. As of December 31, 1998, Pacific Gas and Electric Company had $23 billion in assets. The Company generated $8.9 billion in operating revenues for 1998. As of December 31, 1998, Pacific Gas and Electric Company had approximately 19,800 employees.
In addition to the regulated utility business of Pacific Gas and Electric Company, PG&E Corporation's other affiliated businesses include the ownership and operation of natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest and Texas, through various subsidiaries of PG&E Corporation (PG&E Gas Transmission or PG&E GT); the development, construction, operation, ownership, and management of independent power generation facilities through U.S. Generating Company, LLC and its affiliates (USGen); the purchase and sale of energy commodities and financial instruments to PG&E Corporation's other businesses, unaffiliated utilities, marketers, municipalities, cooperatives, independent power producers, and large end-use customers through PG&E Energy Trading Corporation and its affiliates (PG&E Energy Trading or PG&E ET); and the provision to customers nationwide with competitively priced natural gas and electricity and services to manage and make more efficient their energy consumption through PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES). On September 1, 1998, PG&E Corporation, through its indirect subsidiary, USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for approximately $1.59 billion plus $85 million for certain employee-related costs. See "Wholesale Operations of Affiliates-- Independent Power Generation" below.
The gas and electric utility operations of Pacific Gas and Electric Company represent the principal component of PG&E Corporation's business, contributing 45% of PG&E Corporation's total revenues in 1998. Pacific Gas and Electric Company's utility operations contributed $1.82 of PG&E Corporation's total 1998 earnings per share of $1.88.
Pacific Gas and Electric Company's utility service territory covers 70,000 square miles with an estimated population of approximately 13 million and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, financial services, food processing, petroleum refining, agriculture, and tourism.
At December 31, 1998, Pacific Gas and Electric Company served approximately 4.6 million electric customers. In 1998, Pacific Gas and Electric Company served its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, two nuclear power reactor units at Diablo Canyon Nuclear Power Plant (Diablo Canyon), 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. (In connection with the ongoing California electric industry restructuring, on July 1, 1998, the Company sold three fossil-fueled power plants which included six steam units and three combustion turbines. In late 1998 and in January 1999, the Company entered into agreements to sell three of its five remaining fossil-fueled power plants, which include 10 steam units and three combustion turbines, and its geothermal facilities. The sales are expected to be completed in 1999. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" below.) The Company also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal, and cogeneration. In addition, the Company is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling, and transmitting power.
Pacific Gas and Electric Company served approximately 3.8 million gas customers at December 31, 1998. Most of these customers continue to obtain gas supplies from the Company under regulated tariff rates. To ensure a diverse and competitive mix of natural gas supplies to serve customers that choose the Company as its supplier, the Company directly purchases gas from producers and marketers in both Canada and the United States. In 1998, about 68% of the Company's gas supply was purchased in Canada, about 4% was purchased in California, and about 28% was purchased in the U.S. Southwest.
In 1998, California became one of the first states in the nation to implement an electric industry restructuring plan. (The framework of this plan was established by Assembly Bill 1890 (AB 1890) passed by the California Legislature and signed by the Governor in 1996.) In California, electric customers may choose to purchase their electricity from investor-owned utilities (such as Pacific Gas and Electric Company), unregulated retail electricity providers (such as marketers, including PG&E Energy Services, brokers, and aggregators), or unregulated power generators, on a competitive basis (i.e., "direct access"). The California restructuring plan contemplates that the investor-owned utilities (such as Pacific Gas and Electric Company) will continue to provide distribution services to substantially all customers within their service territories. In November 1998, the California voters defeated Proposition 9, a voter initiative which would have overturned major portions of AB 1890 if it had been approved. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" below.
The following information includes forward-looking statements about the future that involve a number of risks and uncertainties. Words such as "estimates," "expects," "intends," "anticipates," and "plans," and similar expressions identify those statements which are forward-looking. These forward-looking statements are based on management's beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause actual results to differ materially from those contemplated in the forward-looking statements include, but are not limited to, the pace and extent of the ongoing restructuring of the electric and gas industries across the United States; the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring; any changes in the amount Pacific Gas and Electric Company is allowed to collect
(recover) from its customers for certain costs which prove to be uneconomic under the new competitive market (called transition costs) in accordance with the Company's plan for recovering those costs; the successful integration and performance of recently acquired assets; the Corporation's ability to successfully compete outside of the traditional regulated markets; the ability to lessen the risk of the impact of the Year 2000 on internal and external computer and software systems; the outcome of ongoing regulatory proceedings, including Pacific Gas and Electric Company's pending General Rate Case which will determine whether the Company will have the opportunity to earn its authorized rate of return, the Cost of Capital proceeding, which will determine the amount of return the Company will be authorized to earn on its assets and recover from ratepayers, the Company's proposal to adopt performance-based ratemaking, the Company's electric transmission rate case applications, and the CPUC's proceeding relating to the Company's affiliate transactions; fluctuations in commodity gas and electric prices and the ability to successfully manage such price fluctuations; and the pace and extent of competition in the California generation market and its impact on the Company's costs and resulting collection of transition costs. As the ultimate impacts of these and other factors is uncertain, these and other factors may cause future results to differ materially from results or outcomes currently expected or sought by PG&E Corporation.
Competition and the Changing Regulatory Environment
The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.
Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies have challenged the utilities' exclusive relationship with their customers and have sought to replace certain utility functions with their own. Customers, too, have asked for choice in their energy provider. These pressures have caused a move from the traditional regulatory framework to one in which competition is allowed in certain segments of the gas and electric industries.
In 1998, a significant portion of Pacific Gas and Electric Company's business was transformed from the traditional monopoly structure to a competitive operation. The return on Diablo Canyon and certain other generation assets continued to be significantly lower in 1998 than historical levels and will remain at this lower level throughout the transition period. See "Utility Operations--Electric Utility Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. The new competitive environment and the regulatory decisions made in the context of electric and gas industry restructuring will continue to affect PG&E Corporation's financial results and may result in greater earnings volatility. The changes in both the electric and gas industries, as described below, require the Company to develop and implement changes to its business processes and systems, including customer information and billing systems, to accommodate electric and gas industry restructuring. To the extent the Company is unable to successfully and timely develop and implement such changes, there could be an adverse impact on the Company's future results of operations.
Electric Industry
In 1998, California became one of the first states in the nation to implement an electric industry restructuring plan, the framework of which was established by AB 1890. Pursuant to AB 1890, on January 1, 1997, electric rates were frozen, at the levels in effect on June 10, 1996, until the earlier of March 31, 2002, or when the particular utility has recovered its generation-related transition costs (the transition period). The following key features of AB 1890 have been implemented:
--Mandatory unbundling of transmission, distribution, and generation services, although the utilities must continue to offer bundled electric service to customers who wish to continue receiving it from the utility.
--Commencement of operations of the California Power Exchange (PX) which provides a competitive auction process to establish a transparent market clearing price for electricity in California.
--Relinquishment of control (but not ownership or maintenance) of the utilities' transmission facilities to the California Independent System Operator (ISO).
--Commencement of operations of the ISO which ensures system reliability and provides electric market participants with open and comparable access to transmission services.
--A 10% reduction in the previously frozen rates, effective January 1, 1998, through the end of the transition period, for residential and small commercial customers.
--The issuance of rate reduction bonds in December 1997 to finance the 10% rate reduction.
--Collection of a nonbypassable charge (the competition transition charge or CTC) to provide the opportunity for utilities to recover their transition costs.
--Accelerated recovery of transition costs associated with utility-owned generation facilities.
--Commencement of direct access to competitive generation resources for all retail electric customers on March 31, 1998.
--Commencement of the market valuation process for utility-owned non- nuclear generation assets, to be completed by 2001.
For more information about California electric industry restructuring, see "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" below.
Other states also have moved forward with their electric industry restructuring plans to increase competition. PG&E Corporation's national energy strategy includes active pursuit of opportunities created by the gradual deregulation of the electric industry across the nation. PG&E Corporation's ability to anticipate and capture profitable business opportunities created by deregulation will have a significant impact on the Corporation's future operating results.
Additional information concerning electric industry restructuring and the financial impact of these changes on PG&E Corporation is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders.
Gas Industry
Restructuring of the natural gas industry on both the national and state levels has given customers greater options in meeting their gas supply needs. Regulators and legislators are using "unbundling" (separating the various services and the pricing of those services) to increase competition for non- monopoly energy services and to increase choices for customers. In the gas industry, Federal Energy Regulatory Commission (FERC) Order 636 required interstate pipeline companies to divide their services into separate sales, transportation, and storage services. Under Order 636, interstate pipelines must provide transportation service regardless of whether the customer (typically a local gas distribution company) buys the gas commodity from the pipeline.
During 1998, the California gas industry continued to be restructured pursuant to the Gas Accord Settlement, a multi-party agreement approved by the CPUC in 1997 (Gas Accord). The Gas Accord separates, or "unbundles," Pacific Gas and Electric Company's gas transmission services from its distribution services and changes the terms of service and rate structure for gas transportation. Unbundling gives noncore customers the opportunity to select from a menu of services offered by Pacific Gas and Electric Company and enables them to pay only for the services they use. Unbundling also makes access to the transmission system possible for all gas marketers and shippers, as well as noncore end-users. As a result, the transmission system is now more accessible to a greater number of customers.
Pacific Gas and Electric Company's customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from Pacific Gas and Electric Company. The Company's
transmission and distribution services historically have been "bundled," or sold together at a combined rate, within California. Most of Pacific Gas and Electric Company's industrial and larger commercial (noncore) customers now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers buy gas as well as transmission and distribution services from Pacific Gas and Electric Company as a bundled service. Customer rates for gas are updated on a monthly basis in order to reflect changes in Pacific Gas and Electric Company's gas procurement costs.
The Gas Accord increases opportunities for Pacific Gas and Electric Company's core customers to purchase gas from competing suppliers and, therefore, may reduce the Company's role in procuring gas for such customers. However, Pacific Gas and Electric Company will continue to procure gas as a regulated utility supplier for those customers who do not obtain gas supplies from an alternative provider.
Under the Gas Accord, Pacific Gas and Electric Company's core gas procurement costs for the period 1994 to 2002 are recoverable under a core procurement incentive mechanism (CPIM), a form of incentive regulation. The CPIM provides the Company with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are deemed reasonable and fully recoverable from ratepayers. If the Company's actual core procurement costs fall outside the tolerance band, the Company's ratepayers and shareholders share savings or costs, respectively.
The Gas Accord also established gas transmission and storage rates for the period from March 1, 1998, through December 31, 2002. During this period, Pacific Gas and Electric Company is at risk for revenue fluctuations resulting from variances in demand for noncore gas transmission throughput. Rates for distribution service continue to be set by the CPUC, and are designed to provide the Company an opportunity to recover its costs of service and include a return on investment.
In January 1998, the CPUC opened a rulemaking proceeding to expand market- oriented policies in the natural gas industry, including the further unbundling of services to promote competition, streamlining regulation for noncompetitive services, mitigating the potential for anti-competitive behavior, and establishing appropriate consumer protections. In August 1998, the Governor of California signed Senate Bill 1602, allowing the CPUC to investigate issues associated with the further restructuring of natural gas services. If the CPUC determines that further changes are in the public interest, it is required to submit its findings to the Legislature. Senate Bill 1602 prohibits the CPUC from adopting any decisions regarding gas industry restructuring until January 1, 2000. The CPUC has completed hearings dealing with market conditions and has indicated that it will issue a decision identfiying the most promising structural changes for further study. The CPUC will hold hearings in the future on safety issues associated with gas revenue cycle service unbundling and the costs and benefits associated with the most promising options. The CPUC then intends to conduct open public comment meetings, develop consumer protection rules, and submit a report to the Legislature setting forth its recommendations.
Additional information concerning gas industry restructuring, and the financial impact of these changes on PG&E Corporation, is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18.
Regulation of Pacific Gas and Electric Company
State Regulation
The CPUC consists of five members appointed by the Governor (although there are currently two vacancies) and confirmed by the State Senate for six-year terms. The CPUC regulates Pacific Gas and Electric Company's rates and conditions of service, sales of securities, dispositions of utility property, rate of return, rates of depreciation, uniform systems of accounts, long-term resource procurement, and transactions between Pacific Gas and Electric Company and its subsidiaries and affiliates. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies.
The California Energy Commission (CEC) has the responsibility to make electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a statewide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California. The CEC also administers funding for public purpose research and development, and renewable technologies programs. The funding will be collected from ratepayers through a nonbypassable public benefits charge. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring--Public Purpose Programs" below.
Federal Regulation
The Federal Energy Regulatory Commission (FERC) regulates electric transmission rates and access, operation of the California Independent System Operator and the California Power Exchange, compliance with the uniform systems of accounts, and electric contracts involving sales of electricity for resale. The FERC also has jurisdiction over Pacific Gas and Electric Company's electric transmission revenue requirements and rates. The FERC also regulates the interstate transportation of natural gas. Further, most of Pacific Gas and Electric Company's hydroelectric facilities are subject to licenses issued by the FERC.
The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant (Unit 3). NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities.
Licenses and Permits
Pacific Gas and Electric Company obtains a number of permits, authorizations, and licenses in connection with the construction and operation of its generating plants and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, FERC hydroelectric facility licenses, and NRC licenses are the most significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.
Regulation of PG&E Corporation and Other Subsidiaries
PG&E Corporation
PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the federal Public Utility Holding Company Act of 1935 (Holding Company Act) on the basis that PG&E Corporation and Pacific Gas and Electric Company are incorporated in the same state and their business is predominantly intrastate in character and carried on substantially in the state of incorporation. At present, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing Pacific Gas and Electric Company to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that Pacific Gas and Electric Company is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, Pacific Gas and Electric Company's dividend policy shall continue to be established by Pacific Gas and Electric Company's Board of Directors as though Pacific Gas and Electric Company were a comparable stand-alone utility company, and the capital requirements of Pacific Gas and Electric Company, as
determined to be necessary to meet Pacific Gas and Electric Company's service obligations, shall be given first priority by the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company. The conditions also provide that Pacific Gas and Electric Company shall maintain on average its CPUC- authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the utility's equity ratio by 1% or more.
A further condition of the CPUC's approval of the holding company formation was that an audit of affiliate transactions from 1994 to 1996 be conducted and supervised by the CPUC's Office of Ratepayer Advocates (ORA). The audit report, completed in November 1997, was critical of Pacific Gas and Electric Company's affiliate transaction internal controls and compliance. The report contained numerous recommendations for additional conditions to be imposed on the holding company. Pacific Gas and Electric Company has responded to the audit report, and the CPUC held hearings in 1998 to determine if the additional recommended conditions should be imposed on the holding company. On February 23, 1999, a CPUC administrative law judge (ALJ) issued a proposed decision which declines to adopt most of the recommended conditions, including all of the financial conditions contested by the Company. Instead, the ALJ's proposed decision directs the CPUC staff to prepare for the CPUC's consideration a draft CPUC order to institute a generic proceeding to determine whether the recommended financial conditions, or other appropriate financial conditions, should be imposed on all California electric and gas utilities within the CPUC's jurisdiction with respect to their holding company operations. The ALJ's proposed decision also proposes to require Pacific Gas and Electric Company to establish and maintain various accounting and internal control practices and systems with respect to affiliate transactions. A final CPUC decision is expected in early 1999.
On December 16, 1997, the CPUC issued a decision that adopted rules governing transactions between California's natural gas local distribution and electric utility companies and their non-regulated affiliates. This decision permits non-regulated affiliates of regulated utilities (such as PG&E Energy Services, the non-regulated energy marketing subsidiary of PG&E Corporation) to compete in the affiliated utility's service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The decision adopts complex and detailed rules requiring the separation of regulated utilities and their non-regulated affiliates, and also contains rules regarding information exchange among the affiliates and prohibits the utility from engaging in certain practices which would discriminate against energy service providers which compete with the utility's non-regulated affiliates. As required by the decision, Pacific Gas and Electric Company filed a comprehensive plan to comply with the affiliate transaction rules and on September 17, 1998, the CPUC approved parts of the plan and ordered that other parts be resubmitted. The Company has resubmitted its plan and expects the CPUC to act on the plan in early 1999.
On December 17, 1998, the CPUC issued a decision establishing specific penalties and enforcement procedures for affiliate rules violations. The decision included a new requirement that utilities self-report for affiliate rules violations, provided for an experimental advisory ruling process to be established, and established an informal inquiry and a formal complaint process.
Wholesale Operations of Affiliates
In addition to Pacific Gas and Electric Company, certain of PG&E Corporation's other subsidiaries which conduct interstate gas transmission and electric wholesale power marketing operations, are subject to FERC jurisdiction. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The FERC also regulates certain transportation transactions on the intrastate pipelines pursuant to Section 311 of the Natural Gas Policy Act of 1978.
The Railroad Commission of Texas (RRC) regulates gas utilities, including those owned by PG&E Corporation through PG&E Gas Transmission, Texas Corporation, (PG&E GTT), PG&E Gas Transmission Teco, Inc., and other affiliates operating in Texas. The RRC's gas proration rules govern the wellhead production and purchase of gas. Intrastate pipelines can provide intrastate gas transportation at negotiated rates which are
presumed just and reasonable. If the criteria for negotiated rates cannot be met, the RRC may assess a cost-of-service-based rate. The RRC also may regulate certain sales of gas. Currently, the price of natural gas sold under a majority of PG&E GTT's gas sales contracts is not regulated by the RRC. All transportation and gathering of gas is subject to the RRC Code of Conduct which prohibits undue discrimination among similarly situated shippers. Further, all transportation of gas, processing of gas, and transportation of natural gas liquids are subject to safety regulations enforced by the RRC and the Texas Natural Resource Conservation Commission.
In addition, the power generation projects that USGen develop, manage, or own are subject to differing types of federal regulation depending on the regulatory status of the particular project. Some of these projects are exempt wholesale generators (EWG) under the National Energy Policy Act of 1992, which status exempts the project from the Holding Company Act. EWG status is granted by the FERC upon application by the project. Some projects have received authority from the FERC to charge market-based rates for the power they sell, rather than traditional cost-based rates. Many of USGen's affiliated projects are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978. QF status exempts the project from regulation under various federal and state laws concerning the electric industry. USGen's projects are also subject to various federal, state, and local regulations concerning siting and environmental matters.
PG&E Corporation's indirect subsidiary, USGen New England, Inc. (USGenNE), acquired the electric generating facilities of the New England Electric System (NEES) in September 1998. USGenNE also is subject to numerous federal, state, and local statutes and regulations. USGenNE sells at wholesale all of the electricity it generates, as well as electricity it purchases from third parties under existing power sales agreements. Under the Federal Power Act ("FPA"), the FERC regulates these wholesale sales. The FERC has approved USGenNE's rate schedule as a market-based schedule and, accordingly, the FERC granted USGenNE waivers of certain other requirements that otherwise are imposed on utilities with cost-based rate schedules. In addition, USGenNE owns and operates a number of hydroelectric and pumped-storage projects that are licensed by the FERC. These licenses expire periodically and the projects must be relicensed at that time. USGenNE's licenses for these hydroelectric projects expire over a period from 2001 to 2020. Prior to the expiration of any one of the hydroelectric licenses, there is an opportunity for the existing licensee (as well as others interested in owning and operating the project) to apply for, and obtain, a new license.
USGenNE also is subject to limited regulation by certain state public utility commissions located in states where USGenNE owns and operates electric generating facilities. This regulation does not extend to its rates, which are regulated exclusively by the FERC, and the scope of this regulation has been substantially limited by various legislative initiatives.
Other regulatory matters are described throughout this report.
Capital Requirements and Financing Programs
PG&E Corporation and Pacific Gas and Electric Company continue to require capital for improvements to facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. PG&E Corporation's expenditures for these purposes, including the allowance for funds used during construction (AFUDC), were approximately $1,633 million for 1998. New investments totaled $1,779 million in 1998.
The following table sets forth estimated capital expenditures, as well as amounts for maturing debt and sinking funds, for PG&E Corporation subsidiaries for the years 1999 through 2001. The amount of capital expenditures for Pacific Gas and Electric Company (other than estimated capital expenditures for Diablo Canyon) include estimates prepared for the Company's GRC application now pending at the CPUC, excluding capital expenditures for divested fossil and geothermal power plants. The amount of capital expenditures for Pacific Gas and Electric Company shown in the table will be reduced if the CPUC authorizes base revenues significantly lower than those requested by the Company in its GRC filing.
- -------- (1) Utility capital expenditures include the estimates prepared for Pacific Gas and Electric Company's GRC but exclude capital expenditures for divested fossil and geothermal power plants. These numbers are shown net of reimbursed capital and include AFUDC.
(2) Other expenditures include those of PG&E GT, PG&E ES, PG&E ET, and USGen.
Most of the estimated capital expenditures for Pacific Gas and Electric Company for 1999 through 2001 are associated with short lead time capital expenditure projects aimed at the replacement and enhancement of existing facilities, and compliance with environmental laws and regulations. Also included are proposed expenditures to maintain and improve safety and reliability of Pacific Gas and Electric Company's electric transmission and distribution system, as well as proposed expenditures for major projects associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years 1999 through 2001 will include approximately $2.4 billion for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt, as indicated above.
The funds necessary for 1999-2001 capital requirements of PG&E Corporation and its subsidiaries will be obtained from (i) internal sources, principally net income before noncash charges for depreciation and deferred income taxes, and (ii) external sources, including short-term financing, such as bank loans and the sale of short-term notes, and long-term financing, such as sales of equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing review of their capital expenditures and financing programs. The amounts shown in the table above are forward-looking statements based on a number of assumptions and which are subject to various uncertainties. Actual amounts may differ materially based upon a number of factors, including the outcome of Pacific Gas and Electric Company's GRC filing, changes in assumptions about system load growth, rates of inflation, receipt of adequate and timely rate relief, availability and timing of regulatory approvals, total cost of major projects, availability and cost of suitable nonregulated investments, and availability and cost of external sources of capital, as well as the outcome of the ongoing restructuring in both the electric and gas industries.
Price Risk Management Programs
PG&E Corporation has an officer-level Price Risk Management Committee and has adopted a Risk Management Policy, approved by the Board of Directors of PG&E Corporation, for trading and risk management activities. The Price Risk Management Committee oversees implementation of the policy, approves the trading and price risk management policies of subsidiaries, and monitors compliance with the policy.
The Risk Management Policy allows derivatives to be used for both hedging and non-hedging purposes. (A derivative is a contract whose value is dependent on or derived from the value of some underlying asset.) PG&E Corporation uses derivatives for hedging purposes primarily to offset underlying commodity price risks. PG&E Corporation also participates in markets using derivatives to create liquidity and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. The Risk Management Policy and the trading and risk management policies of PG&E Corporation's subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset. PG&E Corporation also monitors the trading and risk management of PG&E ET, consistent with PG&E Corporation's Risk Management Policy. See "Wholesale Operations of Affiliates--Energy Trading."
In 1998, the CPUC granted authority to Pacific Gas and Electric Company to trade natural gas-based financial instruments to manage the influence of natural gas prices on the cost of electricity purchased under existing power- purchase contracts and to manage price and revenue risks associated with its natural gas transmission and storage assets, subject to certain conditions. The CPUC had previously granted authority to Pacific Gas and Electric Company to trade natural gas-based financial instruments to hedge the gas commodity price swings in serving core gas customers.
Additional information concerning price risk management activities and the financial impact of price risk management activities on PG&E Corporation and Pacific Gas and Electric Company is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18 and in Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements" beginning on page 46 of the 1998 Annual Report to Shareholders.
Year 2000 Matters
PG&E Corporation's Year 2000 compliance program generally is proceeding on schedule. However, if PG&E Corporation or third parties with whom PG&E Corporation or Pacific Gas and Electric Company have significant business relationships fail to achieve Year 2000 readiness with respect to mission- critical systems, there could be a material adverse impact on PG&E Corporation and Pacific Gas and Electric Company's financial position, results of operations, and cash flow.
Additional information concerning Year 2000 matters and the financial impact of Year 2000 matters on PG&E Corporation and Pacific Gas and Electric Company is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18.
UTILITY OPERATIONS
California Ratemaking Mechanisms
The CPUC authorizes an amount, known as "base revenues," to be collected from ratepayers to recover Pacific Gas and Electric Company's basic business and operational costs for its gas and electric operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, are currently authorized by the CPUC in General Rate Case (GRC) proceedings before the CPUC. During the GRC, which occurs every three years, the CPUC examines Pacific Gas and Electric Company's costs and operations to determine the amount of base revenue requirement the Company is authorized to collect from customers through base revenues. The revenue requirement is forecasted on the basis of a specified test year. (The return component of Pacific Gas and Electric Company's revenue requirement is computed using the overall cost of capital authorized in other proceedings.) Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase, which allocates revenue requirements and establishes rate levels for the different classes of customers. The Company's current GRC application pending at the CPUC is discussed below.
In December 1997, the CPUC adopted a cost-of-service-based ratemaking mechanism for determining Pacific Gas and Electric Company's revenue requirement for its hydroelectric and geothermal generation facilities. Under this mechanism, the revenue requirements for these facilities will be calculated as the sum of the capital-related revenue requirement (based on recorded capital costs), the expense revenue requirement (based on the current GRC-adopted expenses), and actual fuel expenses. A reduced rate of return on common equity of 6.77% applies to these facilities. This alternative revenue requirement mechanism will be in place through 2001, unless the CPUC determines otherwise.
Each year, Pacific Gas and Electric Company files an application with the CPUC to determine the authorized rate of return that the Company may earn on its assets (subject to the rates of return established for Diablo Canyon and non-nuclear generation-related assets discussed in the previous paragraph) and recover from ratepayers. On May 8, 1998, the Company filed its 1999 Cost of Capital application. Since (i) the CPUC separately reduced the rate of return on the Company's generation-related assets including Diablo Canyon, (ii) the FERC will authorize the rate of return for electric transmission assets at a later date (see discussion below), and (iii) gas transmission and storage rates have been set in the Gas Accord, the rate of return adopted in the 1999 Cost of Capital Proceeding only applies to the Company's electric and gas distribution assets. The Company has requested an increase in the rate of return on common equity to 12.10% and an overall utility return on rate base of 9.53% compared to the 1998 authorized returns of 11.20% and 9.17%, respectively. No request was made to change the capital structure for the Company, which continues to be composed of 48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. Other parties have recommended lower rates of return than the amounts requested. If the Company's requested increase is approved, the authorized cost of capital will increase 1999 authorized electric and gas revenue by $49.7 million and $15.5 million, respectively.
In November 1998, Pacific Gas and Electric Company filed an application with the CPUC to establish performance-based ratemaking (PBR) for electric and gas distribution services. If approved, the distribution PBR will establish electric and gas distribution revenue requirements for the years 2000 to 2004. The Company has proposed that the revenue requirement for the year 2000 be determined by applying a formula, based principally on inflation and productivity factors, to the 1999 GRC authorized revenue requirement. In subsequent years, the formula would be applied to the previous year's authorized revenue requirement. The proposed PBR also includes a sharing mechanism for earnings that are significantly above or below the authorized cost of capital, and a framework for rewards and penalties based upon the achievement of various performance measures. As the CPUC has indicated that a decision will not be issued until as late as May 2000, in February 1999, the Company requested interim relief to be effective starting January 2000.
The 1998 Annual Earnings Assessment Proceeding (AEAP), which determines shareholder incentives earned for Pacific Gas and Electric Company's 1996 and 1997 demand side management (DSM) programs, was submitted in May 1998. In the 1998 AEAP, the Company has requested an incentive payment of approximately
$39.8 million for the Company's 1997 DSM programs, to be trued-up and collected in installments over a 10-year period. After consolidating the adjusted incentive payment installments from prior years, the net revenue change in 1999 from DSM shareholder incentives should be an electric decrease of approximately $14.3 million and a gas decrease of approximately $2.5 million. A final CPUC decision is expected during the first quarter of 1999.
On January 7, 1999, Pacific Gas and Electric Company filed an application with the CPUC in its first Catastrophic Event Memorandum Account (CEMA) requesting increases in electric and gas revenue requirements of $60.1 million and $15.8 million, respectively, for costs incurred for several emergencies, including the 1997 storms. The Company has requested that these costs be included in rates effective January 1, 2000.
Electric Ratemaking
During 1998, the CPUC issued many decisions to implement electric industry restructuring and the new market structure, including decisions related to unbundling of rates, the recovery of transition costs, performance-based ratemaking (PBR), and other activities that affect rates and revenue requirements. Because electric rates are frozen, any change in Pacific Gas and Electric Company's electric revenue requirements (the amount of revenue required to pay certain costs) resulting from the items discussed below will not change electric customer rates. Under the electric rate freeze, the portion of total actual revenue that exceeds authorized base revenues and certain other authorized revenue requirements is available to recover transition costs. Therefore, increases in base revenues would reduce the amount of revenue available to recover transition costs. Conversely, decreases in base revenues would increase revenue available from frozen rates for recovery of transition costs.
General Rate Case. In Pacific Gas and Electric Company's GRC now pending before the CPUC, the Company is requesting increases in electric base revenues of $445 million over electric base revenues authorized in 1998 to reflect increasing levels of electric demand as well as customer growth in the service territory, the costs of continued and enhanced maintenance activities, and increased capital expenditures. The GRC electric revenue request includes proposed funding for distribution services, including system reliability and safety projects, increased distribution capacity (poles, wires, substations, etc.), equipment inspection and maintenance, a continuation of tree-trimming programs, and enhanced customer service and information technology systems. Since the FERC authorizes the rates collected from customers for electric transmission services, the GRC application does not seek approval of base revenues to recover the cost of transmission services. In December 1998, the CPUC issued a decision granting the requested increases on an interim basis effective January 1, 1999. This interim decision will be in effect until the CPUC issues its final decision, expected in June 1999. The interim decision allows the Company to reflect the increased revenue requirements in its balancing accounts to permit the Company to track the differences between actual revenue requirements in effect on January 1, 1999, and the requested revenue requirements. The interim decision did not increase electric rates.
Recovery of Transition Costs. On January 1, 1998, the Transition Revenue Account (TRA) was established. Within the TRA, revenue from frozen rates collected from ratepayers are allocated to transmission costs, distribution costs, the costs of public purpose programs, nuclear decommissioning costs, and energy procurement costs. Remaining revenues, if any, are transferred to the Transition Cost Balancing Account (TCBA) to offset transition costs. The CPUC established a separate annual proceeding, the Revenue Adjustment Proceeding (RAP), to review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and to make any necessary adjustments to reflect the authorized revenues that are approved in other proceedings. The RAP is a consolidation proceeding to verify that the outcomes from other proceedings are properly reflected and that the utilities accurately calculate the amount of revenues available to transfer to the TCBA to offset transition costs. On July 1, 1998, Pacific Gas and Electric Company filed an application with the CPUC in its first RAP requesting CPUC approval of entries made into the TRA from January 1 through May 31, 1998, and requesting approval of the Company's accounting, revenue allocation, and rate design proposals. On September 1, 1998, Pacific Gas and Electric Company also filed an application in its first Annual Transition Cost Proceeding (ATCP) requesting recovery of transition costs recorded in the TCBA from January 1 through June 30, 1998. This 1998 ATCP will verify the accounting and recording of costs and revenues in the TCBA and ensure that only eligible transition costs have been entered. Transition costs will receive a limited "reasonableness" review.
Electric Industry Restructuring Implementation Costs. Under AB 1890, certain electric industry restructuring implementation costs, that are found reasonable by the CPUC may be recovered from ratepayers. Eligible costs include FERC-authorized start-up and development costs of the ISO and PX, CPUC approved consumer education programs, and the costs of implementing direct access and demand PX billing and settlement systems. A multiparty settlement agreement filed with the CPUC on November 13, 1998, proposes that Pacific Gas and Electric Company would recover $40 million in 1997 and 1998 restructuring implementation costs during the rate freeze (on a revenue requirements basis). If recovery of these restructuring implementation costs during the rate freeze displaces recovery of transition costs, the settlement agreement proposes that Pacific Gas and Electric Company may recover up to $95 million of such displaced transition costs after the rate freeze. A proposed CPUC decision is expected in June 1999.
Revenues from Must-Run Contracts. The ISO has designated certain units at electric generation facilities as necessary to remain available and operational to maintain the reliability of the electric transmission system. These units are called "must-run" units. In general, the ISO dispatches these units under cost-based rate schedules that allow the owners to recover sunk costs and ongoing operating costs of the must-run units. Although still subject to FERC approval, the owners of must-run units choose among three forms of must-run rate schedules, all of which are premised upon a different mix of cost-based payments and revenues earned in the market.
Electric Transmission Revenues. Beginning in 1998, the FERC obtained jurisdiction to determine the annual amount of Pacific Gas and Electric Company's authorized revenue for transmission services that it may collect from customers. The Company expects to file an application with the FERC in March 1999 requesting 1999 electric transmission revenues of approximately $425 million, an increase of approximately 8% over transmission revenues sought by the Company and accepted, subject to refund, by the FERC in 1998.
Electric Deferred Refund Account (EDRA). In December 1996, the CPUC issued a decision establishing an EDRA. The CPUC ordered Pacific Gas and Electric Company to place into the EDRA credits for CPUC-ordered electric disallowances, the utility electric generation share of gas disallowances ordered by the CPUC or the FERC, and amounts resulting from reasonableness disputes or fuel-related cost refunds made to Pacific Gas and Electric Company based on regulatory agency decisions, plus interest charges. The Company requested, and the CPUC approved, an early refund of amounts accrued in EDRA in 1998. In 1998, the Company refunded approximately $36.4 million of EDRA refunds to customers.
Post-Rate Freeze Ratemaking Mechanisms. On January 15, 1999, Pacific Gas and Electric Company filed an application with the CPUC to determine the ratemaking mechanisms to be in effect after the end of the electric rate freeze period.
Additional information concerning Pacific Gas and Electric Company's transition cost recovery plan, and the financial impact of electric industry restructuring, is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders.
Gas Ratemaking
Gas Accord. As noted above (see "General--Competition and the Changing Regulatory Environment--Gas Industry"), the CPUC approved the Gas Accord in 1997. As part of the Gas Accord, the CPUC's traditional reasonableness reviews of Pacific Gas and Electric Company's core gas costs have been replaced with a CPIM (which also is discussed below in "Utility Operations--Gas Utility Operations--Core Procurement Incentive Mechanism") for the period from June 1, 1994, through 2002. Additional information concerning the potential financial impact of the Gas Accord is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18.
General Rate Case. The Company is requesting an increase in gas base revenues of $377 million, over base revenues authorized in 1998. The requested increase in base revenues reflects increasing levels of gas demand as well as customer growth in the service territory, the costs of continued and enhanced maintenance activities, and increased capital expenditures. The GRC gas base revenue request includes proposed funding for distribution system safety and reliability improvements, increased depreciation costs of the gas pipeline system, expanded customer service, and expanded customer and other information systems. In December 1998, the CPUC issued a decision granting the requested increase on an interim basis effective January 1, 1999. This interim decision will be in effect until the CPUC issues its final decision, expected in June 1999. The interim decision allows the Company to reflect the increased revenue requirements in its balancing accounts to permit the Company to track the differences between actual revenue requirements in effect on January 1, 1999, and the requested revenue requirements. The interim decision did not increase gas rates. However, gas customers would experience an increase in gas distribution rates if the CPUC approves the requested gas base revenue increase. The requested increase in gas base revenues will not result in an increase in customer gas transmission and storage rates, since the Gas Accord has set gas transmission and storage rates for the period from implementation of the Gas Accord through December 2002.
The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the proceeding in which distribution costs and balancing account balances are allocated to customers. The BCAP normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. Balancing accounts for natural gas costs accumulate differences between the actual recovery of gas costs and the revenues designed for recovery of such costs. Balancing accounts for sales volumes accumulate differences between authorized and actual base revenues. In 1997, Pacific Gas and Electric Company filed its 1998 BCAP application. In June 1998, the CPUC adopted a decision in the 1998 BCAP granting an annual $97.8 million revenue requirement decrease effective September 1, 1998, compared to revenues established by the Gas Accord on March 1, 1998. The overall annual revenue requirement for the two-year BCAP period (September 1, 1998, through August 31, 2000) is approximately $1.5 billion, of which an annual average of approximately $102 million is allocated for the collection of balancing accounts. The previous annual revenue requirement was approximately $1.8 billion, of which approximately $303 million was allocated for the collection of balancing accounts.
Electric Utility Operations
Implementation of Electric Industry Restructuring
In 1998, electric industry restructuring in California became effective with the commencement of operations of the California Independent System Operator (ISO) and the California Power Exchange (PX) on March 31, 1998.
Independent System Operator and Power Exchange
The ISO operates and controls most of the state's electric transmission facilities (which continue to be owned and maintained by the California utilities) and provides comparable open access to electric transmission service. The ISO accepts balanced supply and load schedules from market participants and manages the availability of electric transmission on a statewide basis for these transactions. The ISO also purchases necessary generation and ancillary services to maintain grid reliability.
In 1998, California's three largest investor-owned utilities relinquished operational control, but not ownership, of their transmission facilities to the ISO. The ISO is required to ensure reliable transmission services consistent with planning and operating reserve criteria no less stringent than those established by the Western Systems Coordinating Council and the North American Electric Reliability Council. Oversight responsibility for reliability of utility distribution systems remains with the CPUC.
The PX provides a competitive auction process to establish transparent market clearing prices for electricity in the markets operated by the PX. The three largest investor-owned utilities in California are required to sell into the PX all of their generated electric power. "Must-take" generation resources, such as nuclear generation,
electric power generated by QFs which the utilities are required to purchase under existing contractual commitments, are also scheduled through the PX. The utilities must then purchase all electric power for their retail customers through the PX. Customers who buy power directly from non-regulated suppliers pay for that generation based upon negotiated contracts. The PX sets a market clearing price for electricity by matching all demand load bids with supply bids ranked from lowest to highest. The highest-accepted generation supply bid used to serve load sets the PX market clearing price for electricity.
The FERC has jurisdiction over both the ISO and the PX. In October 1997, the FERC granted authority for the ISO and the PX to commence operations and approved the initial structure, rates, terms and conditions applicable to the new market structure. The ISO and PX both have made numerous tariff amendment filings with the FERC to address issues which arose after the commencement of ISO and PX operations. The FERC has acted on several of these filings and several remain pending.
The ISO and PX, California public benefit non-profit corporations, each has a Governing Board that includes representatives of investor-owned utility transmission systems, publicly-owned utility transmission systems, non-utility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives. The ISO and PX currently are overseen by a five-member Electricity Oversight Board which appoints the members of the ISO and PX Governing Boards. However, this appointment power has been rejected by the FERC and new bylaws for the ISO and the PX have been filed with the FERC which, if approved by the FERC, would eliminate this role of the Electricity Oversight Board.
Voluntary Generation Asset Divestiture
As part of the electric industry restructuring plan to promote a competitive electric generation market, California utilities, including Pacific Gas and Electric Company, have voluntarily begun divestiture of some of their generation assets. On July 1, 1998, Pacific Gas and Electric Company sold three electric generating plants with a combined capacity of 2,645 megawatts (MW): the Morro Bay Power Plant located in San Luis Obispo County, the Moss Landing Power Plant located in Monterey County, and the Oakland Power Plant located in Alameda County. The aggregate sale price for these three fossil- fueled plants was $501 million and the combined book value for these three plants was approximately $346 million as of July 1, 1998. Pacific Gas and Electric Company has retained liability for required environmental remediation of any preclosing soil or groundwater contamination at these plants.
In late 1998 and in January 1999, Pacific Gas and Electric Company agreed to sell three fossil-fueled generating facilities (the Pittsburg and Contra Costa power plants located in Contra Costa County, and the Potrero power plant in San Francisco) and its geothermal generating facilities (The Geysers Power Plant located in Lake and Sonoma Counties) for a combined sale price of $1.014 billion compared to their combined book value of approximately $523 million (as of December 31, 1998). The aggregate purchase price of the fossil-fueled power plants is $801 million. The purchase price for the Geysers geothermal facilities is $213 million. The sales are subject to approval by various regulatory agencies, including the CPUC, and are conditioned upon the transfer of various permits and licenses. The transactions are expected to close by the first half of 1999.
Together, the seven power plants represent 91% of Pacific Gas and Electric Company's fossil-fueled generating capacity and all of its geothermal generating capacity. The facilities generated approximately 31% of Pacific Gas and Electric Company's total electric energy production. The gain from the sale of these power plants will be used to offset Pacific Gas and Electric Company's transition costs.
As required by the California electric industry restructuring legislation, Pacific Gas and Electric Company employees, under two-year operations and maintenance agreements with the new owners, will continue to operate and maintain the power plants that are sold. To the extent that payments to the Company under these agreements exceed the Company's cost of operating the plants, the Company would offset other transition costs. Conversely, to the extent the Company's operating costs exceed the revenues from these agreements, the Company would have lower earnings.
In May 1998, Pacific Gas and Electric Company notified the CPUC that its non-nuclear generating facilities, including the hydroelectric facilities, will not be retained by the Company. In July 1998, the Company reached an agreement with the City and County of San Francisco regarding the Hunters Point fossil-fueled power plant, which the ISO has designated as a "must run" facility. The agreement expresses the Company's intention to retire the plant when it is no longer needed by the ISO. In December 1998, the Company asked the CPUC to allow it to hire appraisers to determine the market value of the hydroelectric system. Under the Company's proposal, the Company would have the option of accepting the appraised value and transferring the assets to another unit of PG&E Corporation or rejecting the appraised value and auctioning the assets. The Company expects the CPUC to issue a decision on the appraisal process in 1999.
Direct Access
Although the restructuring legislation contemplated that direct access would begin on January 1, 1998, the ISO and PX delayed the commencement of operations until March 31, 1998. Customers participating in direct access may purchase their electric power directly either through (1) competing non- utility retail electric providers such as brokers, marketers, aggregators, or other retailers, or (2) direct negotiated contracts with electric generators. All customers (with limited exceptions), whether they choose direct access or not, must pay the nonbypassable CTC, which will be collected by their distribution utility in connection with recovery of the utilities' transition costs. Utilities began accepting requests for direct access in November 1997 to become effective after direct access began. As of February 24, 1999, Pacific Gas and Electric Company had transferred 53,990 customers to direct access. The CPUC requires that electric customers with an electricity demand, or load, of 50 kilowatts (kW) or more must have meters that are capable of providing hourly data in order to participate in direct access. Those customers with a load less than 50 kW may participate in direct access either through "load profiling" or by installing an hourly meter. (Load profiling approximates the pattern of electricity usage for a given customer class and provides the equivalent of hourly meter reads.) The customer is responsible for the cost of the meter and the meter installation.
Energy service providers supplying the direct access market may choose one of three billing options: (1) consolidated energy supplier billing, under which the utility bills the energy supplier for the services provided directly by the utility to the customer, and the supplier, in turn, provides a consolidated bill to the customer, (2) consolidated distribution company billing, under which the utility places the supplier's energy charge on a distribution bill, or (3) dual billing, under which the energy supplier and the utility bill separately for their own services. Since January 1, 1998, energy service providers have been allowed to provide metering services to their customers with a demand greater than 20 kW, and beginning January 1, 1999, energy service providers may provide metering to all of their customers.
During 1998, Pacific Gas and Electric Company continued its efforts to develop and implement changes to its business processes and systems, including customer information and billing systems, to accommodate direct access. To the extent the Company is unable to successfully and timely develop and implement such changes, there could be an adverse impact on the Company's future results of operations.
Electric Base Revenue Increase
AB 1890 provides for an increase in Pacific Gas and Electric Company's electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. The CPUC authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC authorized an additional base revenue increase of $77 million, for a total authorized base revenue increase for 1997 and 1998 of $406 million. The recovery of these amounts from ratepayers is subject to a reasonableness review by the CPUC. In May 1998, the Company filed its report on 1997 expenditures with the CPUC seeking review of approximately $183 million for costs incurred in 1997 for safety and system reliability enhancements, which exceeded the 1997 authorized revenue requirement by approximately $19 million. On January 29, 1999, the ORA issued its report on the claimed expenditures and recommended that a total of approximately $50 million, including the $19 million amount overspent, be disallowed, for a net recommended disallowance of $31 million. Under AB 1890, the
disallowance or underspending of the 1997 revenue requirement, if adopted by the CPUC, would be credited as an expense against the 1998 authorized revenue requirement. To the extent that 1998 expenditures (including any amounts carried over from 1997) exceed the 1998 authorized revenue requirement, the amount overspent would not be recoverable from ratepayers. The Company plans to file its report on 1998 expenditures seeking review of its 1997 and 1998 costs for safety and system reliability enhancements in March 1999.
Rate Levels and Rate Reduction Bonds
To achieve the 10% rate reduction for residential and eligible small commercial customers, effective January 1, 1998, AB 1890 authorized utilities to finance a portion of their transition costs with "rate reduction bonds." On December 8, 1997, a special purpose entity established by the California Infrastructure and Economic Development Bank issued $2.9 billion of rate reduction bonds on behalf of a wholly owned subsidiary of Pacific Gas and Electric Company. The bonds were issued in eight classes with maturities ranging from 10 months to 10 years, and bearing interest at rates ranging from 5.94% to 6.48%. Pacific Gas and Electric Company is collecting a separate nonbypassable charge on behalf of the bondholders to recover principal, interest, and related costs over the life of the bonds from residential and small commercial customers. The bond proceeds were used by the wholly owned subsidiary to purchase from Pacific Gas and Electric Company the right to be paid the revenues from this separate charge. The bonds are secured by the future revenue from the separate charge and not by Pacific Gas and Electric Company's assets. While the bonds are reflected as long-term debt on Pacific Gas and Electric Company's balance sheet, creditors of Pacific Gas and Electric Company do not have any recourse to the revenues from the separate charge.
In November 1998, the California voters defeated a voter initiative known as Proposition 9. If it had passed, Proposition 9 would have, among other things, (i) required investor-owned California utilities to provide an additional 10% rate reduction to residential and small commercial customers, (ii) eliminated transition cost recovery for nuclear investments by utilities (other than reasonable decommissioning costs), (iii) restricted transition cost recovery for non-nuclear investments (other than costs associated with QFs), unless the CPUC found that the utility would be deprived of the opportunity to earn a fair rate of return, and (iv) prohibited the collection of any customer charges for rate reduction bonds, or alternatively, required the utility to offset such charges with an equal credit to customers.
Recovery of Transition Costs
Under electric industry restructuring, utilities are authorized to recover their transition costs--the utilities' costs of their generation-related assets and obligations which prove to be uneconomic in the new competitive framework. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above-market sunk costs (sunk costs are costs associated with utility generating facilities that are fixed and unavoidable and currently included in customer rates), and future sunk costs, such as costs related to plant removal; (2) costs associated with long-term contracts to purchase power at above-market prices from QFs and other power suppliers; and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) Transition costs are eligible for recovery from all customers (with certain exceptions) through a nonbypassable competition transition charge, or CTC, included as part of rates. Transition costs that are disallowed by the CPUC for collection from customers will be written off.
As a prerequisite to any consumer obtaining direct access services, the consumer must agree to pay its applicable nonbypassable CTC. Further, nuclear decommissioning costs are being recovered through a separate CPUC-authorized charge. Most transition costs must be recovered by December 31, 2001, although certain transition costs may be recovered after December 31, 2001. These costs include certain employee-related transition costs, costs that are unrecovered as result of the implementation of direct access and creation of the PX and ISO, and above-market costs associated with power-purchase agreements. In addition, costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds.
The total amount of sunk costs to be included as transition costs will be based on the aggregate of above-market and below-market values of utility- owned generation assets and obligations. Under AB 1890, valuation of generation-related assets through appraisal or sale must be completed by December 31, 2001. In 1997, the value of three of Pacific Gas and Electric Company's electric facilities was established through the auction process. In 1998, the value of four of the Company's remaining power plants and its geothermal facilities also has been established by the auction process, subject to CPUC approval. In October 1998, the CPUC ruled that the market value of the Hunters Point power plant is zero. In December 1998, the Company filed an application with the CPUC requesting approval for the Company to hire appraisers to establish a market value for the Company's hydroelectric facilities.
In September 1997, the CPUC adopted a decision addressing transition cost recovery for capital additions to Pacific Gas and Electric Company's non- nuclear generating facilities. The decision allows Pacific Gas and Electric Company to recover costs of capital additions made in 1996 and 1997 (and in 1998 for fossil-fueled plants completely divested by March 31, 1998) based upon an after-the-fact reasonableness review. All capital additions found reasonable by the CPUC through this process will be recoverable as transition costs. Capital additions made in 1998 and thereafter to non-nuclear generation-related assets, and capital additions made to fossil-fueled generating assets which are not completely divested by March 31, 1998, must be recovered either through revenues from the ISO agreements for "must-run" plants or from sales of electricity to the PX. The CPUC decision allows Pacific Gas and Electric Company to seek an after-the-fact reasonableness review of post-1997 capital addition expenditures for collection as transition costs in certain limited circumstances. In May 1998, the CPUC approved $53 million in 1996 non-nuclear generation capital additions as eligible for recovery as transition costs. Further, a multiparty settlement agreement filed with the CPUC on January 8, 1999, proposes that Pacific Gas and Electric Company would recover approximately $128.5 million of its $133 million request for recovery of 1997 and first quarter 1998 capital additions. A CPUC decision on the 1997 and first quarter 1998 capital additions is expected in 1999.
In 1997, to reflect the accelerated recovery of transition costs related to non-nuclear generation-related assets, including hydroelectric and geothermal facilities, and for Diablo Canyon, the CPUC reduced the authorized rate of return on common equity for these assets to 6.77%. The reduced rate of return will be effective for the duration of the transition period.
During 1998, proceedings commenced at the CPUC to review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and to make any necessary adjustments to reflect the authorized revenues that are approved in other proceedings. An annual proceeding also was established to verify the accounting and recording of transition costs and revenues available for recovery of transition costs and to ensure that only eligible transition costs have been entered. In this proceeding, transition costs will receive a limited "reasonableness" review.
Public Purpose Programs
On January 1, 1998, and continuing through December 31, 2001, energy efficiency, research and development, and low-income programs are being funded through a separate nonbypassable charge included in frozen electric rates, in compliance with AB 1890. Low-income programs are funded at the level of need, but are not to be funded at less than the 1996 level of expenditures. Under this provision of AB 1890, Pacific Gas and Electric Company is obligated to fund through electric rates energy efficiency and conservation programs in an amount not less than $106 million per year, public interest research and development programs at not less than $30 million per year, renewable technologies at not less than $48 million per year, and low-income energy efficiency programs at not less than $14 million per year. The California Alternative Rates for Energy (CARE) low-income discount rate, a rate subsidy paid for by the Company's other customers, is currently about $31 million per year.
The California Energy Commission (CEC) administers the public interest research and development program and the renewable program. The CPUC has set up public member boards to advise the CPUC on public purpose programs related to energy efficiency and low-income programs. Initially, these boards also were
assigned to solicit competitive bids to determine who will administer the programs in place of the utility's interim administration. However, the CPUC appointed Pacific Gas and Electric Company as interim administrator of energy efficiency and low-income programs for 1999. The CPUC recently has issued a draft decision which, if adopted, would continue the Company's interim administration of these programs through the end of the transition period.
Additional information concerning AB 1890 and its financial impact on PG&E Corporation is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders.
Electric Operating Statistics
The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
The following table shows certain customer information:
Electric Generating Capacity
As described above in "Implementation of Electric Industry Restructuring-- Voluntary Generation Asset Divestiture," in 1998, Pacific Gas and Electric Company sold three fossil-fueled power plants and entered into agreements for the sale of an additional four fossil-fueled power plants and its geothermal facilities. Except as otherwise noted below, as of December 31, 1998, Pacific Gas and Electric Company owned and operated the following generating plants, all located in California, listed by energy source:
- -------- (1) In 1998, Pacific Gas and Electric Company entered into agreements to sell these power plants and its geothermal facilities in connection with electric industry restructuring.
(2) Listed to show capability; subject to relocation within the system as required.
(3) The Geysers Power Plant net operating capacity is based on adequate geothermal steam supply conditions. (Present steam conditions prevent the units from operating at full operating capacity.)
Diablo Canyon
Diablo Canyon Operations
Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. The operating license expiration dates for Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively. As of December 31, 1998, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 81.4% and 82.9%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next five years. Diablo Canyon refueling outages typically are scheduled every 19 to 21 months. Pacific Gas and Electric Company has been seeking NRC licensing authority to schedule such outages once every 24 months. Though nominal 20- month cycles are firm, achieving a 24-month cycle is uncertain and its implementation could be delayed. The schedule below assumes that a refueling outage for a unit will last approximately five weeks, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages or changes in the length of the fuel cycle.
Diablo Canyon Ratemaking
Effective January 1, 1997, Pacific Gas and Electric Company's sunk costs in Diablo Canyon are recovered from ratepayers through a sunk cost revenue requirement, at a reduced return on common equity equal to 6.77% that will remain in effect through the end of the transition period. (Sunk costs are costs associated with the facility that are fixed and unavoidable and currently included in customers' electric rates.) Also effective January 1, 1997, a performance-based Incremental Cost Incentive Price (ICIP) mechanism was established to recover Diablo Canyon's variable and other operating costs and capital addition costs. The ICIP mechanism establishes a rate per kWh generated by the facility. This rate is based upon a fixed forecast of ongoing costs, capital additions, and capacity factors for the period 1997 through 2001. The fixed forecast of ICIP for 1999-2001 is shown below. The revenues are based on an assumed capacity factor of 83.6%.
Incremental Cost Incentive Prices and Estimated Total CPUC Revenue Requirement
The CPUC decision adopting the ratemaking mechanism excluded several items totaling $160 million from the sunk cost revenue requirement, including out- of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The CPUC decision requires that the costs of materials, supplies, and nuclear fuel be recovered through the ICIP mechanism as these items are used. The CPUC also disallowed about $70 million in plant costs from the sunk cost revenue requirement.
The CPUC decision also ordered that a financial verification audit of Diablo Canyon plant accounts be performed by an independent accounting firm, and that the CPUC hold a proceeding to review the results of the audit, including any proposed adjustments to Diablo Canyon accounts, following the completion of the audit. On August 31, 1998, an independent accounting firm retained by the CPUC completed its financial verification audit of Diablo Canyon plant accounts at December 31, 1996. The audit resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review the results of the audit and may seek to make adjustments to Diablo Canyon sunk costs subject to transition cost recovery. At this time, the amount of transition cost disallowances, if any, cannot be predicted.
Additional information concerning the financial impact of Diablo Canyon ratemaking is included in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders.
Nuclear Fuel Supply and Disposal
Pacific Gas and Electric Company has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well as one contract for fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, the conversion of uranium to uranium hexaflouride, and the enrichment of the uranium hexaflouride to enriched uranium will be satisfied by a combination of existing contracts and inventories through 2002, 2000, and 2002, respectively. The fuel fabrication contract for the two units will supply their requirements for the next seven operating cycles of each unit. These contracts are intended to ensure long- term fuel supply, but permit Pacific Gas and Electric Company the flexibility to take advantage of short-term supply opportunities. In most cases, Pacific Gas and Electric Company's nuclear fuel contracts are requirements-based, with the Company's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, Pacific Gas and Electric Company signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Company's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has been unable to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted by the DOE for interim or permanent storage before 2010, at the earliest. At the projected level of operation for Diablo Canyon, Pacific Gas and Electric Company's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2006. Pacific Gas and Electric Company is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility.
In July 1988, the NRC gave final approval to Pacific Gas and Electric Company's plan to store radioactive waste from the nuclear generating unit (Unit 3) at Humboldt Bay Power Plant (Humboldt) at Humboldt prior to ultimately decommissioning the unit. The Company has agreed to remove all spent fuel when the federal disposal site is available.
Insurance
Pacific Gas and Electric Company has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL, which is owned by utilities with nuclear generating facilities, provides insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. Under these insurance policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Company may be subject to maximum retrospective premium assessments of $17 million (property damage) and $5 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NEIL.
Pacific Gas and Electric Company has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $9.6 billion of coverage is provided by secondary financial protection required by federal law and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, Pacific Gas and Electric Company may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident.
Decommissioning
Pacific Gas and Electric Company's estimated total obligation to decommission and dismantle its nuclear power facilities is $1.5 billion in 1998 dollars ($5.1 billion in future dollars). This estimate, which includes labor, materials, waste disposal charges, and other costs, is based on a 1997 decommissioning cost study. A contingency to capture engineering, regulatory, and business environment changes is included in the total estimated obligation. Actual decommissioning costs are expected to vary from this estimate because of changes in the assumed dates of decommissioning, regulatory requirements, and technology, as well as differences in the amount of labor, materials, and equipment needed to complete decommissioning. The estimated total obligation needed to complete decommissioning is recognized proportionately over the license term of each facility.
Nuclear decommissioning costs recovered in rates are placed in external trust funds. These funds, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the nuclear facilities. The trust funds maintain substantially all of their investments in debt and equity securities. All earnings on the trust fund, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Monies may not be released from the external trust funds until authorized by the CPUC. In December 1997, the CPUC granted Pacific Gas and Electric Company's request for authority to disburse up to $15.7 million from the Humboldt Bay Power Plant decommissioning trust funds to finance three partial nuclear decommissioning projects at Humboldt Bay Power Plant Unit 3. Accordingly, as of December 31, 1998, $7.2 million (net of taxes) was disbursed from the Humboldt Bay Power Plant Unit 3 non-tax-qualified trust to reimburse the Company for nuclear decommissioning expenses associated with the partial decommissioning projects.
In its 1999 GRC, Pacific Gas and Electric Company is seeking approval from the CPUC to use the tax savings resulting from the payment of tax-deductible nuclear decommissioning expenses from the Humboldt Bay Power Plant Unit 3 non- tax-qualified trust to fund nuclear decommissioning work. If the CPUC rejects the Company's request, an additional $4.9 million will be disbursed from the trust to reimburse the Company for the full amount of the 1998 nuclear decommissioning expenses of $12.1 million. A mechanism to flow the realized tax savings of $4.9 million associated with $12.1 million tax-deductible nuclear decommissioning expenses to ratepayers will be established.
As of December 31, 1998, Pacific Gas and Electric Company had accumulated external trust funds with an estimated fair value of $1.2 billion, based on quoted market prices and net of deferred taxes on unrealized gains, to be used for the decommissioning of the Company's nuclear facilities.
The amount recovered in rates for nuclear decommissioning costs is authorized by the CPUC as part of the GRC. The CPUC considers the trusts' asset levels, together with revised earnings and decommissioning cost
assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trusts. The monies contributed to the decommissioning trusts, together with existing trust fund balances and projected earnings, are intended to satisfy the estimated future obligation for decommissioning costs. For the year ended December 31, 1998, nuclear decommissioning costs recovered in rates were $33 million.
Beginning January 1, 1998, nuclear decommissioning costs, which are not transition costs, were being recovered through a nonbypassable charge which will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. The CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and to establish the annual revenue requirement and attrition factors over subsequent three-year periods when and if GRCs are discontinued.
Other Electric Resources
QF Generation and Other Power-Purchase Contracts
By federal law, Pacific Gas and Electric Company is required to purchase electric energy and capacity provided by independent power producers. The CPUC established a series of power-purchase contracts and set the applicable terms, conditions, price options, and eligibility requirements.
Under these contracts, Pacific Gas and Electric Company is required to make payments only when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. Pacific Gas and Electric Company's contracts with these power producers expire on various dates through 2028. Total energy payments are expected to decline in the years 1999 through 2001. Total capacity payments are expected to remain at current levels during this period. Deliveries from these power producers account for approximately 23% of Pacific Gas and Electric Company's 1998 electric energy requirements and no single contract accounted for more than 5% of the Company's energy needs.
Pacific Gas and Electric Company has negotiated early termination or suspension of certain power-purchase contracts. These amounts are expected to be recovered in rates and as such are reflected as deferred charges on the Company's balance sheet. At December 31, 1998, the total discounted future payments remaining under early termination or suspension contracts is $48 million.
Pacific Gas and Electric Company also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Company must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the provider's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. The total cost of these payments is recoverable in rates. At December 31, 1998, the undiscounted future minimum payments under these contracts are $32 million for each of the years 1999 through 2003 and a total of $280 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 7.5% of Pacific Gas and Electric Company's 1998 electric energy requirements.
The amount of energy received and the total payments made under all these power-purchase contracts were:
As of December 31, 1998, Pacific Gas and Electric Company had commitments to purchase approximately 5,200 MW of capacity under CPUC-mandated power-purchase agreements. Of the 5,200 MW, approximately
4,400 MW were operational. Development of the majority of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 4,400 MW of operational capacity consists of 2,800 MW from cogeneration projects, 600 MW from wind projects, and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric.
Geothermal Generation
In late 1998 and January 1999, Pacific Gas and Electric Company entered into agreements to sell its geothermal units at The Geysers Power Plant located in Lake and Sonoma counties (Geysers) for a total of $213 million. The sale is subject to final approval by the CPUC and other regulatory agencies, and the transaction is expected to close by the first half of 1999. See "Electric Utility Operations--Implementation of Electric Industry Restructuring-- Voluntary Generation Asset Divestiture" above.
The Geysers are forecast to operate at reduced capacities because of declining geothermal steam supplies and curtailment of the Geysers due to the existence of more economic sources of electric generation. The Company's agreements with several of its steam suppliers permit the Company to curtail generation at the Geysers at the Company's discretion. The 1999 consolidated Geysers capacity factor through the expected close of sale is forecast to be approximately 38% of installed capacity in 1999, which includes economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 44% in 1998.
Electric Transmission and Distribution
To transport energy to load centers, Pacific Gas and Electric Company as of December 31, 1998, owned and operated approximately 18,624 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 39,565,906 kilovolt-amperes (kVa), including spares, excluding power plant interconnection facilities. Energy is distributed to customers through approximately 112,080 circuit miles of distribution system and distribution substations having a capacity of approximately 23,575,800 kVa.
In 1998, the utilities relinquished control, but not ownership, of their transmission facilities to the ISO. The ISO commenced operations on March 31, 1998. The ISO, regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. In 1998, the FERC approved the various forms of agreements for must-run facilities that have been entered into between the utilities and the ISO to ensure grid reliability.
The FERC has also approved a proposal from Pacific Gas and Electric Company and the other California utilities that distinguishes between local distribution facilities and transmission facilities. The order defines jurisdiction for the CPUC over local distribution and retail power customers. The FERC will have jurisdiction over the transmission facilities as defined in the order and over the transmission aspects of retail direct access. Most of Pacific Gas and Electric Company's distribution services will remain subject to CPUC jurisdiction.
On December 17, 1998, the CPUC opened a rulemaking proceeding to consider whether it should pursue further reforms in the structure and regulatory framework governing electricity distribution service. The CPUC will solicit comments and proposals regarding the scope and substance of issues, possible policy options, and procedural steps the CPUC could pursue in considering distributed generation and competition in electric distribution service. The rulemaking was opened, in part, in response to a request from Pacific Gas and Electric Company for a comprehensive review of distribution competition. Initial comments are due to the CPUC on March 17, 1999.
On December 8, 1998, Pacific Gas and Electric Company lost power on all its 115 kV transmission lines from the San Mateo Substation to San Francisco, and the two San Francisco power plants tripped off line, leaving more than 456,000 customers without power. The Company immediately notified the ISO of the outage. Only the approximately 13,000 customers served from the 230 kV transmission line maintained power. Six hours later, the Company had restored service to all but 27,000 customers. Within the next two hours, all customers had power.
Pacific Gas and Electric Company immediately began an internal investigation of the outage. On December 17, 1998, the CPUC issued an Order Instituting Investigation concerning the power outage. The order required Pacific Gas and Electric Company to file a report by January 25, 1999 to address various issues arising from the outage, including chronology, cause, response, mitigation, prevention, and handling of claims.
On January 25, 1999, the Company completed its internal investigation and filed a report with the CPUC detailing the results of its investigation. The Company's internal investigation confirmed that the outage resulted when a construction crew working on an equipment upgrade project at the San Mateo Substation failed to follow established procedures and practices, and failed to remove temporary protective grounds. Separately, a transmission operator at the substation then energized the substation bus, but failed to engage the protective relays associated with the bus. (A "bus" refers to a collection point for connecting transmission lines and flowing power out from a substation.) Without the local protective system in place, the electric current was sent to ground, and the system took a half second to isolate the fault instead of the one-tenth of a second that would normally be required. This delay resulted in a sharp drop in transmission line voltages, and the transmission system into San Francisco then experienced large power fluctuations. As they are designed to do, protective systems at other substations and at the Hunters Point and Potrero power plants separated from the transmission system to make sure that the fluctuations did not extend to other parts of the Company's system, and that no damage occurred to equipment in San Francisco's electric facilities that could have delayed restoration of operations.
Pacific Gas and Electric Company is taking actions to strengthen and adjust its grounding and switching procedures as preventative measures to minimize the risk that such an initiating event could occur in the future. The Company's internal investigation found that the transmission system design is consistent with the requirements of the North American Electric Reliability Council and the Western Systems Coordinating Council, and performed as designed given the initiating event that occurred. As a result of this finding, the Company is not proposing modifications to the system design. Finally, the Company and the ISO are using the lessons learned in this event to strengthen their communications.
Gas Utility Operations
Pacific Gas and Electric Company owns and operates an integrated gas transmission, storage, and distribution system in California. At December 31, 1998, Pacific Gas and Electric Company's system, including the PG&E Expansion (Line 401), consisted of approximately 5,706 miles of transmission pipelines, three gas storage facilities, and approximately 37,023 miles of gas distribution lines.
Pacific Gas and Electric Company's peak day send-out of gas on its integrated system in California during the year ended December 31, 1998, was 4,300 million cubic feet (MMcf). The total volume of gas throughput during 1998 was approximately 850,000 MMcf, of which 295,000 MMcf was sold to direct end-use or resale customers, 158,000 MMcf was used by Pacific Gas and Electric Company primarily for its fossil-fueled electric generating plants, and 397,000 MMcf was transported as customer-owned gas.
The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities as a result of a CPUC order. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years.
The 1998 California Gas Report updates Pacific Gas and Electric Company's annual gas requirements forecast (excluding bypass volumes) for the years 1998 through 2015, forecasting average annual growth in gas throughput served by the Company of approximately 1%. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching, and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing the Company's system entirely. The 1998 California Gas Report forecasts a total bypass volume of 133,600 MMcf for 1999.
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 34,169 MMcf, 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, and 79,749 MMcf, for 1998, 1997, 1996, 1995, and 1994, respectively.
(3) In January 1997, a Pacific Gas and Electric Company subsidiary--Pacific Gas Transmission Company (PGT)--became a subsidiary of PG&E Corporation and is now known as PG&E Gas Transmission, Northwest Corporation.
- -------- (1) Over 100% indicates colder than normal. (2) The net plant investment per customer figures for 1997 and 1998 are lower than in previous years because they exclude subsidiaries.
Natural Gas Supplies
The objective of Pacific Gas and Electric Company's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs, and fosters competition among suppliers.
Under current CPUC regulations, Pacific Gas and Electric Company purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 1998, approximately 68% of the Company's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by Canadian pipeline companies and PG&E Gas Transmission, Northwest Corporation; approximately 4% was purchased in California; and approximately 28% was purchased in the U.S. Southwest and transported by the El Paso Natural Gas Company or Transwestern Pipeline Company pipelines. California purchases include both purchases from various California producers and purchases of gas transported to California by others. The following table shows the total volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by Pacific Gas and Electric Company from these sources during each of the last five years.
- -------- (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. Beginning March 1, 1998, the average price for gas also includes intrastate pipeline demand and reservation charges. These costs were previously bundled in gas rates.
Gas Regulatory Framework
In August 1997, the CPUC approved the Gas Accord which restructures Pacific Gas and Electric Company's gas services and its role in the gas market. As discussed above (see "General--Competition and the Changing Regulatory Environment--Gas Industry"), the Gas Accord separates, or "unbundles," the rates for Pacific Gas
and Electric Company's gas transmission services from its distribution services, increases the opportunities for core customers to purchase gas from competing suppliers, establishes a form of incentive regulation to measure the reasonableness of core procurement costs, and establishes gas transmission and storage rates from March 1998 through December 2002. The Gas Accord also settled various issues pending in certain regulatory proceedings.
The CPUC is considering further changes in California's natural gas industry. See "General--Competition and the Changing Regulatory Environment-- Gas Industry" above.
Transportation Commitments
Pacific Gas and Electric Company has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that Pacific Gas and Electric Company will pay each year may change due to changes in tariff rates. The total demand and volumetric transportation charges paid by Pacific Gas and Electric Company under these agreements were approximately $113 million in 1998. This amount includes payments made to PG&E Gas Transmission, Northwest Corporation (PG&E GT-Northwest) of approximately $49 million in 1998, but which are eliminated in the consolidated financial statements of PG&E Corporation.
As a result of regulatory changes, Pacific Gas and Electric Company no longer procures gas for most of its noncore customers, resulting in a decrease in the Company's need for firm transportation capacity for its gas purchases. Pacific Gas and Electric Company continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers). Pacific Gas and Electric Company is continuing its efforts to broker or assign any of its remaining contracted-for but unused interstate transportation capacity, including unused capacity held for its core and core subscription customers.
Under a firm transportation agreement with PG&E GT-Northwest that runs through October 31, 2005, Pacific Gas and Electric Company currently retains approximately 600 million cubic feet per day (MMcf/d) on the PG&E GT-Northwest system to support its core and core subscription customers. The Company has been able to broker its unused capacity on PG&E GT-Northwest's system, when not needed for core and core subscription customers.
In general, any shortfall resulting from the difference between the fixed demand charges Pacific Gas and Electric Company pays under gas transportation contracts with interstate pipeline companies for the reservation of interstate pipeline capacity that the Company no longer uses to serve noncore customers, and the revenues Pacific Gas and Electric Company obtains from brokering that capacity, is eligible for rate recovery through the Interstate Transition Cost Surcharge (ITCS), subject to a reasonableness review. Various groups had challenged Pacific Gas and Electric Company's recovery of these amounts, including amounts which arose in connection with firm transportation commitments that the Company had entered into with PG&E GT-Northwest and El Paso Natural Gas Company (El Paso). (The agreement with El Paso terminated as of December 31, 1997.) Under the Gas Accord, these challenges were resolved through Pacific Gas and Electric Company's agreement to forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated for collection from its core and noncore customers, respectively.
In 1992, Pacific Gas and Electric Company entered into a firm transportation agreement with Transwestern Pipeline Company (Transwestern), which expires in 2007, to meet core gas sales demands and electric generation needs. The demand charges associated with the entire Transwestern capacity are currently approximately $26 million per year. Pacific Gas and Electric Company was not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account, although the Company was authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings. In 1995, the CPUC determined that it was unreasonable for Pacific Gas and Electric Company to commit to transportation capacity with Transwestern and disallowed recovery of the costs
of capacity for 1992. It indicated that it would disallow costs through the term of the contract unless Pacific Gas and Electric Company could demonstrate on an annual basis that the benefit of the commitment outweighed the costs in a particular year. As part of the Gas Accord, Pacific Gas and Electric Company agreed to resolve this issue by forgoing the recovery of costs associated with capacity originally subscribed to in order to serve core customers through 1997 and to limit its recovery of demand charges through the CPIM during the period 1998 through 2002.
Core Procurement Incentive Mechanism
Pacific Gas and Electric Company's core gas procurement costs for the period June 1994 to 2002 are recoverable under a core procurement incentive mechanism (CPIM), a form of incentive regulation established by the Gas Accord. The CPIM provides the Company with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are deemed reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, the Company's ratepayers and shareholders share savings or costs, respectively. In January 1999, the Company filed a performance report with the ORA of the CPUC, recommending a shareholder award of $190,766, for the period January 1, 1998 through October 31, 1998. During 1998, the Company submitted a similar report to the ORA for its January 1997 through December 1997 performance, recommending a shareholder award of approximately $1.8 million. After ORA comments on the Company's performance reports, the Company will seek CPUC approval for all gas procurement costs for both periods, including the Company's shareholder awards.
PGT/Pacific Gas and Electric Company Pipeline Expansion
In November 1993, PG&E GT-Northwest (then known as Pacific Gas Transmission Company or PGT) and Pacific Gas and Electric Company placed in service the Pipeline Expansion, an expansion of their interconnected natural gas transmission systems from the Canadian border into California. The 840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern and Southern California.
The conditions of the CPUC's approval of the construction of Pacific Gas and Electric Company's portion of the Pipeline Expansion (PG&E Expansion or Line 401) placed the Company at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross-over" ban under which volumes delivered from the incremental portion owned by PG&E GT- Northwest (PGT Expansion) of the Pipeline Expansion must be transported at an incremental PG&E Expansion rate. The costs of PG&E Expansion operations were recovered only from PG&E Expansion customers, through rates established in separate PG&E Expansion rate proceedings.
Under the Gas Accord, Pacific Gas and Electric Company is at risk for recovery of all gas transmission costs, including costs of the PG&E Expansion, through rates; however, a portion of the PG&E Expansion will be combined with other transmission assets (specifically, a portion of the Company's Line 400) for ratemaking purposes. This new ratemaking treatment for gas transmission assets allows all shippers supplying noncore customers to transport Canadian gas in California at a single rate, and obviates the need for the "cross-over" ban, which was eliminated under the Gas Accord. Further, in the Gas Accord, the CPUC adopted a rule under which Pacific Gas and Electric Company is required, whenever it discounts service for a shipper on its Line 400/401 delivering primarily Canadian gas within the Company's service territory, to contemporaneously offer a commensurate discount to all shippers delivering Southwest or California source gas on Line 300 within the Company's service territory.
WHOLESALE OPERATIONS OF AFFILIATES
Gas Transmission Operations
PG&E Corporation participates in the "midstream" portion of the gas business through PG&E GTT, PG&E Gas Transmission Teco, Inc. and PG&E GT-Northwest. The "midstream" gas business includes (1) gas gathering, processing, and storage, and transportation of natural gas and natural gas liquids (NGLs); (2) the marketing of natural gas to gas distribution companies, electric utilities, municipalities, marketers, independent power producers, and end-use customers; (3) the transportation of natural gas for these customers, producers, and other pipelines; and (4) the marketing and transportation of NGLs to various customers, including end-use customers.
PG&E GTT and PG&E Gas Transmission Teco, Inc. own and operate gas gathering, transportation, and processing facilities, and NGL pipelines. The NGL business includes the gathering of natural gas, the extraction of NGLs from natural gas, the fractionation of mixed NGLs into component products (e.g., ethane, propane, butane, and natural gasoline), and the transportation and marketing of NGLs. The Texas operations include approximately 6,600 miles of natural gas pipelines and joint ownership or leasehold interests in approximately 1,900 miles of pipelines, including pipelines from Waha in west Texas to the Katy area near Houston, Texas. These pipeline systems have the capacity to transport more than 3 billion cubic feet (bcf) of gas per day. Other Texas assets include a long-term lease of 7.2 bcf of storage capacity, approximately 536 miles of NGL pipelines and nine natural gas processing plants with a combined capacity of approximately 1.6 bcf per day of gas throughput, capable of producing approximately over 100,000 barrels per day of NGLs.
PG&E GT-Northwest owns and operates gas transmission pipelines and associated facilities which extend over 612 miles from the Canada-U.S. border to the Oregon-California border and are capable of transporting 2.4 bcf per day of natural gas. It also owns two smaller diameter pipeline extensions within Oregon, totaling 106 miles. In July 1998, PG&E Corporation sold its natural gas pipeline in Australia as part of its strategy to focus on the domestic market.
In September 1996, the FERC approved a settlement of PG&E GT-Northwest's 1994 rate case. The major issue in this proceeding was whether PG&E GT- Northwest's mainline transportation rates should be equalized through the use of rolled-in cost allocations or whether they should continue to reflect the use of incremental cost allocation to determine the rates to be paid by firm shippers. (Under incremental rates, a pipeline would generally charge higher rates to shippers contracting for capacity on newly-added expansion facilities, as compared to shippers using depreciated pre-expansion facilities.) The settlement provides for rolled-in rates effective November 1996. To mitigate the impact of the higher rolled-in rates on shippers who were paying lower rates under contracts executed prior to construction of the PGT Expansion, most of the firm shippers who took service prior to such time receive a reduction from the rolled-in rate for a six-year period, while PGT Expansion firm shippers pay a surcharge in addition to the rolled-in rates to offset the effect of the mitigation. See "Utility Operations--Gas Utility Operations--PGT/Pacific Gas and Electric Company Pipeline Expansion" above. The settlement also provides for rates based on a return on equity of 12.2%. In 1998, petitions filed by various parties for rehearing of the FERC order approving the settlement were denied. Some parties have appealed the FERC's denial of these rehearing petitions to the U.S. Court of Appeals for the District of Columbia Circuit, but PG&E GT-Northwest currently expects the settlement to be upheld.
Independent Power Generation
Through USGen and its affiliates, PG&E Corporation participates in the development, construction, operation, ownership, and management of non-utility electric generating facilities that compete in the United States power generation market. USGen is headquartered in Bethesda, Maryland.
In 1998, PG&E Corporation, through its indirect subsidiary, USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generating assets and power supply contracts from NEES for
$1.59 billion, plus $85 million for early retirement and severance costs previously committed to by NEES. Including fuel and other inventories and transaction costs, PG&E Corporation's financing requirements were approximately $1.8 billion, funded through $1.3 billion of debt, a $425 million equity contribution, and $70 million from cash on hand and other sources. The debt was raised through revolving credit facilities established at both the USGen and the USGenNE levels. Specifically, a $1.1 billion credit facility was established at the USGen level, and $575 million credit facility was established at the USGenNE level. In December 1998, USGenNE canceled $475 million of this $575 million facility through a sale-leaseback transaction involving the pumped storage facility acquired from NEES.
The acquired NEES facilities consist of two conventional hydroelectric systems with 14 stations, three fossil-fuel stations (coal, oil, and natural gas) with 11 units, and a pumped storage facility, with a combined generating capacity of approximately 4,000 MW. In addition, USGenNE assumed the purchase obligations under 27 multi-year power-purchase agreements between NEES's subsidiary, New England Power, and other utility and non-utility wholesale suppliers representing an additional 1,100 MW of production capacity. Subsequently, several of the power-purchase agreements expired and/or were transferred, thereby reducing the total capacity to the current level of approximately 800 MW. USGenNE entered into agreements with NEES as part of the acquisition, which (1) provide that NEES shall make annual support payments through early 2008 to offset the cost of power associated with these above- market contracts, and (2) require that USGenNE provide electricity to NEES under supply agreements that expire over the next six to 11 years.
Three of the four states in which the acquired assets are located (Massachusetts, Rhode Island, and New Hampshire) were also among the first states in the country to introduce retail competition. (A referendum in Massachusetts reaffirming electric industry restructuring was approved by the voters in November 1998.) Connecticut also has passed retail competition legislation.
The acquired assets are located within the New England Power Pool (NEPOOL). The wholesale electricity market in New England features a bid-based, real- time pricing structure. Traditionally, NEPOOL has operated as a "tight power pool," one in which the utilities within the pool dedicate their generation resources to be centrally dispatched. Dispatch starts with the lowest-cost generation and ends with the highest-cost generation. In 1998, an independent system operator for the New England states (ISO-NE) began to provide central dispatch service and to operate the power pool as a competitive wholesale marketplace.
As a result, the NEPOOL market is in the midst of transitioning to a competitive market. The duties of the ISO-NE include scheduling the operations of the regional transmission systems and, importantly, operating a power exchange for seven generation products (the "Interchange"). These products are energy, installed (monthly) capacity and operable (hourly) capacity, three types of reserves and automatic generation control (adjustment of generators to meet the second-to-second changes in electric load). The installed capacity market began operations on April 1, 1998. The balance of the Interchange is anticipated to begin operations on April 1, 1999, although this date is subject to final implementation by the ISO-NE.
In these New England states, the utility companies providing service to retail customers are required to provide Standard Offer Service (SOS) to those customers. The SOS is intended to provide consumers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, followed by a price disincentive that is intended to stimulate the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New Hampshire (subject to early termination on December 31, 2000, at the discretion of the New Hampshire Public Service Commission); through December 31, 2004, in Massachusetts; and through December 31, 2009, in Rhode Island. However, if any customer elects to have their electricity provided by an alternate supplier, they are precluded from returning to the SOS. In connection with the purchase of the NEES generation assets, PG&E Corporation, through USGenNE, entered into agreements to supply the electric capacity and energy requirements necessary for NEES to meet its SOS obligations. In December 1998, NEES's New Hampshire utility subsidiary, Granite State Electric Co., reached an agreement with Constellation Power Source, Inc. under which Constellation Power Source, Inc. will
provide the SOS for Granite State Electric Co.'s customers. USGenNE retains its supply obligations for Massachusetts Electric Company and Narrangansett Electric Company, two utility subsidiaries of NEES located in Massachusetts and Rhode Island, respectively. NEES is responsible for passing on to PG&E Corporation the revenues generated from the SOS.
Initially, approximately 90% of the operating capacity acquired from NEES, including capacity and energy generated by independent power producers (IPPs) under the assumed power-purchase agreements, has been dedicated to providing SOS. To the extent that customers eligible to receive SOS choose alternate suppliers this percentage will decrease.
Like California utilities, the New England utilities have entered into agreements with IPPs to provide energy and capacity at prices which are anticipated to be in excess of market prices. As described above, USGenNE assumed NEES's contractual rights and duties under certain power-purchase agreements with IPPs, which in the aggregate provide for approximately 800 MW of capacity. In connection with the acquisition of NEES's generating assets, USGenNE is required to pay NEES amounts due from NEES to the IPPs in accordance with their power-purchase agreements. These payment obligations are reduced by monthly support payments that NEES pays USGenNE.
Finally, in connection with the NEES acquisition, USGenNE obtained the right to purchase NEES's nuclear generated electric energy, capacity, and associated products at market prices up to the entire amount available. This right terminates automatically with respect to any nuclear facility that is sold or ceases operation for any reason, and if not terminated earlier, expires at termination of the SOS.
The financial impact of the acquisition of the NEES assets on PG&E Corporation is subject to a number of risks and uncertainties, including future market prices of power in the region where the NEES assets are located, future fuel prices, the development of a competitive market in the states in which the NEES assets are located, the extent to which operating efficiencies at the NEES plants can be attained, changes in legislation affecting electric industry restructuring and in the regulatory environment in the states where the NEES assets are located, the extent of the obligation to provide electricity under the SOS at prices below cost or market, the extent to which a liquid, well-structured trading market develops for wholesale electric power in the states in which the NEES assets are located, and generating capacity expansion and retirements by others.
As of December 31, 1998, USGen affiliates had ownership interests in 30 operating plants (including the assets acquired from NEES) in 10 states. The total generating capacity of these 30 plants is approximately 6,560 MW. PG&E Corporation's combined net equity ownership and leased interest in these plants as of December 31, 1998, represented approximately 5,300 MW. The plants were financed largely with a combination of equity or equity commitments from the project sponsors and non-recourse debt. (For a description of the financing of the NEES acquisition, see above.) USGen, through its affiliate, U.S. Operating Services Company (USOSC), provides contract operations and maintenance services to many of these facilities. Nationwide, USGen's power plant development activities exceed 8,600 MW in 8 states. USGen and its affiliated or managed facilities sold 22,242,949 million megawatt-hours (MWh) of electricity in 1998, including sales of electricity from the generating facilities acquired from NEES on September 1, 1998.
The following table sets forth information regarding the operating generating plants in which USGen affiliates have ownership or leasehold interests. The table also notes the operating plants which USGen affiliates manage or operate, or both manage and operate, power plant operations.
Portfolio of Operating Generating Plants
- -------- (1) Unlike other operating facilities in which USGen affiliates have ownership and management interests, the Bear Swamp Facility is owned by a third party through a single-investor lease arrangement. USGen maintains full management and operating responsibility for the facility.
(2) Acquired from NEES on September 1, 1998.
(3) USGen affiliates have an ownership or leasehold interest in these plants, but do not manage power plant operations.
(4) Of the total of 6,563 megawatts, USGen's net equity ownership and leased percentage is 5,282 megawatts.
Energy Trading
PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P. (collectively referred to as PG&E Energy Trading), headquartered in Houston, Texas, purchase bulk volumes of power and natural gas from PG&E Corporation affiliates and the wholesale market. PG&E Energy Trading then schedules, transports, and resells these commodities, either directly to third parties or to other PG&E Corporation affiliates. PG&E Energy Trading also provides price risk management services to PG&E Corporation's other businesses (except Pacific Gas and Electric Company) and to wholesale customers. Additionally, PG&E Energy Trading provides PG&E Energy Services Corporation with a broad portfolio of energy products and services for the retail market. For more information, see "General--Price Risk Management Programs" above.
Additional information concerning the wholesale operations of PG&E Corporation's affiliates is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 16 of the "Notes to Consolidated Financial Statements" beginning on page 67 of the 1998 Annual Report to Shareholders.
RETAIL OPERATIONS OF AFFILIATES
Energy Services
PG&E Energy Services (PG&E ES), headquartered in San Francisco, California, provides retail gas and electric commodities nationwide, where permitted under applicable laws, and provides energy related value-added services, including billing and information management services, energy efficiency and other energy management services, regulatory and rate analysis, and power quality solutions. PG&E ES targets primarily industrial, commercial, and institutional customers, offering comprehensive energy management solutions to reduce their energy costs and improve their productivity. PG&E ES has 20 offices nationwide to support its sales activities. PG&E ES currently competes with other non- utility electric retailers in California for direct access customers. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" above.
Additional information concerning the retail operations of PG&E ES is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 16 of the "Notes to Consolidated Financial Statements" beginning on page 67 of the 1998 Annual Report to Shareholders.
ENVIRONMENTAL MATTERS
Environmental Matters
The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection and the possible future impact of environmental compliance. This information below reflects current estimates, which are periodically evaluated and revised. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recoveries or contributions from third parties. Future estimates and actual results may differ materially from those indicated below.
PG&E Corporation, Pacific Gas and Electric Company, U.S. Generating Company and its affiliates (including USGen New England, Inc. (USGenNE) which holds the electric generating facilities acquired from NEES in September 1998), and other PG&E Corporation subsidiaries and affiliates, are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. Pacific Gas and Electric Company has undertaken major compliance efforts with specific emphasis on its purchase, use, and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Company's bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations generally have been recovered in rates.
Environmental Protection Measures
The estimated expenditures of PG&E Corporation's subsidiaries for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. It is likely that the stringency of environmental regulations will increase in the future. With Pacific Gas and Electric Company's 1998 sale of its Morro Bay, Moss Landing, and Oakland power plants, and the upcoming sale of the Company's Contra Costa, Pittsburg, Potrero, and Geysers power plants (expected to close in 1999), the Company's oxides of nitrogen (NOx) emission reduction compliance costs will be reduced significantly. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring--Voluntary Generation Asset Divestiture" above.
Air Quality
Pacific Gas and Electric Company's thermal electric generating plants are subject to numerous air pollution control laws, including the California Clean Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air Act, three of the local air districts in which Pacific Gas and Electric Company operates fossil-fueled generating plants have adopted final rules that require a reduction in NOx emissions from the power plants of approximately 90% by 2004 (with numerous interim compliance deadlines).
Following divestiture of the Company's fossil-fueled generating plants in connection with electric industry restructuring, the new owners will bear NOx retrofit costs. Under AB 1890, NOx retrofit costs would be eligible for recovery as transition costs but only to the extent that those costs are found by the CPUC to be both reasonable and necessary to maintain the unit in operation through 2001.
The Gas Accord authorizes $42 million to be included in rates through 2002, for gas NOx retrofit projects related to natural gas compressor stations on Pacific Gas and Electric Company's Line 300, which delivers Southwest gas. Other air districts are considering NOx rules which would apply to Pacific Gas and Electric
Company's other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at many of these natural gas compressor stations. Pacific Gas and Electric Company currently estimates that the total cost of complying with these various NOx rules will be up to $51.9 million over four years.
USGen's compliance with certain future regulatory requirements limiting the total amount of NOx emissions from its fossil-fueled power plants is expected to be achieved by installing additional controls, fuel switching and purchasing of NOx allowances. USGenNE has agreed to be bound by a number of state and regional initiatives that will require it to achieve significant reductions of sulfur dioxide (SO/2/) and NOx emissions by the time its older fossil-fueled power plants have been in operation for 40 years or by 2010, whichever comes first. It is expected that USGenNE can meet these requirements through the utilization of allowances it currently owns, installation of additional controls or through the purchase of additional allowances. (SO/2/ allowances are emission credits that are traded in a national market under the United States Environmental Protection Agency's (EPA) Acid Rain Program. NOx allowances are emission credits that are traded in a regional market consisting of seven Northeast states known as the Ozone Transport Region.) It is estimated that USGenNE's total cost of complying with these requirements will be up to $6 million through the year 2000.
Water Quality
Pacific Gas and Electric Company's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Pacific Gas and Electric Company's fossil-fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast Regional Water Quality Control Board (Central Coast Board). The Central Coast Board did not make a final decision on the report and requested that Pacific Gas and Electric Company continue its thermal effects monitoring program. In 1995, the Central Coast Board requested that Pacific Gas and Electric Company prepare an updated comprehensive assessment of Diablo Canyon's thermal effects and approved a reduced environmental monitoring program. A comprehensive statistical analysis of Diablo Canyon's thermal effects was submitted to the Central Coast Board in December 1997 and a regulatory assessment was submitted in November 1998. In the unlikely event that the Central Coast Board finds that Diablo Canyon's existing thermal limits are not protective of beneficial uses of the marine waters and that major modifications are required (e.g., cooling towers), significant additional construction expenses could be required.
Pursuant to the federal Clean Water Act, Pacific Gas and Electric Company is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. The Company has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. The Company is currently preparing a new study for Diablo Canyon. The study is scheduled to be submitted to the Central Coast Board for review in 1999. In the event that the Central Coast Board finds that Diablo Canyon's cooling water intake structure does not meet the BTA requirements, significant additional expenses for construction or mitigation could be required. In addition, the promulgation or modification of statutes, regulations, or water quality control plans at the federal, state, or regional level may impose increasingly stringent cooling water discharge requirements on Pacific Gas and Electric Company power plants in the future. Costs to comply with renewed permit conditions required to meet any more stringent requirements that might be imposed cannot be estimated at the present time.
Several fish species listed or proposed for listing as endangered species may be found in the waters near Pacific Gas and Electric Company's Delta power plants (the Contra Costa and Pittsburgh fossil-fueled power plants). To address the impacts of operation and maintenance activities at the Delta plants on sensitive species, the Company has developed a Habitat Conservation Plan (HCP) pursuant to the requirements of Section 10(a) of the federal Endangered Species Act. The HCP is designed to minimize and mitigate any incidental "take"
(e.g., harassing, wounding, or killing) of listed species that may occur from the operation, maintenance, and repair of the power plants, in order to support the issuance of a Section 10(a) incidental take permit necessary for continued operation of the plants.
USGen's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Two of the fossil-fueled plants owned and operated by USGenNE are operating in compliance with National Pollutant Discharge Elimination System (NPDES) permits that have expired and the NPDES permit for a third facility is scheduled to expire in 1999. As to the facilities for which the NPDES permit has expired, new permit applications are pending and it is anticipated that all three facilities should be able to continue to operate under existing terms and conditions until new permits are issued. USGenNE has submitted a permit renewal application and is negotiating with EPA on ongoing studies and permit conditions. It is estimated that USGenNE's cost to comply with these conditions could be as much as $4 million through the year 2000.
Hazardous Waste Compliance and Remediation
PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. Pacific Gas and Electric Company has a comprehensive program to comply with many hazardous waste storage, handling, and disposal requirements promulgated by the EPA under the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with other state hazardous waste laws and other environmental requirements.
One part of this program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plants produced lampblack and tar residues, byproducts of a process that Pacific Gas and Electric Company, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), Pacific Gas and Electric Company's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. The Company has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which operated in the Company's service territory. The Company owns all or a portion of 30 of these manufactured gas plant sites. The Company has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which the Company owns. It is estimated that the Company's program may result in expenditures of approximately $8 million in 1999. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if Pacific Gas and Electric Company is found to be responsible for cleanup at sites it does not currently own.
In addition to the manufactured gas plant sites, Pacific Gas and Electric Company may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the environment because of an actual or potential release of hazardous substances. Pacific Gas and Electric Company has been designated as a potentially responsible party (PRP) under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. With respect to the Casmalia site near Santa Maria, California, the Company and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires these generators to perform certain site investigation and mitigation measures, and provides a release from liability for certain other site cleanup obligations. Although the Company has not been formally designated a PRP with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed the Company and other parties to initiate measures with respect to the study and remediation of that site.
In addition, Pacific Gas and Electric Company has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Company is responsible for performing or paying for remedial action at sites the Company no longer owns or never owned.
The cost of hazardous substance remediation ultimately undertaken by Pacific Gas and Electric Company is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. Pacific Gas and Electric Company had an accrued liability at December 31, 1998, of $296 million for hazardous waste remediation costs at those sites, including fossil-fueled power plants, where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $487 million if, among other things, other PRPs are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to the Company based upon a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.
USGen acquired the onsite environmental liability associated with USGenNE's acquisition of electric generating facilities from NEES, but did not acquire any offsite pollution liability associated with the past disposal practices at the acquired facilities. USGen has obtained pollution liability and environmental remediation insurance coverage to limit the financial risk associated with the onsite pollution liability at all of its facilities.
Potential Recovery of Hazardous Waste Compliance and Remediation Costs
In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs (HWRC). That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. However, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. Under the HWRC, 70% of the ratepayer portion of Pacific Gas and Electric Company's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. The Company can seek to recover hazardous substance cleanup costs under the HWRC in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related clean-up costs for contamination caused by events occurring after January 1, 1998.
Pacific Gas and Electric Company retains liability for certain required environmental remediation of pre-closing soil or groundwater contamination for fossil and geothermal generation facilities which are sold in connection with electric industry restructuring. As each generation facility is divested, the Company is required to prepare a forecast of environmental remediation costs for that plant and to use the forecast to adjust the current plant decommissioning cost estimate, eventually to be recovered through the Transition Cost Balancing Account (TCBA). (For ratemaking purposes, estimates of environmental remediation costs are discounted to present value, whereas for accounting purposes the nominal value of estimated remediation costs is used.) The discounted environmental liability associated with the Morro Bay, Moss Landing, and Oakland power plants (which were sold on July 1, 1998) and approved by the CPUC is $31.6 million. (The buyer of these plants has assumed the decommissioning liability for the purchased plants.) As of July 1, 1998, the Company had recovered $66 million from ratepayers for both the environmental and non-environmental decommissioning accrual related to the Morro Bay, Moss Landing, and Oakland power plants. The excess recovery related to these plants in the amount of $34.5 million ($66 million minus $31.6 million) resulted in a net credit to the sunk cost of the remaining plants (the Contra Costa, Pittsburgh, and Potrero power plants, and the Geysers geothermal facilities) reducing the amount of sunk costs to be amortized over the transition period, offsetting other transition costs.
On October 23, 1998, Pacific Gas and Electric Company requested that the CPUC approve a total of $88.6 million of estimated costs of environmental remediation liability that the Company will retain for the Contra Costa, Pittsburg, and Potrero power plants, and the Geysers geothermal facilities. (The buyers will assume
the decommissioning liability.) The Company also requested that the CPUC approve similar accounting and ratemaking treatment of environmental remediation and non-environmental decommissioning for these plants as the CPUC approved for the first group of plants sold. As of December 31, 1998, Pacific Gas and Electric Company has recovered from ratepayers approximately $141 million for environmental and non-environmental decommissioning accrual related to these plants. After the plant sales are completed, the excess recovery of approximately $48.5 million (as adjusted for decommissioning costs that will continue to be accrued) would reduce the amount of generation- related sunk costs to be amortized over the transition period, offsetting other transition costs.
Pacific Gas and Electric Company expects to recover $160 million of the $296 million accrued liability, discussed above, in future rates. The liability also includes $76 million related to power plant decommissioning for environmental clean-up, which is recovered through depreciation. Additionally, the Company is seeking recovery of costs from insurance carriers and from other third parties.
In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Company previously had notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, the Company's carriers neither admitted nor denied coverage, but requested additional information from the Company. Although the Company has received some amounts in settlements with certain of its insurers (approximately $49.6 million through December 31, 1998), the ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time.
Compressor Station Litigation
Several cases have been brought against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Company's Hinkley, Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings-- Compressor Station Chromium Litigation" below, for a description of the pending litigation.
Electric and Magnetic Fields
In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks which may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled which raises the question of whether adverse health impacts might exist.
In November 1993, the CPUC adopted an interim EMF policy for California energy utilities which, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services.
As part of its effort to educate the public about EMF, Pacific Gas and Electric Company provides interested customers with information regarding the EMF exposure issue. The Company also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
Pacific Gas and Electric Company is not currently involved in third party litigation concerning EMF. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly limited its holding to
property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. Pacific Gas and Electric Company was a defendant in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMF. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMF and barred plaintiffs' personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.
In the event that the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility- related EMF exposures can be isolated from other exposures, Pacific Gas and Electric Company may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if relocation of existing power lines is ultimately required.
Low Emission Vehicle Programs
In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding which approved approximately $42 million in funding for Pacific Gas and Electric Company's LEV program for the six-year period beginning in 1996. The CPUC's decision on electric industry restructuring finds that the costs of utility LEV programs should continue to be collected by the utility for the duration of the six-year period. Pacific Gas and Electric Company continues to run its LEV program as funded.
ITEM 2.
ITEM 2. Properties.
Information concerning Pacific Gas and Electric Company's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of Pacific Gas and Electric Company are subject to the lien of an indenture which provides security to the holders of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds.
Information concerning properties and facilities owned by other PG&E Corporation subsidiaries is included in the discussion under the heading of this report entitled "Wholesale Operations of Affiliates."
ITEM 3.
ITEM 3. Legal Proceedings.
See Item 1, Business, for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, PG&E Corporation and Pacific Gas and Electric Company are subject to routine litigation incidental to their business.
Compressor Station Chromium Litigation
Pacific Gas and Electric Company is a defendant in five civil actions pending in California courts on behalf of approximately 2,300 plaintiffs. These cases are (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court; (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996 in Los Angeles County Superior Court; (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles Superior Court; (4) Little and Mustafa v. Pacific Gas and Electric Company and PG&E Corporation, filed September 10, 1997, in San Bernardino Superior Court; and (5) Whipple, et al. v. Pacific Gas and Electric Company and PG&E Corporation, et al., filed September 10, 1997, in San Bernardino Superior Court. (Plaintiffs have agreed to dismiss PG&E Corporation in these last two suits.) These cases are collectively referred to as the "Aguayo Litigation."
Each of the complaints in the Aguayo Litigation, except the Little case described below, alleges personal injuries and seeks compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of Pacific Gas and Electric Company's gas compressor stations at
Kettleman, Hinkley, and Topock, California. The plaintiffs in the Aguayo Litigation include current and former Pacific Gas and Electric Company employees, relatives of current and former Company employees, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim only loss of consortium or injury through the alleged exposure of their spouses or parents.
In the Whipple case, pending in San Bernardino Superior Court, the plaintiffs (four members of one family) allege personal injuries, injury to a business enterprise, and injury to real property based upon causes of action for (1) actual fraud and deceit, (2) negligence, (3) negligence per se, (4) strict liability, (5) battery, (6) intentional misrepresentation, (7) negligent misrepresentation, (8) fraudulent concealment, and (9) intentional spoliation of evidence. In the Little case, also pending in San Bernardino Superior Court, two plaintiffs allege injury to real property based upon causes of action for (1) actual fraud and deceit, (2) negligence, and (3) negligence per se. Plaintiffs in each action are seeking unspecified compensatory and punitive damages, as well as civil penalties pursuant to Proposition 65.
In June 1998, a Los Angeles Superior Court judge found that preconception claims are not recognizable under California law and ordered the dismissal of 235 plaintiffs with such claims from the Aguayo Litigation. Judgment was entered against these plaintiffs in December 1998. During September and October 1998, the court made similar rulings in the Acosta and Aguilar cases. The Company expects that plaintiffs may appeal these rulings.
All discovery and discovery motion practice in three of the cases brought in Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas and Electric Company, and Aguayo v. Pacific Gas and Electric Company) has been referred by the judge to a discovery referee. The court ordered that those plaintiffs who did not respond to written discovery requests served by Pacific Gas and Electric Company by November 15, 1998, would be dismissed. The Company has submitted stipulations to dismiss approximately 630 plaintiffs who failed to respond to discovery requests. It is not anticipated that these plaintiffs will appeal.
After the entry of the dismissal of plaintiffs with preconception claims and those plaintiffs who failed to respond to discovery requests, there will be approximately 1,650 plaintiffs remaining in the Aguayo Litigation.
On September 16, 1998, a discovery referee set the procedures for selecting 20 trial test plaintiffs and two alternates in the Aguayo, Acosta, and Aguilar cases. Ten of these trial test plaintiffs and one alternate were selected by plaintiffs, six plaintiffs and one alternate were selected by defendants, and four plaintiffs were selected at random (by selecting seven plaintiffs at random and allowing each party -- plaintiffs, Pacific Gas and Electric Company, and Betz to strike one). A trial date has been set for November 16, 1999. The Company has filed a motion to transfer venue to Fresno County Superior Court which is scheduled to be heard on March 22, 1999.
Pacific Gas and Electric Company is responding to the complaints and asserting affirmative defenses. The Company will pursue appropriate legal defenses including statute of limitations, inability of certain plaintiffs to state a claim for alleged preconception exposure, or exclusivity of workers' compensation laws, and factual defenses including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged. The Company is attempting to gather information concerning the alleged type and duration of exposure, the nature of injuries alleged by individual plaintiffs, and the additional facts necessary to support its legal defenses, in order to better evaluate and defend this litigation.
PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or Pacific Gas and Electric Company's financial position or results of operations.
Texas Franchise Fee Litigation
On July 31, 1997, PG&E Corporation acquired Valero Energy Corporation (Valero), now known as PG&E Gas Transmission, Texas Corporation or PG&E GTT. PG&E GTT succeeded to the eight cases described below
which were pending at the time of the acquisition against Valero and its affiliates (collectively referred to as the "Texas Franchise Fees Litigation"). These actions were brought by various cities in Texas arising out of several Texas statutes and city ordinances involving the following: (a) what rights, if any, Texas cities may have to require companies engaged in the gathering, production, distribution, transmission, and/or sale of natural gas (gas business) to obtain consent from, and pay fees to, the cities within which such activities are being conducted, (b) what form any such consent, if required, must take, (c) what constitutes "use" of city property, and (d) what types of charges, if any, a Texas city properly can assess against gas pipeline and marketing companies for use of that city's property.
These seven cases pending against Valero entities at the time of the acquisition are: (1) City of Edinburg v. Rio Grande Valley Gas Co. (RGVG), Valero Energy Corporation (now known as PG&E GTT), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed August 31, 1995, in the 92nd State District Court, Hidalgo County, Texas; (2) Cities of San Benito, Primera, and Port Isabel v. RGVG, Valero Energy Corporation (now known as PG&E GTT), Southern Union Company, et al., filed December 31, 1996, in the 107th State District Court, Cameron County, Texas; (3) City of Mercedes v. Reata Industrial Gas L.P. (now known as PG&E Reata Energy, L.P.), and Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), filed April 16, 1997, in the 92nd State District Court in Hidalgo County, Texas; (4) Cities of Alton and Dana v. Rio Grande Valley Gas Co., Valero Energy Corporation (now known as PG&E GTT), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed July 18, 1996, in the 92nd State District Court, Hidalgo County, Texas; (5) City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as PG&E GTT), Southern Union Company, et al., filed December 27, 1996, in the 92nd State District Court, Hidalgo County, Texas; (6) City of San Juan, City of La Villa, City of Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as PG&E GTT), Southern Union Company, et al., filed December 27, 1996, in the 93rd State District Court, Hidalgo County, Texas; and (7) City of Weslaco v. Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation) and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) filed April 17, 1997, in the 92nd State District Court, Hidalgo County, Texas.
The trial in the City of Edinburg case began on June 15, 1998. On August 14, 1998, a jury returned a verdict in favor of the City of Edinburg, and awarded damages in the approximate aggregate amount of $9.8 million, plus attorneys' fees of approximately $3.5 million, against PG&E GTT, Southern Union Gas Company and various affiliates of PG&E GTT. The jury refused to award punitive damages against the PG&E GTT defendants. On December 1, 1998, based on the jury verdict, the court entered a judgment in the City's favor, and awarded damages of $5.3 million, attorneys' fees of up to $3.5 million (to the extent that the City is successful on appeal), prejudgment interest of $1.6 million and post-judgment interest at the rate of 10 percent per year, compounded annually, from December 1, 1998. The court found that various PG&E GTT and Southern Union defendants were jointly and severally liable for $3.3 million of the damages, prejudgment interest in the amount of $1.1 million, and all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable for $1.4 million of the damages and prejudgment interest of $440,000. The court did not clearly indicate the extent to which the PG&E GTT defendants could be found liable for the remaining damages. The judgment also decreed that (1) certain pipelines owned by PG&E GTT subsidiaries encroached on the City's property without the City's consent and (2) based on certain jury findings, PG&E GTT was vicariously liable for certain conduct of the local distribution company, RGVG, from October 1, 1985, to September 30, 1993 (the date Valero, PG&E GTT's predecessor, sold RGVG to Southern Union). The PG&E GTT defendants are appealing the judgment.
On November 4, 1997, the lawsuit filed in Cameron County, Texas, by the cities of San Benito, Primera, and Port Isabel was amended to name as defendants PG&E GTT and all of its subsidiaries (excluding its Canadian gas trading and power trading company), PG&E Gas Transmission Teco, Inc. and its subsidiaries, and PG&E Energy Trading Corporation (now known as PG&E Energy Trading--Gas Corporation), and to dismiss the Southern Union defendants. In connection with the certification of a class in this case, the court ordered notice to be sent to all potential class members and setting an opt-out deadline of December 31, 1997. Notices were mailed to approximately 159 Texas cities. Fewer than 20 cities opted out by the deadline. Some of the cities opting out include Austin, Brownsville, Houston, Pharr, and San Antonio. Defendants' motion to transfer venue of this case to Bexar County, Texas, is currently pending.
The factual allegations and claims asserted in the lawsuit filed by the city of La Joya, and in the lawsuit filed by the cities of San Juan, Lavilla, Penitas, Edcouch, and Palmview, are similar to the claims made in the lawsuit filed by the cities of San Benito, Primera, and Port Isabel. Defendants' motion to transfer venue of both cases to Bexar County, Texas, also is currently pending.
In July 1996, the lawsuits brought by the cities of Alton and Dana were originally brought as intervening actions in the City of Edinburg case, but were severed from the Edinburg lawsuit. The claims asserted by the cities of Alton and Dana are substantially similar to the Edinburg litigation claims. Damages are not quantified. Defendants' motion to transfer venue of both cases to Bexar County, Texas, also is currently pending.
On September 4, 1997, the City of Mercedes amended its petition to include class action claims and requested to be named as class representative for a statewide class consisting of all Texas municipal corporations, municipalities, towns, and villages, excluding the cities of Edinburg and Weslaco (both of which filed separate actions), in which any of the defendants have sold or supplied gas, or used public rights-of-way to transport gas. The City of Mercedes has requested a damage award, but has not specified an amount. On November 26, 1997, defendants' motion to recuse the presiding judge was granted. Plaintiffs' request for class certification is still pending. If a class is certified, defendants anticipate that they will challenge such certification. Defendants' motion to transfer venue to Bexar County, Texas, also is still pending.
The causes of action alleged in the case brought by the city of Weslaco are identical to those alleged in the City of Mercedes case. Defendants' motion to transfer venue to Bexar County, Texas, is currently pending. Defendants also have filed a motion to disqualify or recuse the presiding judge (the same judge that was recused in the Mercedes case) which is also pending.
In addition to the seven cases described above, a lawsuit was filed on April 3, 1996, in the 92nd State District Court, Hidalgo County, Texas, by the City of Pharr against Southern Union Company, et al., and RGVG. On June 24, 1996, the court certified the case as a class action and named Pharr as the class representative for the class consisting of those Texas cities, excluding Edinburg and McAllen, that have, or had natural gas franchises with RGVG. The Pharr class was certified as to two claims: breach of contract and declaratory relief dealing with the rights, status, and legal relationship between plaintiff, the class members, and the local distribution company regarding payment of franchise fees and use of granted easements. Plaintiffs' original petition also sought injunctive relief, but the class order does not include injunctive relief. Plaintiffs seek actual damages, exemplary damages, attorneys' fees, costs, and pre- and post-judgment interest, but have not specified any amounts. The court records show that a pleading was allegedly filed on December 12, 1997, but not docketed until mid-February 1998, that purports to add as defendants the same 29 PG&E Corporation entities that are parties in the San Benito class action. These PG&E Corporation entities have not been served in this litigation. On December 30, 1997, in affirming the Pharr class certification, the appellate court specifically found that the PG&E Corporation-related entities were not parties to the class action.
PG&E Corporation believes that the ultimate outcome of the Texas franchise fee cases described above could have a material adverse impact on its financial position or results of operation.
ITEM 4.
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 69 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 1998 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 22, 1999, there were 162,261 holders of record of PG&E Corporation common stock.
Pacific Gas and Electric Company has made no sales of unregistered equity securities in the last three years. PG&E Corporation has made the following sales of unregistered equity securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common stock. The shares were issued to nine former shareholders of Teco Pipeline Company (Teco) in connection with the acquisition of Teco by PG&E Corporation. PG&E Corporation owns all the outstanding shares of Teco as a result of the acquisition. The shares were issued in reliance upon the exemption from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the former shareholders of Teco represented that they were "accredited investors" as defined in Rule 501(a) under the Securities Act of 1933 and made other representations establishing the basis for the exemption. A legend as provided for by Rule 501(d)(3) was placed on each of the stock certificates representing the shares of PG&E Corporation common stock received by the former shareholders of Teco.
ITEM 6.
ITEM 6. Selected Financial Data.
A summary of selected financial information for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years is set forth on page 17 under the heading "Selected Financial Data" in the 1998 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company's earnings to fixed charges ratio for the year ended December 31, 1998, was 3.02. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the year ended December 31, 1998, was 2.85. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding.
ITEM 7.
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated results of operations and financial condition is set forth on pages 18 through 35 under the heading "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
Information responding to Item 7A appears in the 1998 Annual Report to Shareholders on page 32 under the heading "Management's Discussion and Analysis--Debt Obligations and Rate Reduction Bonds," on pages 34 and 35 under the heading "Management's Discussion and Analysis--Price Risk Management Activities," and on pages 47, 48, 53, and 54 under Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data.
Information responding to Item 8 appears on pages 36 through 70 of the 1998 Annual Report to Shareholders under the following headings for PG&E Corporation: "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," and "Statement of Consolidated Common Stock Equity;" under the following headings for Pacific Gas and Electric Company: "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," and "Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes to Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," and "Report of Independent Public Accountants," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Information responding to Item 9 has been previously reported by PG&E Corporation and Pacific Gas and Electric Company in a current report on Form 8-K dated February 17, 1999 and filed on February 23, 1999.
PART III
ITEM 10.
ITEM 10. Directors and Executive Officers of the Registrant.
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned "Executive Officers of the Registrant" contained on pages 45 through 47 in Part I of this report. Other information responding to Item 10 is included on pages 3 through 6 under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and page 43 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 11.
ITEM 11. Executive Compensation.
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 9 and 10 under the heading "Compensation of Directors" and on pages 36 through 41 under the headings "Summary Compensation Table," "Option/SAR Grants in 1998," "Aggregated Option/SAR Exercises in 1998 and Year-End Option/SAR Values," "Long-Term Incentive Plan--Awards in 1998," "Retirement Benefits," and "Termination of Employment and Change In Control Provisions" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 11 and 12 under the heading "Security Ownership of Management" and on pages 42 and 43 under the heading "Principal Shareholders" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions.
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on page 10 under the heading "Certain Relationships and Related Transactions" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
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 1998 Annual Report to Shareholders, which have been incorporated by reference in this report:
Statements of Consolidated Income for the Years Ended December 31, 1998, 1997, and 1996, for each of PG&E Corporation and Pacific Gas and Electric Company.
Statements of Consolidated Cash Flows for the Years Ended December 31, 1998, 1997, and 1996, for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1998, and 1997, for each of PG&E Corporation and Pacific Gas and Electric Company.
Statement of Consolidated Common Stock Equity for the Years Ended December 31, 1998, 1997, and 1996, for PG&E Corporation.
Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities for the Years Ended December 31, 1998, 1997, and 1996, for Pacific Gas and Electric Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 55 of this Form 10-K.
3. Consolidated financial statement schedules:
I --Condensed Financial Information of Parent for the Years Ended December 31, 1998 and 1997.
II--Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 1998, 1997 and 1996.
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.
4.Exhibits required to be filed by Item 601 of Regulation S-K:
- -------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder.
(b) Reports on Form 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1998, and through the date hereof:
1. October 21, 1998 Item 5. Other Events -- Year-to-Date Financial Results
2. November 4, 1998 Item 5. Other Events A. Electric Industry Restructuring
3. November 25, 1998 Item 5. Other Events A. Electric Industry Restructuring
4. January 20, 1999 Item 5. Other Events A. 1998 Consolidated Earnings (unaudited) B.1999 Outlook C.Share Repurchase Program
5. February 17, 1999 Item 4. Changes in Registrant's Certifying Accountant Item 5. Other Events -- Share Repurchase Program - -------- (1) Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and Electric Company) and Commission File Number 1-12609 (PG&E Corporation)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 5th day of March, 1999.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant)
By /s/ Gary P. Encinas By /s/ Gary P. Encinas --------------------------------- --------------------------------- (Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
*By /s/ Gary P. Encinas ---------------------------- (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 Form 10-K, and have issued our report thereon dated February 8, 1999. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in Part IV, Item 14. (a)(3) in this Form 10-K are the responsibility of the management of PG&E Corporation and of Pacific Gas and Electric Company and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
San Francisco, California February 8, 1999
SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEET
SCHEDULE I--CONDENSED FINANCIAL INFORMATION FOR PARENT--(Continued)
CONDENSED STATEMENTS OF INCOME
For the years ended December 31, 1998 and 1997
CONDENSED STATEMENTS OF CASH FLOWS
For the years ended December 31, 1998 and 1997
PG&E CORPORATION
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1998, 1997, and 1996
- -------- (1) Deductions consist principally of write-offs. Reserve for deferred project costs and reserve for land costs are classified on the balance sheet in other noncurrent assets.
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1998, 1997, and 1996
- -------- (1) Deductions consist principally of write-offs. Reserve for deferred project costs and reserve for land costs are classified on the balance sheet in other noncurrent assets.
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
EXHIBIT INDEX
The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder. - -------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.