ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
PG&E Corporation was incorporated in California in 1995 for the purpose of becoming the parent holding company of Pacific Gas and Electric Company (PG&E). Effective January 1, 1997, PG&E became a subsidiary of PG&E Corporation. PG&E's ownership interest in PG&E Enterprises (Enterprises) and Pacific Gas Transmission Company (PGT) has been transferred to PG&E Corporation. PG&E's outstanding common stock was converted on a share-for- share basis into PG&E Corporation common stock. PG&E's debt securities and preferred stock were unaffected and remain securities of PG&E. The consolidated financial statements of PG&E incorporated herein include the accounts of PG&E and its wholly-owned and controlled subsidiaries (collectively, the Company), and, therefore, also represent the accounts of PG&E Corporation and its subsidiaries (also referred to collectively as, the Company). For financial information summarizing certain pro forma financial effects of the restructuring of PG&E, see "Formation of PG&E Corporation" below.
The principal executive offices of PG&E Corporation and PG&E are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and their telephone number is (415) 973-7000.
PG&E, incorporated in California in 1905, is an operating public utility engaged principally in the business of providing electric and natural gas services throughout most of Northern and Central California. As of December 31, 1996, the Company had $26.1 billion in assets. The Company generated $9.6 billion in operating revenues for 1996. As of December 31, 1996, the Company had approximately 22,000 employees.
PG&E's gas and electric utility operations, which include Diablo Canyon Nuclear Power Plant (Diablo Canyon) operations, represent the principal component of its business, contributing $9.2 billion in revenues in 1996 (96% of the Company's total revenues). PG&E's utility operations contributed $1.83 of the Company's total 1996 earnings per share of $1.75. (Utility earnings were offset by losses at Enterprises.)
Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. In 1996, Diablo Canyon contributed $1.8 billion of revenues (19% of the Company's total revenues) and $1.18 in earnings per share (67% of the Company's total 1996 earnings per share). PG&E has proposed a modification to existing Diablo Canyon ratemaking, which if adopted, would significantly reduce PG&E's future revenues from Diablo Canyon operations. See "Future Ratemaking--Electric Ratemaking" below.
PG&E's utility service territory covers 70,000 square miles with an estimated population of approximately 13 million, and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, financial services, food processing, petroleum refining, agriculture, and tourism.
At December 31, 1996, PG&E served approximately 4.5 million electric customers. PG&E serves its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, Diablo Canyon's two units, 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. (PG&E has announced plans to sell four fossil-fueled power plants, with an aggregate of 12 units, in connection with the ongoing electric industry restructuring. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below.) PG&E also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal, and cogeneration. In addition, PG&E is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling, and transmitting power.
PG&E served approximately 3.7 million gas customers at December 31, 1996. To ensure a diverse and competitive mix of natural gas supplies, PG&E purchases gas from both Canadian and United States suppliers. In 1996, about 65% of PG&E's gas supply came from fields in Canada, about 7% came from fields in California, and about 28% came from fields in other states (substantially all from the U.S. Southwest).
PG&E's utility operations in 1996 also included PGT's gas pipeline operations. PGT owns and operates gas transmission pipelines and associated facilities capable of transporting approximately 2.4 billion cubic feet per day of natural gas over 612 miles from the Canada-U.S. border to the Oregon- California border, as well as two smaller diameter pipeline extensions within Oregon, totaling 106 miles. In 1996, PGT acquired the PGT Queensland Gas Pipeline, an approximately 389-mile 12-inch pipeline in Queensland, Australia, which provides natural gas transportation service to customers in the vicinity of the pipeline. As noted above, at present PGT is a wholly owned subsidiary of PG&E Corporation.
Building on its expertise in the energy industry, PG&E Corporation is expanding its operations in the "midstream" portion of the gas business, the independent power generation business, and the energy services business. The midstream portion of the gas business includes gas gathering, processing, storage, and transportation. The energy services business includes obtaining gas and electricity from competitive producers, arranging for distribution and transmission service, and providing customized energy billing and analysis, power quality assessments, energy efficiency products and services, and facility improvements.
Enterprises, through its subsidiaries and affiliates, develops, owns, and operates unregulated electric and gas projects both in and outside the United States. Vantus Energy Corporation (Vantus), a subsidiary of Enterprises, markets gas and electricity commodities and provides energy services. In 1996, Enterprises generated approximately $127 million in revenues and accounted for $(0.08) of the Company's total 1996 earnings per share of $1.75. As noted above, Enterprises is now a wholly owned subsidiary of PG&E Corporation.
In December 1996, PGT acquired the gas marketing operations of Edisto Resources Corporation in the United States and Canada, known jointly as Energy Source, Inc. (ESI). The acquisition included most of ESI's existing contracts for the purchase, sale, and transportation of natural gas and natural gas futures. In January 1997, PG&E Corporation acquired Teco Pipeline Company (Teco) in Texas. Teco is an owner of a 500-mile natural gas pipeline system in Texas. Teco also has investments in gas gathering and processing facilities, and owns a gas marketing company in Houston, Texas. Also in January 1997, PG&E Corporation agreed to acquire Valero Natural Gas Company (Valero). Valero's operations include the gathering, transportation, marketing, and storage of natural gas, the processing, transportation, and marketing of natural gas liquids, and the marketing of electric power. Valero operates approximately 7,500 miles of natural gas pipeline and also owns and operates approximately 540 miles of natural gas liquid pipelines and eight natural gas processing plants in Texas. The acquisition is expected to be completed by mid-1997 and is subject to applicable regulatory and shareholder approvals.
The following discussion of the Company's business includes some forward- looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," and similar expressions identify forward-looking statements involving risks and uncertainties. Those risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas industries and the outcome of regulatory proceedings related to that restructuring. The ultimate impacts of both increased competition and the changing regulatory environment on future results are uncertain, but are expected to fundamentally change how the Company conducts its business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by the Company.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal
access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.
Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies are challenging the utilities' exclusive relationship with their customers and are seeking to replace certain utility functions with their own. Customers, too, are asking for choice in their energy provider. These pressures are causing a move from the existing regulatory framework to a framework under which competition would be allowed in certain segments of the gas and electric industries.
For several years, PG&E has been working with its regulators to achieve an orderly transition to competition and to ensure that PG&E has an opportunity to recover investments made under traditional regulatory policies. In addition, PG&E has proposed alternative forms of regulation for those services for which prices and terms will not be determined by competition. These alternative forms include performance-based ratemaking (PBR) and other incentive-based alternatives. Over the next five years, a significant portion of PG&E's business will be transformed from the current utility monopoly to a competitive operation. This change will impact PG&E's financial results and may result in greater earnings volatility. During the transition period, PG&E expects the return on Diablo Canyon and certain other generation assets to be significantly lower than historical levels.
ELECTRIC INDUSTRY
In 1995, the California Public Utilities Commission (CPUC) issued a decision that provides a plan to restructure California's electric industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called competition transition costs, or CTCs, through a nonbypassable charge to be collected over a period of years.
In 1996, legislation on electric industry restructuring, Assembly Bill 1890 (AB 1890), was signed into law in California. AB 1890 adopts the basic tenets of the CPUC's restructuring decision and establishes the operating framework for a competitive electric generation market. Key features of AB 1890 include:
--mandatory unbundling of transmission, distribution, and generation services;
--formation by January 1, 1998, of a California Power Exchange (PX) to provide a competitive auction process to establish the price of electricity;
--establishing an Independent System Operator (ISO) to ensure system reliability and provide electric generators with open and comparable access to transmission and distribution services;
--an electric rate freeze at 1996 levels until the earlier of March 31, 2002, or the point in time when PG&E has recovered its CTCs (the transition period);
--a 10% rate reduction by January 1, 1998, for residential and small commercial customers, financed through "rate reduction bonds";
--nonbypassable charges to provide the opportunity for utilities to recover their CTCs and required accelerated recovery of CTCs associated with utility owned generation facilities;
--direct access for all electric customers;
--market valuation for utility owned fossil generation assets by 2001, followed by an end to cost-of-service ratemaking for most plants; and
--continued support for renewable generation resources, conservation and other public purpose programs.
Under AB 1890, PG&E and other utilities will continue to own transmission and distribution facilities and must continue to offer bundled electric service to customers who request it.
Recent regulatory changes enacted at the federal level are also changing the electric industry. In 1996, the Federal Energy Regulatory Commission (FERC) paved the way for the transition to more competitive electric markets by providing open access to electric transmission. See "Electric Utility Operations--Electric Transmission" below.
Additional information concerning electric industry restructuring, the expected operating framework for a competitive generation market and the financial impact of these changes on the Company is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 29 of the 1996 Annual Report to Shareholders.
GAS INDUSTRY
Restructuring of the natural gas industry on both the national and state levels has given customers greater options in meeting their gas supply needs. PG&E's customers may buy commodity gas directly from competing suppliers and purchase transmission- and distribution-only services from PG&E. PG&E's transmission and distribution services have remained "bundled," or sold together at a combined rate, within California. PGT, as an interstate pipeline, has provided nondiscriminatory transmission-only service since 1993, and no longer sells commodity gas.
Most of PG&E's industrial and larger commercial (noncore) customers purchase their commodity gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers continue to buy commodity gas as well as transmission and distribution from PG&E as a bundled service.
In 1995 and 1996, PG&E actively pursued changes in the California gas industry in an effort to promote competition and increase options for all customers, as well as to position itself for the competitive marketplace. In 1996, PG&E submitted to the CPUC the Gas Accord Settlement (Gas Accord). The Gas Accord is the result of an extensive negotiation process, begun in 1995, among a broad coalition of customer groups and industry participants. The Gas Accord must be approved by the CPUC before it can be implemented. A CPUC decision is expected in 1997.
The Gas Accord consists of three broad initiatives:
--The Gas Accord would separate, or "unbundle," PG&E's gas transmission and storage services from its distribution services and would change the terms of service and rate structure for gas transportation. Unbundling would give customers the opportunity to select from a menu of services offered by PG&E and would enable them to pay only for the services they use. PG&E would be at risk for variations in revenues resulting from differences between actual and forecasted transmission throughput. PG&E would also continue to provide cost-of-service based distribution service, much as it does today.
--The Gas Accord would increase opportunities for PG&E's core customers to purchase gas from competing suppliers and, therefore, could reduce PG&E's role in procuring gas for such customers. However, PG&E would continue to procure gas as a regulated utility supplier for those customers who request it. The Gas Accord also would establish principles for continuing negotiations between PG&E and California gas producers for the mutual release of supply contracts and the sale of gas gathering facilities. Also related to PG&E's procurement activities, PG&E has proposed that traditional reasonableness reviews of its core gas costs be replaced with a core procurement incentive mechanism (CPIM) for the period June 1, 1994, through 2002. See "Future Ratemaking--Gas Ratemaking" below.
--The Gas Accord would resolve various regulatory issues including the recovery of certain capital costs associated with the PG&E portion (PG&E Expansion) of the PGT/PG&E Pipeline Expansion (Pipeline Expansion), recovery of costs related to PG&E's capacity commitments with Transwestern Pipeline Company (Transwestern) through 2002, certain disallowances ordered by the CPUC in connection with PG&E's 1988 through 1995 gas reasonableness proceedings, and the recovery, through the Interstate
Transition Cost Surcharge (ITCS), of fixed demand charges paid to El Paso Natural Gas Company (El Paso) and PGT for firm capacity held by PG&E on behalf of its customers.
Additional information concerning gas industry restructuring, and the financial impact of these changes on the Company is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 31 of the 1996 Annual Report to Shareholders.
REGULATION OF PG&E
STATE REGULATION
The CPUC consists of five members appointed by the governor and confirmed by the senate for six-year terms. The CPUC regulates PG&E's rates and conditions of service, sales of securities, dispositions of utility property, rate of return, rates of depreciation, uniform systems of accounts, examination of records, long-term resource procurement, and transactions between PG&E and its subsidiaries and affiliates. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition, and the environment, to determine its future policies.
The California Energy Commission (CEC) has discretion over electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California. Beginning January 1, 1998, the CEC will also administer funding for public purpose research and development, and renewable technologies programs. The funding will be collected from ratepayers through a nonbypassable public benefits charge. See "Electric Utility Operations--Electric Industry Restructuring Legislation--Public Purpose Programs" below.
FEDERAL REGULATION
Both PG&E and PGT are subject to regulation by the FERC. The FERC regulates electric transmission rates and access, compliance with the uniform systems of accounts, and electric contracts involving sales for resale. The FERC also regulates the interstate transportation of natural gas. In addition, most of PG&E's hydroelectric facilities are subject to licenses issued by the FERC.
The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities. NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities.
LOCAL REGULATION
PG&E has separate electric and gas franchises with the 48 counties and the 241 cities in its service territory. These franchises allow PG&E to locate facilities for the transmission and distribution of electricity and gas in the streets and other public ways. With few exceptions, the franchises do not have fixed terms and remain in effect as long as PG&E meets the terms and conditions of the franchises. PG&E is currently involved in litigation brought by several counties and cities who have granted franchises to PG&E. See Item 3, Legal Proceedings, "Counties Franchise Fees Litigation" and "Cities Franchise Fees Litigation" below for more information.
LICENSES AND PERMITS
PG&E obtains a number of permits, authorizations, and licenses in connection with the construction and operation of its generating plants. Discharge permits, various Air Pollution Control District permits, FERC hydroelectric facility licenses, and NRC licenses are the most significant examples. Some licenses and permits
may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements imposed by the granting agency.
REGULATION OF PG&E CORPORATION
PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding Company Act) on the basis that PG&E Corporation and PG&E are incorporated in the same state and their business is predominantly intrastate in character and carried on substantially in the state of incorporation. It is necessary for PG&E Corporation to file an annual exemption statement with the Securities and Exchange Commission (SEC), and the exemption may be revoked by the SEC upon a finding that the exemption may be detrimental to the public interest or the interest of investors or consumers. At present, PG&E Corporation has no intention of becoming a registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing PG&E to form a holding company was granted subject to various conditions related to finance, human resources, record and book-keeping, and the transfer of customer information. The financial conditions provide that PG&E is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, PG&E's dividend policy shall continue to be established by PG&E's Board of Directors as though PG&E were a comparable stand-alone utility company, and the capital requirements of PG&E, as determined to be necessary to meet PG&E's service obligations, shall be given first priority by the Boards of Directors of PG&E Corporation and PG&E. The conditions also provide that PG&E shall maintain on average its CPUC- authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition in the event an adverse financial event reduces the utility's equity ratio by 1% or more.
PG&E Corporation and PG&E have agreed to be subject to the conditions included in the CPUC approval. PG&E Corporation may also be subject to additional conditions based upon the outcome of an audit of affiliate transactions currently underway. The audit is being conducted by an outside consultant and supervised by the CPUC's Office of Ratepayer Advocates (ORA), formerly known as the Division of Ratepayer Advocates.
Other regulatory matters are described throughout this report.
RATE MATTERS
CALIFORNIA RATEMAKING MECHANISMS
The principal ratemaking mechanisms currently applied by the CPUC in setting PG&E's revenue requirements are described below. It is expected that many of these mechanisms may be changed significantly or eliminated as both the electric and gas utility industries are restructured and regulatory reforms proposed by PG&E and government authorities are implemented. See "Future Ratemaking" below.
PG&E's utility operations, other than Diablo Canyon, are regulated primarily under the traditional cost-based approach to ratemaking. In 1996, Diablo Canyon operations were regulated under a performance-based approach under which revenues for the plant are based primarily on the amount of electricity generated, rather than on the costs associated with the plant's operations. However, PG&E has proposed a significant modification to Diablo Canyon ratemaking. See "Electric Utility Operations--Diablo Canyon--Diablo Settlement" below.
PG&E's basic business and operational costs for its utility operations, other than Diablo Canyon, are recovered through base revenues. Base revenues are intended to recover operation and maintenance expenses (excluding fuel expenses, fuel-related energy costs, and purchased power costs), depreciation expense, taxes, and return on invested capital. Base revenue requirements are currently set in general rate case (GRC) proceedings
held before the CPUC every three years. (PG&E's current base revenues were set in the 1996 GRC; its next scheduled GRC would establish base revenue requirements effective January 1, 1999.)
During a GRC, the CPUC critically reviews PG&E's operations and general costs to provide service (excluding energy costs and, in certain instances, major plant additions), and then determines the revenue requirement to cover those costs. The revenue requirement is forecasted on the basis of a specified test year. (The return component of PG&E's revenue requirement is computed using the overall cost of capital authorized by the CPUC in the annual Cost of Capital consolidated proceeding, in which financing costs are reviewed and capital structures for all California energy utilities are adopted.) Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase, which allocates revenue requirements and establishes rate levels for the different classes of customers.
The Electric Revenue Adjustment Mechanism (ERAM) allows rate adjustments to offset the effect on base revenues of differences between actual electric sales volumes and the forecasted volumes used to set rates in the last GRC. The ERAM eliminates the impact on earnings of sales fluctuations, including those resulting from conservation and weather conditions. Base revenue differences resulting from the disparity between actual and forecasted electric sales accumulate in a balancing account, with interest. ERAM rate adjustments are made as part of the Energy Cost Adjustment Clause (ECAC) proceeding described below.
Most of PG&E's fuel, purchased-power, and energy-related costs of providing electric service, as well as revenues attributable to Diablo Canyon generation, are recovered through a balancing account mechanism called the ECAC. Under the ECAC balancing account procedure, actual costs are compared with revenues designated for recovery of such costs, and the difference is recorded as either an undercollection or overcollection. The differential between forecasted Diablo Canyon revenues under the Diablo Canyon rate case settlement (Diablo Settlement) and actual revenues also is tracked in the ECAC balancing account. In prior years, rates would be adjusted such that the amount of overcollections would be returned to ratepayers through lower rates and undercollections would be recovered through higher rates. However, as part of the electric industry restructuring, PG&E's electric rates have been frozen at 1996 levels, and the recorded overcollection in PG&E's ECAC/ERAM balancing accounts, if any, as of December 31, 1996, will be applied to offset PG&E's CTCs. See "1997 Revenues" below. The disposition of 1997 balancing accounts is being addressed at the CPUC in connection with electric industry restructuring. PG&E has proposed to recover 1997 year end balancing account balances through the CTC ratemaking mechanism.
The Annual Energy Rate (AER) mechanism has provided for recovery of 9% of forecasted electric fuel and fuel-related costs, without balancing account protection for differences between actual and forecasted costs. However, the AER was indefinitely suspended by the CPUC in a December 1996 decision.
In December 1996, the CPUC issued a decision establishing an electric deferred refund account (EDRA). The CPUC ordered PG&E to place into the EDRA credits for CPUC-ordered electric disallowances, the utility electric generation share of CPUC-ordered gas disallowances, electric and utility electric generation gas settlement amounts resulting from reasonableness disputes and fuel-related cost refunds made to PG&E based on regulatory agency decisions, plus interest charges. The CPUC ordered PG&E to file advice letters by January 31 of each year, setting forth its annual refund plans for directly refunding to electric customers the dollars accumulated in the EDRA. The CPUC also ordered PG&E to include initially in the EDRA any such credits which were already recorded in the ECAC and ERAM but had not yet been amortized in rates. The effect of this is to reduce the amount available to offset PG&E's CTCs by approximately $75 million. PG&E is seeking rehearing of this decision at the CPUC. PG&E is also seeking an injunction in federal court to block the refund of $50 million of the initial EDRA amount pending resolution of PG&E's lawsuit challenging the disallowance order issued in PG&E's 1988-1990 gas reasonableness proceeding that gave rise to that portion of the initial EDRA amount.
Fuel and fuel-related costs included in an ECAC adjustment are subject to a subsequent reasonableness review, in which the CPUC determines whether those costs were reasonably incurred. Costs found to be unreasonable may be disallowed, or deducted, from the amount to be recovered in rates. Currently, the amount of Diablo Canyon revenues recovered through the ECAC is determined under the Diablo Settlement and is not subject to reasonableness review. See "Electric Utility Operations--Diablo Canyon--Diablo Settlement" below.
The Biennial Cost Allocation Proceeding (BCAP) is the major rate proceeding for PG&E's natural gas service, other than service on the PG&E Expansion which is addressed in a separate proceeding. Rates to recover the cost of gas procured for customers who buy gas from PG&E and the cost of providing gas transportation service for gas customers are determined in the BCAP. The BCAP normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. Balancing accounts for natural gas costs and sales volumes are similar to those for electric fuel costs and sales volumes.
In addition to adopting the gas revenue requirements in the BCAP, the CPUC also allocates both the gas fuel and transportation revenue requirements among core and noncore classes and among the customer groups within those classes. The BCAP also includes the rate design process, in which it is determined how specific costs are recovered from customers, with rates set accordingly.
1997 REVENUES
Cost Recovery Plan. In December 1996, the CPUC approved the cost recovery plan filed by PG&E in compliance with AB 1890. The provisions of the plan approved by the CPUC include a freeze of electric rates at 1996 levels beginning on January 1, 1997, and pursuant to the provisions of AB 1890, an increase in PG&E's electric base revenues for 1997 of approximately $164 million to be used to enhance transmission and distribution system safety and reliability. In January 1997, The Utility Reform Network (TURN) filed an application for rehearing of the CPUC's decision. TURN's application for rehearing argues that the CPUC exceeded its authority in interpreting AB 1890 to authorize a base revenue increase for PG&E, and that the CPUC's decision requires clarification to ensure that any such base revenue increase as is granted is used only to fund activities which are supplemental to those funded in the most recent GRC. PG&E believes it is entitled to the base revenue increase provided for in AB 1890. However, if the CPUC were to find that those funds were not properly used to supplement PG&E's system safety and reliability expenditures, the CPUC might order disallowances that could negatively impact 1997 earnings.
ECAC. In December 1996, the CPUC issued a decision in PG&E's ECAC proceeding, authorizing a decrease in electric revenue requirements of approximately $720 million. The three elements of this decrease are: (1) a reduction in ECAC revenues of approximately $565 million; (2) a reduction in ERAM revenues of approximately $153 million; and (3) an increase in the California Alternate Rates for Energy (CARE) program, which supports energy rate discounts for low income customers, of approximately $2 million. This net reduction of approximately $720 million is partially offset by an electric revenue requirement increase of approximately $164 million resulting from the consolidation of revenue changes from the ERAM component of other proceedings, the base revenue increase authorized by AB 1890 and included in PG&E's cost recovery plan, the Cost of Capital proceeding, and the Annual Energy Assessment Proceeding (AEAP), which sets rate adjustments resulting from shareholder incentives earned on demand side management (DSM), or energy efficiency, programs. The ECAC decision also indefinitely suspends the AER mechanism, which had placed PG&E at partial risk for variations between actual and forecasted electric energy costs.
Cost of Capital. The CPUC's decision in the 1997 Cost of Capital proceeding authorized a utility return on common equity of 11.60%, a continuation of the 1996 level. The decision authorizes a utility capital structure for PG&E of 48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. The combined authorized costs of debt, preferred stock, and the 11.60% return on common equity result in an overall return on utility rate base (excluding Diablo Canyon and the PG&E Expansion) of 9.45%, a decrease from the 9.49% authorized for 1996. (However, actual returns for 1997 are expected to be substantially less than authorized levels as a result of the electric industry restructuring. See "Future Ratemaking--Electric Ratemaking" below.) Also as part of the Cost of Capital decision, the CPUC set the authorized return on equity and capital structure for the PG&E Expansion. See "Gas Utility Operations--PGT/PG&E Pipeline Expansion--CPUC Ratemaking" below.
BCAP. The CPUC's December 1995 decision in PG&E's last BCAP authorized an increase of approximately $60 million in annual gas revenues beginning January 1, 1996. In November 1996, PG&E submitted an interim filing, as permitted under the BCAP mechanism to set new rates for the second year of the
two-year BCAP period. If approved by the CPUC, the filing would result in an approximately $17 million increase in total gas revenues effective upon CPUC approval, which is not reflected in the table below.
AEAP. The CPUC's December 1996 decision in the annual AEAP, which determines shareholder incentives earned for PG&E's DSM programs, adopted an incentive payment of approximately $72 million for PG&E's 1995 programs, to be collected in installments over a 10-year period. After consolidating incentive payment installments from prior years, the net revenue change in 1997 from DSM shareholder incentives is an electric increase of approximately $9 million and a gas decrease of approximately $2 million.
The consolidated effect of these decisions on authorized revenue requirements for 1997 is indicated in the table below:
SUMMARY OF RATE CASE DECISIONS EFFECTIVE AS OF JANUARY 1, 1997 (IN MILLIONS)
Pursuant to PG&E's cost recovery plan and AB 1890, electric rates will not be changed from 1996 levels. Instead, the consolidated net reduction in electric revenue requirements of approximately $556 million will be available to offset PG&E's CTCs and any increase in revenue requirements resulting from PG&E's proposed cost recovery plan.
FUTURE RATEMAKING
Although it is clear that ratemaking for both electric and gas utilities in California will be significantly different in the future as a result of the ongoing restructuring in both industries, many of the specifics concerning how rates will be set, adjusted, and billed after 1997 remain to be resolved by the relevant regulatory authorities, utilities, and other interested parties. Outlined below are the more significant regulatory rulings to date on this issue, and some of the proposals made by PG&E in connection with changes to ratemaking in the new restructured markets.
ELECTRIC RATEMAKING
In December 1996, the CPUC issued a "roadmap" decision outlining the necessary steps to accomplish electric industry restructuring and commence the transition period no later than January 1, 1998. In that decision, the CPUC notes that ratemaking has not changed in that the CPUC will still determine the rate components, revenue allocation, and rate design necessary to derive a rate for each customer class. However, the CPUC recognizes that the process must be revised to accommodate changes in the electric industry necessary for implementation of AB 1890 and the new market structure beginning in 1998. A consideration of necessary changes includes unbundling of rates, transition costs, PBR, and other activities that affect rates and revenue requirements.
In its roadmap decision, the CPUC establishes a separate annual proceeding to consider ratemaking issues related to each electric utility's revenues, which will consolidate all pending revenue changes and track utility revenues at present rate levels for the purpose of comparison with authorized amounts. This annual Revenue Adjustment Proceeding (RAP) will be designed to annually review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and to make any necessary adjustments or
updates due to authorized revenues from PBR mechanisms and other proceedings, or revenues for various power purchase contracts, public purpose programs, nuclear facilities, nuclear decommissioning, and transition costs. The differential between actual recorded revenues and the consolidated authorized revenue requirement will be applied to recover CTCs. The authorized revenues will be established in their respective proceedings and consolidated into the RAP. The first RAP will begin in 1998.
PG&E has filed numerous regulatory applications and proposals that detail its cost recovery plan during the transition period. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of- service revenue requirement for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) accelerated recovery of transition costs, and (3) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period.
PG&E's unbundling application, filed in December 1996, proposes to unbundle PG&E's revenue requirements, enabling it to separate revenues provided by frozen rates into transmission, distribution, PPPs, and generation. As proposed, revenues collected under frozen rates would be assigned to transmission, distribution, and PPPs, based upon their respective cost of service. Revenue would also be provided for other costs, including nuclear decommissioning, rate-reduction-bond debt service, the ongoing cost of generation, and CTC recovery. The combination of a rate freeze and decreasing costs, based upon existing ratemaking and cost recovery periods, provides an adequate amount of revenue available for full CTC recovery. PG&E's unbundling application also presents a method to separate electric rates into the four functional cost categories of PPPs, distribution, transmission, and generation (including energy costs based on the PX price, and CTCs, determined after all other costs are accounted for), effective January 1, 1998. Bills for all customers would describe what portion of the bill is attributable to transmission, distribution, PPPs, energy, and CTCs and other nonbypassable charges. PG&E's unbundling application also proposes to replace the ECAC and ERAM during the transition period with a single balancing account, the Transition Revenue Account (TRA). The TRA would be functionally equivalent to the current system in that it would match revenues with cost components. With the TRA, CTC would be the only cost component for which recovery during the transition period would be affected by any variation in billed revenues due to sales fluctuations.
PG&E has proposed to accelerate recovery for certain CTCs related to generation facilities, including Diablo Canyon. Additionally, PG&E would receive a reduced return on common equity associated with generation plant assets for which recovery is accelerated. The lower return is intended to reflect reduced risk associated with the shorter amortization period and increased certainty of recovery.
In applying its cost recovery plan to Diablo Canyon, PG&E has proposed a significant modification to the existing Diablo Canyon ratemaking. Under the current Diablo Settlement, Diablo Canyon revenues are based on a pre- established price per kWh of plant generation. PG&E proposes to replace the existing settlement price with: (1) a sunk cost revenue requirement to recover fixed costs, including a return on those fixed costs, and (2) a PBR mechanism to recover the facility's variable costs and capital addition costs. As proposed, the sunk cost revenue requirement would accelerate recovery of Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five- year period beginning in 1997 and ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90% of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52% in 1996. The reduced rate of return combined with a shorter recovery period would result in an estimated $4.0 billion decrease in the net present value of PG&E's future revenues from Diablo Canyon operations. If the proposed cost recovery plan for Diablo Canyon had been adopted during 1996, Diablo Canyon's 1996 reported net income would have been reduced by $350 million ($0.85 per share). The assigned CPUC administrative law judge (ALJ) has issued a proposed decision on PG&E's proposal to modify existing Diablo Canyon ratemaking. With significant exceptions, the proposed decision generally adopts the overall ratemaking structure proposed by PG&E, but would substantially alter the proposed ICIP mechanism and would exclude certain items from the sunk cost revenue requirement. See "Electric Utility Operations--Diablo Canyon--Diablo Settlement" below for more information regarding PG&E's proposed modification and the proposed decision issued by the ALJ. The proposed decision is not a final decision of the CPUC, and is subject
to change prior to a vote of the full CPUC. The proposed decision currently is scheduled for consideration by the full CPUC at its April 9, 1997 meeting.
PG&E has proposed a PBR mechanism for recovery of its hydroelectric and geothermal generating unit costs. The proposed mechanism consists of a base revenue amount that is adjusted to account for inflation less a productivity offset. In its unbundling application, PG&E proposed a starting point for the hydroelectric/geothermal generation PBR at approximately $545 million in 1998. Under the AB 1890 cost recovery plan submitted by PG&E and approved by the CPUC, the difference between the authorized revenue requirement for these units and revenues earned at PX prices would be credited against CTC recovery if, as currently expected, the revenues earned at market prices exceed the cost of operating these facilities as set under the PBR mechanism.
Additional information concerning the Company's transition cost recovery plan, the financial impact of electric industry restructuring and these various proposals is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Notes 2 and 4 of the "Notes to Consolidated Financial Statements" beginning on pages 29 and 32, respectively, of the 1996 Annual Report to Shareholders.
GAS RATEMAKING
As noted above (see "Competition and the Changing Regulatory Environment-- Gas Industry" above), PG&E has submitted to the CPUC the Gas Accord, which would offer increased customer choice, establish gas transmission rates for the period July 1997 through December 2002, and resolve various pending regulatory issues. The Gas Accord must be approved by the CPUC before it can be implemented. Among other things, the Gas Accord would unbundle PG&E's gas transmission and storage services from its distribution services and would change the terms of service and rate structure for gas transportation. Unbundling would give customers the opportunity to select from a menu of services offered by PG&E and would enable them to pay only for the services they use. PG&E would be at risk for variations in revenues resulting from differences between actual and forecasted transmission throughput. PG&E would continue to provide cost-of-service based distribution service, much as it does today. Additional information concerning the potential financial impact of the Gas Accord is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 31 of the 1996 Annual Report to Shareholders.
As part of the Gas Accord, PG&E has proposed that traditional reasonableness reviews of its core gas costs be replaced with a CPIM for the period June 1, 1994, through 2002. Under the CPIM, PG&E would be able to recover its gas commodity and interstate transportation costs and would receive benefits or be penalized depending on whether its actual core procurement costs were within, below, or above a "tolerance band" constructed around market benchmarks. Actual core procurement costs measured for the period June 1, 1994, through December 31, 1996, have generally been within the CPIM "tolerance band." The CPIM proposal also requests authorization to use derivative financial instruments to reduce the risk of gas price and foreign currency fluctuations. Gains, losses, and transaction costs associated with the use of derivative financial instruments would be included in the purchased gas account and the measurement against the benchmarks.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
PG&E and PGT continue to require capital for improvements to facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. PG&E's and PGT's expenditures for these purposes, including the allowance for funds used during construction (AFUDC), were approximately $1,244 million for 1996. New investments totaled $159 million in 1996.
The following table sets forth PG&E Corporation's estimated total capital requirements, consisting of capital expenditures for PG&E's utility functions, including Diablo Canyon, as well as capital requirements for PGT and diversified operations and amounts for maturing debt and sinking funds for the years 1997 through 1999. These are forward-looking statements which involve a number of assumptions and uncertainties. Actual amounts may differ materially from the estimated amounts shown below.
PG&E CORPORATION CAPITAL REQUIREMENTS (IN MILLIONS)
- -------- (1) Utility expenditures include PG&E's electric and gas operations and PGT's gas pipeline operations, are shown net of reimbursed capital, and include AFUDC.
(2) Actual capital expenditures may vary significantly depending on the availability of attractive investment opportunities. PG&E has announced an agreement to sell its interest in International Generating Company, Ltd. in 1997 and capital requirements for that company are not included in the table.
(3) U.S. Generating Company expenditures include commitments by PG&E Corporation, PG&E, and/or Enterprises to make capital contributions for Enterprises' equity share of currently identified generating facility projects. These contributions, payable upon commercial operation of the projects, are estimated to be $52 million and $15 million in 1997 and 1998, respectively.
(4) Other expenditures include ongoing capital requirements for ESI and Teco.
Most of Utility and Diablo Canyon capital expenditures for 1997 through 1999 are associated with short lead time, modest capital expenditure projects aimed at the replacement and enhancement of existing facilities, and compliance with environmental laws and regulations. Also included are expenditures to improve the safety and reliability of PG&E's electric transmission and distribution system consistent with AB 1890, as well as major projects associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years 1997 through 1999 will include approximately $1,140 million for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt, as indicated above.
The funds necessary for 1997-1999 capital requirements of PG&E Corporation and its subsidiaries will be obtained from (i) internal sources, principally net income before noncash charges for depreciation and deferred income taxes, and (ii) external sources, including short-term financing, such as bank loans and the sale of short-term notes, and long-term financing, such as sales of equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing review of their capital expenditures and financing programs. The programs and estimates above are subject to revision and actual amounts may vary based upon changes in assumptions as to system load growth, rates of inflation, receipt of adequate and timely rate relief, availability and timing of regulatory approvals, total cost of major projects, availability and cost of suitable nonregulated investments, and availability and cost of external sources of capital, as well as the outcome of the ongoing restructuring in both the electric and gas industries.
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for approximately $380 million, consisting of the purchase of a $61 million note, and $319 million of PG&E Corporation common stock. Also in January 1997, PG&E Corporation agreed to acquire Valero for approximately $1.5 billion, consisting of approximately $720 million of PG&E Corporation common stock and the assumption of debt and liabilities. The cost of these acquisitions is not included in the table above, nor are estimates of expected ongoing capital requirements for Valero.
RISK MANAGEMENT PROGRAMS
Due to the changing business environment, the Company's exposure to risks associated with changes in energy commodity prices, interest rates, and foreign currencies is increasing. To manage these risks, the Company has adopted a price risk management policy and established an officer-level price risk management committee. The Company's price risk management committee oversees implementation of the policy, approves each price risk management program, and monitors compliance with the policy.
The Company's price risk management policy and procedures adopted by the committee establish guidelines for implementation of price risk management programs. Such programs may include the use of energy and financial derivatives. (A derivative is a contract whose value is dependent on or derived from the value of some underlying asset.) Additionally, the Company's policy allows derivatives to be used for hedging and non-hedging purposes. (Hedging is the process of protecting one transaction by means of another to reduce price risk.) Both hedging and non-hedging activities are limited to those specifically approved by the committee only after appropriate controls and procedures are put in place to measure, monitor, and control the risk of such activities. The Company's policy prohibits the use of derivatives whose payment formula includes a multiple of some underlying asset.
In 1996, the Company approved and implemented interest rate and foreign exchange risk management programs, applied for regulatory approval to use energy derivatives to manage commodity price risk in its utility business, and acquired certain natural gas marketing operations which engage in both hedging and non-hedging derivative transactions. Gains and losses associated with price risk management activities during 1996 were immaterial.
Additional information concerning the Company's risk management activities is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 18, and in Note 1 of the "Notes to Consolidated Financial Statements" on page 28 of the 1996 Annual Report to Shareholders.
ELECTRIC UTILITY OPERATIONS
ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION
In 1996, comprehensive legislation on electric industry restructuring, in the form of AB 1890, was signed into law in California. AB 1890 adopted the basic tenets of the CPUC's 1995 restructuring decision and provides guidance to the CPUC on a number of implementation issues. Although many details remain to be worked out, implementation of AB 1890 will have a significant impact on PG&E's electric utility operations beginning as early as 1998.
Major provisions of AB 1890 include the following:
INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE
AB 1890 requires the CPUC to facilitate the development of an ISO and a PX, and establishes a five-member Oversight Board to oversee the ISO and PX and appoint the members of the ISO and PX Governing Boards. The ISO and PX Governing Boards will include representatives of investor owned utility transmission owners, publicly owned utility transmission owners, nonutility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives. In a November 1996 order approving in concept the proposed ISO/PX framework, the FERC limited the ongoing role of the Oversight Board and eliminated the requirement of AB 1890 that members of the Oversight Board be residents of California.
Under AB 1890, it is intended that both California's investor owned utilities and its publicly owned utilities commit control of their transmission facilities to the ISO. The ISO is required to ensure reliable transmission services consistent with planning and operating reserve criteria no less stringent than those established by the Western Systems Coordinating Council and the North American Electric Reliability Council. Oversight responsibility for reliability of utility distribution systems remains with the CPUC.
To prevent undue influence on the PX price by any participant in the competitive framework, PG&E has indicated that it is willing to proceed with voluntary divestiture of at least 50% of its fossil-fueled power plants as directed by the CPUC. PG&E has filed an application seeking approval from the CPUC to sell four plants (comprised of 12 units) before the end of 1997. The book value for these plants is approximately $400 million, and together they generate approximately 10% of PG&E's total electric sales. PG&E proposes to recover any shortfall in proceeds from divestitures of these plants as CTCs.
DIRECT ACCESS
AB 1890 authorizes direct transactions between electricity suppliers and customers, beginning January 1, 1998, and on a phased-in schedule, if justified by technical considerations, through December 31, 2001, that is equitable to all customer classes. Aggregation of customer electrical load for such direct transactions is authorized.
RATE LEVELS AND RECOVERY OF CTCS
AB 1890 provides for a 10% rate reduction for residential and small commercial electric customers, freezes electric customer rates for all other customers, and requires the accelerated recovery of CTCs associated with utility owned generation facilities. The rate freeze will continue until the end of the transition period, which extends to the earlier of March 31, 2002, or until PG&E has recovered its CTCs. The freeze will hold rates at 1996 levels for all customers except those receiving the 10% rate reduction. The rate freeze will hold the rates for these customers at the reduced level.
To achieve the 10% rate reduction, AB 1890 authorizes utilities to finance a portion of their CTCs with "rate reduction bonds." PG&E expects to work with state authorities to coordinate the issuance of up to
$2.5 billion of these bonds by a special purpose entity. The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current cost of capital. Once the bonds are issued, PG&E would collect, on behalf of the special purpose entity, a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs will lower the amounts paid by these customers each year during the transition period thereby achieving the 10% reduction in rates. PG&E does not expect to secure the bonds with the Company's assets or unrelated future revenues.
AB 1890 authorizes utilities to recover transition costs, or CTCs (the uneconomic costs of their generation-related assets and obligations, including regulatory assets and the costs associated with nuclear ratemaking settlements such as the Diablo Settlement), from all customers (with certain exceptions) through a nonbypassable charge included as part of rates over the period ending December 31, 2001. Recovery may extend beyond December 31, 2001, for certain CTCs, such as certain employee-related transition costs (recoverable through December 31, 2006) and costs resulting from implementation of direct access and creation of the PX and ISO, and above market costs associated with power purchase agreements. As a prerequisite to any consumer obtaining direct access services, the consumer must agree to pay its applicable nonbypassable CTC charge.
CTCs associated with utility owned fossil generation would be limited to regulatory assets and the uneconomic net book value of the fossil capital investment as of January 1, 1998, plus the costs of capital additions subsequent to December 20, 1995, that the CPUC determines are reasonable and, in the case of fossil plant additions, are necessary to maintain the facilities through December 31, 2001. CTCs associated with utility owned generation-related costs not recovered during the transition period will be absorbed by PG&E. Operating costs for such facilities would generally be recoverable through market-based rates, excluding facilities that are required to be operated for reliability purposes by the ISO. Operating costs for those facilities would be recovered on a cost-of-service basis through ISO contracts. CTCs associated with existing power purchase contracts, such as those for purchases from qualifying facilities (QFs), also would be recoverable through nonbypassable rates, except that the recovery period would be over the duration of the contract or any restructuring thereof.
Nuclear decommissioning costs would continue to be recovered through a nonbypassable charge separate from CTCs until fully recovered. Recovery of nuclear decommissioning costs may be accelerated.
BASE REVENUE INCREASES
AB 1890 provides for annual increases in base revenues for PG&E, effective in 1997 and 1998, equal to the inflation rate for the prior year plus two percentage points. Given the rate freeze, the base revenue increase would reduce the amount available for CTC recovery. The increases will remain in effect pending PG&E's next GRC, which will set rates effective January 1999. The base revenue increases must be used for enhancing transmission and distribution system safety and reliability, and any such revenues not expended for such purposes must be credited against subsequent safety and reliability revenue requirements in future years.
In December 1996, the CPUC approved the cost recovery plan filed by PG&E in compliance with AB 1890, which included an increase in PG&E's electric base revenues for 1997 of approximately $164 million to be used to enhance transmission and distribution system safety and reliability as contemplated by AB 1890. TURN has filed an application for rehearing of the CPUC's decision, challenging the base revenue increase. See "General--Rate Matters--1997 Revenues" above.
PUBLIC PURPOSE PROGRAMS
Under AB 1890, energy efficiency, research and development, and low income programs will be funded in electric rates pursuant to a separate, nonbypassable charge at current levels from January 1, 1998, through December 31, 2001. Under this provision, PG&E is obligated to fund through electric rates energy efficiency and conservation programs at not less than $106 million per year, research and development programs at not less than $30 million per year, and renewable technologies at not less than $48 million per year.
In February 1997, the CPUC adopted a decision that changes the way these programs will be administered, beginning after 1997. Currently, PG&E and other utilities administer public purpose programs for energy efficiency and conservation, research and development and low income customer assistance. Under the CPUC's decision, the CPUC will appoint independent boards to oversee energy efficiency and low income assistance programs. These boards will solicit competitive bids to determine who will administer the programs from January 1, 1998, through 2001. PG&E or an affiliate will be permitted to bid for administration of the energy efficiency programs. The decision also turns over administration of the funding for research and development, and renewable technologies programs to the CEC, beginning January 1, 1998.
Additional information concerning AB 1890 and its financial impact on the Company is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 29 of the 1996 Annual Report to Shareholders.
ELECTRIC OPERATING STATISTICS
The following table shows PG&E's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
- --------
(1) Includes energy supplied through PG&E's system by the City and County of San Francisco for San Francisco's own use and for sale by San Francisco to its customers, by the Department of Energy for government use and sale to its customers, and by the State of California for California Water Project pumping, as well as energy supplied by QFs and purchases from other utilities. (2) Includes energy output from Modesto and Turlock Irrigation Districts' own resources. (3) Represents energy required for pumping operations. (4) Includes use by business units other than the electric utility business units.
- -------- (1) Area net capability at time of annual peak, based on actual water conditions. (2) Net control area peak demand includes demand served by Modesto and Turlock Irrigation Districts' own resources.
ELECTRIC GENERATING AND TRANSMISSION CAPACITY
As of December 31, 1996, PG&E owned and operated the following generating plants, all located in California, listed by energy source:
- -------- (1) Two hydroelectric plants with approximately 5,000 kW of net operating capacity were sold in 1996. (2) PG&E has announced plans to sell these power plants in connection with electric industry restructuring. (3) Listed to show capability; subject to relocation within the system as required. (4) The Geysers Power Plant net operating capacity is based on adequate geothermal steam supply conditions. Any decrease in capacity, at peak, is included as unavailable capacity in the Control Area Net Capacity table below.
The following table sets forth the available capacity for the control area (the area served by PG&E and various publicly owned systems in Northern California) at the date of peak (including reduction for scheduled and forced outages and based on actual water conditions) by various sources of generation available to the control area and the total amount of generation provided by these sources during the year ended December 31, 1996.
- -------- (1) The maximum control area peak demand to date was 21,437,000 kW which occurred in August 1996. (2) The reserve capacity margin at the time of the 1996 control area peak, taking into account short-term firm capacity purchases from utilities located outside PG&E's service area: PG&E's load responsibility for spinning reserve (capability already connected to the system and ready to meet instantaneous changes in demand) to the control area peak was 7.3% of the peak demand and total reserve (spinning reserve and capability available within a short period of time) was 7.8%. (3) Represents actual year net generation from sources shown. Generation received from others is based on the best available information at the publication date of this document.
DIABLO CANYON
DIABLO CANYON OPERATIONS
Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. The operating license expiration dates for Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively. As of December 31, 1996, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 79.7% and 81.7%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next five years. In the past, Diablo Canyon refueling outages typically have occurred every 18 months. Beginning in 1996, PG&E schedules refueling outages every 21 months, and it intends to seek NRC licensing authority to schedule such outages once every 24 months beginning in 2001. The schedule below assumes that a refueling outage for a unit will last approximately six weeks, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages or changes in the length of the fuel cycle.
DIABLO SETTLEMENT
The Diablo Settlement adopted alternative ratemaking for Diablo Canyon by basing revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. Under the existing Diablo Settlement, revenues are based on a pre-established price per kWh of electricity generated by the plant. That price consists of a fixed component (3.15 cents per kWh) and a separate component that declines until 2000, at which point the variable component begins to escalate. The total price per kWh for the year 1996 was 10.50 cents. Under this "performance-based" approach, PG&E assumes a significant portion of the operating risk of the plant because the extent and timing of the recovery of actual operating costs, depreciation, and a return on the investment in the plant primarily depend on the amount of power produced and the level of costs incurred. PG&E's earnings are affected directly by plant performance and costs incurred. Currently, earnings relating to Diablo Canyon can fluctuate significantly as a result of refueling or other extended plant outages, plant expenses, and the effects of a peak-period pricing mechanism.
As noted above, in connection with electric industry restructuring, PG&E has proposed to modify the existing Diablo Settlement. Under the modification proposal, PG&E would replace the existing Diablo Settlement price with a sunk cost revenue requirement and a performance-based Incremental Cost Incentive Price (ICIP). The sunk cost revenue requirement for Diablo Canyon would include recovery of the net investment in Diablo Canyon over a five-year period and a return on common equity of 90% of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52% in 1996. Under the ICIP, the plant's variable and other operating costs and future capital additions would be recovered under a pre-set price per kWh of plant output based on an initial expectation of such costs and output.
Under PG&E's modification proposal, the termination date in the existing Diablo Settlement would be changed from 2016 to 2001. As proposed, closure cost recovery provisions would replace existing abandonment payment provisions. Under the cost recovery provisions, PG&E would be entitled to recover a percentage of its annual operating costs for a limited number of years following the plant's permanent closure. PG&E's continued recovery of the sunk cost revenue requirement would be subject to CPUC evaluation if Diablo Canyon is shut down for nine months or more before the end of the transition period. After such time, there would be no restrictions on Diablo Canyon's operations, to which customers it could sell and at what prices, terms, and
conditions; however, 50% of any after-tax earnings available for common equity after such time would be allocated to ratepayers.
More information concerning the financial impact of the proposed Diablo Settlement modification is included in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and in Notes 2 and 4 of the "Notes to Consolidated Financial Statements" beginning on pages 29 and 32, respectively, of the 1996 Annual Report to Shareholders.
On February 28, 1997, the assigned ALJ issued a proposed decision on PG&E's proposed modification to Diablo Canyon ratemaking. With significant exceptions, the proposed decision generally adopts the overall ratemaking structure proposed by PG&E, but would substantially alter the proposed ICIP mechanism and would exclude certain items from the sunk cost revenue requirement.
Instead of adopting the fixed forecast of ICIP prices for the 1997-2001 period proposed by PG&E, the proposed decision adopts an alternative cost of service approach, which would establish an initial forecast of ICIP prices which will be adjusted annually through 2001 to reflect a new forecast incorporating Diablo Canyon's actual operating costs and capacity factor. With respect to sunk costs, the proposed decision adopts a "prudence" disallowance based on the finding that PG&E admitted in pre-1988 Diablo testimony that a design error cost $100 million. The disallowance would be equal to $100 million times the ratio of depreciated value of the original plant to undepreciated value of the original plant, which PG&E estimates would equal approximately $60-$70 million. The proposed decision also excludes several items totaling $160 million from the sunk cost revenue requirement, including out-of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The proposed decision requires that out-of-core fuel inventory and materials and supplies inventory be recovered in ICIP prices. The proposed decision requires an independent financial verification audit of Diablo Canyon sunk costs, to be completed within six months. Diablo Canyon sunk cost recovery would be adjusted to reflect the results of this audit.
In addition, the proposed decision terminates, rather than modifies as proposed by PG&E, the Diablo Settlement on the date the proposed decision is adopted by the CPUC. PG&E intends to seek clarification from the CPUC that the termination of the Diablo Settlement would not affect Diablo Canyon's "must take" status during the transition period.
Based on a very preliminary review and interpretation of the proposed decision and assuming that the modified rates are effective January 1, 1997, PG&E Corporation estimates that the impact on 1997 earnings could be approximately five cents per share negative compared to PG&E Corporation's 1997 budget. This estimate is subject to change, and the actual impact of the proposed decision on the Company's financial results will depend on several factors, including clarification of several ambiguities in the proposed decision. In addition, there could be a further negative impact compared to PG&E Corporation's 1997 budgeted results if the modified rates are effective on the date the CPUC adopts the final decision, given the timing of recovery of Diablo Canyon transition costs.
The proposed decision is not a final decision of the CPUC, and is subject to change prior to a vote of the full CPUC. The proposed decision currently is scheduled for consideration by the full CPUC at its April 9, 1997 meeting.
NUCLEAR FUEL SUPPLY AND DISPOSAL
PG&E has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium; it has one contract for fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, the conversion of uranium to uranium hexaflouride, and the enrichment of the uranium hexaflouride to enriched uranium will be satisfied by a combination of existing contracts and inventories through 2000, 1999, and 2002, respectively. The fuel fabrication contract for the two units will supply their requirements for the next eight operating cycles of each unit. These contracts are intended to ensure long- term
fuel supply, but permit PG&E the flexibility to take advantage of short-term supply opportunities. In most cases, PG&E's nuclear fuel contracts are requirements-based, with PG&E's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, PG&E has signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from PG&E's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has officially acknowledged that it will not be able to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted by the DOE for interim or permanent storage before 2012, at the earliest. At the projected level of operation for Diablo Canyon, PG&E's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2006. PG&E is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility.
In July 1988, the NRC gave final approval to PG&E's plan to store radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the unit. The license amendment issued by the NRC allows storage of spent fuel rods at Humboldt until a federal repository is established. PG&E has agreed to remove all nuclear waste as soon as possible after the federal disposal site is available.
INSURANCE
PG&E has insurance coverage for property damage and business interruption losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). These companies, which are owned by utilities with nuclear generating facilities, provide insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. Under PG&E's policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, PG&E may be subject to maximum retrospective premium assessments of $29 million (property damage) and $8 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NML or NEIL.
PG&E has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $8.7 billion of coverage is provided by secondary financial protection required by federal law and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, PG&E may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident.
DECOMMISSIONING
The estimated total obligation for decommissioning PG&E's nuclear power facilities is comprised of the total cost (including labor, materials, and other costs) of decommissioning and dismantling plant systems and structures. In addition, a contingency amount for possible changes in regulatory requirements and increases in waste disposal costs is included in the estimated total obligation. The estimated total obligation for nuclear decommissioning costs, based on a 1994 site study, is approximately $1.2 billion in 1996 dollars (or $5.9 billion in future dollars). Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, and costs of labor, materials, and equipment. The estimated total obligation is being recognized proportionately over the license term of each facility.
Decommissioning costs recovered in rates are placed in external trust funds. These funds, along with accumulated earnings, will be used exclusively for decommissioning. The trust funds maintain substantially all of their investments in debt and equity securities. All fund earnings are reinvested. Funds may not be released from the external trust funds until authorized by the CPUC. As of December 31, 1996, PG&E had accumulated external trust funds with an estimated fair value of $883 million, based on quoted market prices, to be used for the decommissioning of PG&E's nuclear facilities.
In the past, the amount recovered in rates for decommissioning costs through an annual allowance has been reviewed by the CPUC as part of the GRC. The CPUC considers the trust's asset level, together with revised earnings and decommissioning cost assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trust. The funds contributed to the decommissioning trusts, together with existing trust fund balances and projected earnings, are intended to satisfy the estimated future obligation for decommissioning costs. For the year ended December 31, 1996, nuclear decommissioning costs recovered in rates were $33 million.
In the future, AB 1890 provides that nuclear decommissioning costs, which are not transition costs, will be recovered through a nonbypassable charge until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. In its roadmap decision, the CPUC established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and establish the annual revenue requirement and attrition factors over three-year periods when and if GRCs are discontinued.
OTHER ELECTRIC RESOURCES
QF GENERATION AND OTHER POWER PURCHASE CONTRACTS
Under the Public Utility Regulatory Policies Act of 1978, PG&E is required to purchase electric energy and capacity provided by QFs which are cogenerators and small power producers. The CPUC established a series of power purchase contracts with QFs and set the applicable terms, conditions, and price options. Under these contracts, PG&E is required to purchase electric energy and capacity; however, payments are only required when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. PG&E's contracts with QFs expire on various dates from 1997 to 2028. Energy payments to QFs are expected to decline in the years 1997 through 2000. Capacity payments are expected to remain at current levels.
In 1996, 1995 and 1994, PG&E negotiated the early termination or suspension of certain QF contracts at discounted costs of $25 million, $142 million, and $155 million, respectively. Amounts to be paid for termination or suspension are payable through 1999. These amounts are expected to be recovered in rates. At December 31, 1996, the total discounted future payments remaining under QF early termination or suspension contracts was $68 million.
QF deliveries in the aggregate account for approximately 19% of PG&E's 1996 electric energy requirements and no single contract accounted for more than 5% of PG&E's energy needs.
PG&E also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, PG&E must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the provider's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the providers. These contracts expire on various dates from 2004 to 2031. The total cost of these payments is recoverable in rates. At December 31, 1996, the undiscounted future minimum payments under these contracts are $34 million for each of the years 1997 through 2001, and a total of $383 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 6% of PG&E's 1996 electric energy requirements, and no single contract accounted for more than 5% of PG&E's energy needs.
The amount of energy received and the total payments made (including termination and suspension payments) under QF contracts and other power purchase contracts were:
As of December 31, 1996, PG&E had approximately 5,800 megawatts (MW) of QF capacity under CPUC-mandated power purchase agreements. Of the 5,800 MW, approximately 4,600 MW were operational. Development of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 5,800 MW of QF capacity consists of 2,900 MW from cogeneration projects, 1,700 MW from wind projects and 1,200 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric.
GEOTHERMAL GENERATION
PG&E's geothermal units at The Geysers Power Plant (Geysers) are forecast to operate at reduced capacities because of declining geothermal steam supplies and curtailment of the Geysers due to the existence of more economic sources of electric generation. PG&E's agreements with several of its steam suppliers permit PG&E to curtail generation at the Geysers at PG&E's discretion. The consolidated Geysers capacity factor is forecast to be approximately 40% of installed capacity in 1997, which includes economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 42% in 1996.
HELMS PUMPED STORAGE PLANT
Helms is a three-unit hydroelectric combined generating and pumped storage facility, completion of which was delayed due to a water conduit rupture in September 1982 and various start-up problems related to the plant's generators. Helms became commercially operable in June 1984. As a result of the damage caused by the rupture and the delay in the operational date, PG&E incurred additional costs which were not initially included in rate base, and lost revenues during the period the plant was under repair. In September 1996, the CPUC approved a settlement resolving the treatment of remaining unrecovered Helms costs.
As part of the 1996 GRC decision issued in December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of Helms. The CPUC indicated the study should consider changes in rate recovery for the plant including, among other things, the option of retirement with recovery of the investment without a return. The cost-effectiveness study submitted by PG&E in July 1996 concluded that the continued operation of Helms is cost effective. PG&E recommended that the CPUC take no action based on the study, but address Helms along with other generating plants in the context of electric industry restructuring. PG&E is currently unable to predict whether there will be a change in rate recovery resulting from the study. As with its other hydroelectric generating plants, PG&E expects to seek recovery of its net investment in Helms ($710 million at December 31, 1996) through the hydroelectric and geothermal PBR and CTC recovery.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
At present, California's long-range electric resource planning is coordinated between the CEC and the CPUC. Applicable statutes require that, every two years, the CEC prepare an Electricity Report that includes load forecasts and resource assumptions for a 20-year period and the CPUC conduct a Biennial Resource Plan Update (BRPU) proceeding which is linked to a specific CEC Electricity Report. The purpose of the BRPU is to determine whether any cost-effective electric resources (either new generating resources or power purchases) should be added to the regulated utilities' electric systems based on a 12-year planning horizon. In making this
determination, the CPUC gives great weight to the load forecasts and resource assumptions included in the CEC's Electricity Report. However, in light of the restructuring of the electric utility industry, it is unclear what relevance, if any, the BRPU and the CEC's Electricity Report proceedings will have with regard to California utility resource planning and procurement in the future. The timetable for release of the draft 1996 Electricity Report has been delayed.
The future of electric resource acquisition is being addressed as part of electric industry restructuring. Under the plan contemplated in the CPUC's restructuring decision issued in December 1995, utilities would retain the obligation to acquire resources for customers who continue to take bundled electric utility services, but this obligation would be met entirely through purchases from the PX during the transition period starting January 1, 1998. Beginning in 2002, PG&E could acquire power from sources other than the PX to satisfy the demands of its utility customers.
PG&E's demand forecasts and resource procurement plans are subject to possibly significant changes depending on the ultimate outcome of electric industry restructuring. In 1997, PG&E does not anticipate adding any new MW of resources to its system. PG&E currently plans no new major construction projects for electric supply.
ELECTRIC TRANSMISSION
To transport energy to load centers, PG&E as of December 31, 1996, owned and operated approximately 18,516 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 32,892,000 kilovolt-amperes (kVa). Energy is distributed to customers through approximately 108,170 circuit miles of distribution system and distribution substations having a capacity of approximately 23,000,000 kVa.
Traditionally, the transmission of electric energy in interstate commerce and the sale of electric energy for resale (wholesale sales) have been regulated by the FERC. In 1996, the FERC issued an order requiring utilities to provide wholesale open access to electric transmission systems on terms that are comparable to the way utilities use their own systems. PG&E's open access tariff, filed in July 1996, is now available for service to any eligible party interested in wholesale transmission service over PG&E's transmission system. The FERC also reaffirmed its intention to permit utilities to recover any legitimate, verifiable, and prudently incurred costs stranded as a result of customers taking advantage of wholesale open access orders to meet their power needs from other sources.
Pursuant to the CPUC's electric industry restructuring decision, PG&E and the other two California investor owned electric utilities filed a joint ISO application with the FERC. The application requested authorization to transfer operational control (but not ownership) of certain transmission facilities to the ISO. The ISO will control the dispatch of generation and the operation of the transmission system and provide open access transmission service on a nondiscriminatory basis. In November 1996, the FERC issued an order approving the structure of the ISO and PX as proposed by the utilities, but requiring detailed tariffs and other required filings by March 31, 1997. Also in connection with electric industry restructuring, the FERC issued an order in December 1996 addressing market power issues. That decision relied on measures to mitigate and monitor market power rather than on continued studies to determine whether the utilities had market power.
The FERC has also approved a proposal from PG&E and the other California utilities that distinguishes between local distribution facilities and transmission facilities. The order defines jurisdiction for the CPUC over local distribution and retail power customers. The FERC will have jurisdiction over the transmission facilities as defined in the order and over the transmission aspects of retail direct access.
GAS UTILITY OPERATIONS
PG&E owns and operates an integrated gas transmission, storage, and distribution system in California. At December 31, 1996, PG&E's system, including the PG&E Expansion (Line 401), consisted of approximately 5,700 miles of transmission pipelines, three gas storage facilities, and approximately 36,200 miles of gas distribution lines.
GAS OPERATIONS
PG&E's peak day send-out of gas on its integrated system in California during the year ended December 31, 1996 was 3,407 million cubic feet (MMcf). The total volume of gas throughput during 1996 was approximately 826,000 MMcf, of which 264,000 MMcf was sold to direct end-use or resale customers, 134,000 MMcf was used by PG&E primarily for its fossil-fueled electric generating plants, and 428,000 MMcf was transported as customer owned gas.
The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities as a result of a CPUC order. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years.
The 1996 Report updates PG&E's annual gas requirements forecast (excluding bypass volumes) for the years 1996 through 2010, forecasting growth in gas thoughput served by PG&E of 2% per year. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing PG&E's system entirely. The 1996 Report forecasts a total bypass volume of 133,600 MMcf for 1996.
GAS OPERATING STATISTICS
The following table shows PG&E's operating statistics (excluding subsidiaries except where indicated) for gas, including the classification of sales and revenues by type of service.
- -------- (1) Includes use by business units other than the Gas Supply business unit, principally as fuel for fossil-fueled generating plants. (2) In August 1991, PG&E implemented its customer identified gas (CIG) program. Sales included approximately 105,000 MMcf and 130,000 MMcf in 1993 and 1992, respectively, of gas procured by PG&E for CIG customers at prices negotiated directly between those customers and suppliers. The CIG Program was terminated on October 31, 1993 upon full implementation of the CPUC's capacity brokering program. (3) Does not include on-system transportation volumes transported on the PG&E Expansion of 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and 7,205 MMcf for 1996, 1995, 1994, and 1993, respectively. (4) Includes gas transportation revenues from PGT.
- -------- (1) Over 100% indicates colder than normal.
NATURAL GAS SUPPLIES
The objective of PG&E's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs, and fosters competition among suppliers.
Under current CPUC regulations, PG&E purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 1996, approximately 65% of PG&E's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by Canadian pipeline companies and PGT; approximately 7% was purchased from various California producers; and approximately 28% was purchased from other states (substantially all U.S. Southwest sources and transported by El Paso or Transwestern). The following table shows the volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by PG&E from these sources during each of the last five years.
- -------- (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. The average prices for California gas include only commodity gas prices delivered to PG&E's gas system.
GAS REGULATORY FRAMEWORK
The current regulatory framework for natural gas service in California (i) segments customers into core and noncore classes; (ii) unbundles utilities' gas transportation and procurement services; (iii) allows customers to purchase gas directly from producers, aggregators, or marketers, and to separately purchase gas transportation from their utilities; and (iv) places the utilities at risk for collecting a portion of the transportation revenues associated with their noncore markets.
Under this regulatory framework, noncore customers have the option of buying gas directly from the supplier of their choice and purchasing from PG&E transmission and distribution services only. Certain customers can also use alternative transportation services provided by competing pipeline companies. However, core customers continue to have more limited opportunities in choosing their gas suppliers, with substantially all core customers receiving bundled services from PG&E.
In an effort to promote competition and increase options for all customers, as well as to position itself in the competitive marketplace, PG&E has submitted to the CPUC for its approval a Gas Accord, which would restructure PG&E's gas services and its role in the gas market. As discussed above (see "Competition and the Changing Regulatory Environment--Gas Industry"), the Gas Accord consists of three broad initiatives: (1) unbundling of PG&E's gas transmission and storage services from its distribution services; (2) reduction of PG&E's role in procuring gas supplies for core customers in order to increase opportunities for such customers to purchase gas from their supplier of choice; and (3) resolution of major outstanding regulatory issues. Also as part of the Gas Accord, PG&E has proposed that traditional reasonableness reviews of its core gas procurement costs be replaced with a CPIM, under which PG&E would be able to recover its gas commodity and interstate transportation costs and receive benefits or be penalized depending on whether its actual core procurement costs were within, below, or above a "tolerance band" constructed around market benchmarks.
The Gas Accord must be approved by the CPUC before it can be implemented.
TRANSPORTATION COMMITMENTS
PG&E has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that PG&E will pay each year may change due to changes in tariff rates. The total demand and transportation charges paid by PG&E under these agreement (excluding agreements with PGT) was approximately $212 million in 1996.
As a result of regulatory changes, PG&E no longer procures gas for its noncore customers, resulting in a decrease in PG&E's need for firm transportation capacity for its gas purchases. PG&E continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers).
PG&E is continuing its efforts to broker or assign any remaining unused capacity, including unused capacity held for its core and core subscription customers. Due to relatively low demand for Southwest pipeline capacity, PG&E cannot predict the volume or price of the capacity on El Paso and Transwestern that will be brokered or assigned.
In general, demand charges incurred by PG&E for pipeline capacity are eligible for rate recovery, subject to a reasonableness review. The demand charges include the cost of capacity that was formerly used to serve noncore customers but which at present cannot be brokered or which is brokered at a discount. However, certain groups, including the ORA and intervenors, have challenged the recovery of these unrecovered demand charges in the proceeding relating to ITCS recovery (see "El Paso and PGT Capacity" below). In addition, the CPUC has issued an unfavorable decision addressing recovery of Transwestern charges (see "Transwestern Capacity" below).
EL PASO AND PGT CAPACITY
PG&E's firm transportation agreement with PGT for 1,066 million cubic feet per day (MMcf/d) runs through October 31, 2005. PG&E's firm transportation agreement with El Paso for 1,140 MMcf/d runs through December 31, 1997. The firm transportation reservation charges associated with PG&E's firm capacity on PGT and El Paso are approximately $57 million and $163 million per year, respectively.
Pursuant to FERC rules on capacity relinquishment and release and the CPUC's capacity brokering program, PG&E currently retains approximately 600 MMcf/d on each of the PGT and El Paso systems to support its core and core subscription customers. PG&E made capacity not needed to support such customers available
for release and brokering to other potential shippers beginning in 1993. PG&E has assigned substantially all of its unused capacity on PGT. Due to lower demand for Southwest pipeline capacity, PG&E cannot predict the volume or price of the capacity on El Paso that will be brokered or assigned. To the extent PG&E is unable to broker its firm interstate capacity above core and core subscription reservations at the full as-billed rate, PG&E has been authorized to accumulate unrecovered demand charges for El Paso and PGT in the ITCS account pending CPUC reasonableness review of those amounts in the ITCS proceeding.
As noted above, in the ITCS proceeding, certain intervenors have challenged PG&E's recovery of amounts in the ITCS account, and suggested disallowances and/or a reallocation among customers of between $40 and $101 million. Pending a final decision in the ITCS proceeding, the CPUC has approved collection in rates (subject to refund) of approximately 50% of the demand charges for unbrokered or discounted El Paso and PGT capacity formerly used to serve PG&E's noncore customers.
In the meantime, PG&E has proposed a resolution of this matter as part of the Gas Accord. Under the Gas Accord, PG&E would forgo recovery of 100% and 50% of the ITCS amounts allocated to its core and noncore customers, respectively.
TRANSWESTERN CAPACITY
In April 1992, PG&E executed firm transportation agreements with Transwestern to transport approximately 200 MMcf/d of San Juan basin gas supplies into PG&E's southern gas system, of which approximately 150 MMcf/d is to be used to meet PG&E's core gas sales demands and approximately 50 MMcf/d is for use by PG&E's electric department. The agreements with Transwestern expire in 2007. The demand charges associated with the entire Transwestern capacity are currently approximately $29 million per year.
Currently, PG&E is not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account. PG&E is authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings.
In December 1995, the CPUC issued a decision on the reasonableness of PG&E's 1992 gas operations, which concluded that it was unreasonable for PG&E to commit to transportation capacity with Transwestern. The decision orders that costs for the capacity in subsequent years of the contract, which expires in 2007, be disallowed each year unless PG&E can demonstrate that the benefits of the commitment outweight the costs in that year.
PG&E has also addressed the Transwestern issue in its Gas Accord proposal. The Gas Accord provides that PG&E would not recover costs through 1997 associated with Transwestern capacity originally subscribed to in order to serve core customers and would have limited recovery during the period 1998 through 2002.
PG&E has recorded reserves relating to its gas capacity commitments and the issues addressed by the Gas Accord. More information concerning the financial impact of these matters is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 1996 Annual Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 31 of the 1996 Annual Report to Shareholders.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through PG&E's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were incurred reasonably. Under the current regulatory framework, annual reasonableness proceedings are conducted by the CPUC on a historic calendar year basis.
1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on PG&E's Canadian gas procurement activities during 1988 through 1990. The CPUC found that PG&E could have saved its customers money if it had bargained more
aggressively with its existing Canadian suppliers or bought less expensive gas from other Canadian sources. The decision ordered a disallowance of $90 million of gas costs, plus accrued interest estimated at approximately $25 million through December 31, 1993.
In December 1994, PG&E filed a complaint against the CPUC in the U.S. District Court for the Northern District of California challenging this decision by the CPUC. The complaint alleges that the CPUC disallowance order purports to regulate the foreign and interstate purchase and transportation of natural gas, matters within the exclusive jurisdiction of United States and Canadian regulatory authorities. Accordingly, the complaint alleges, such order is preempted by federal law and violates PG&E's rights under the United States Constitution. The complaint seeks injunctive and declaratory relief.
PG&E's lawsuit is still pending in federal court. However, as part of the Gas Accord, PG&E would agree to forgo recovery of the $90 million disallowance ordered in the 1988-1990 reasonableness proceeding, irrespective of the outcome of the lawsuit challenging the disallowance.
GAS SETTLEMENT AGREEMENT
In December 1996, the CPUC approved a settlement agreement resolving various issues related to PG&E's gas procurement practices and supply operations for periods from 1988 through May 1994. Pursuant to the settlement agreement, PG&E will return approximately $75 million (including interest) to ratepayers.
PGT/PG&E PIPELINE EXPANSION
In November 1993, PGT and PG&E placed in service the Pipeline Expansion, an expansion of their interconnected natural gas transmission systems from the Canadian border into California. The 840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern and Southern California.
CPUC RATEMAKING
The conditions of the CPUC's approval of the construction of the PG&E Expansion place PG&E at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross-over" ban under which volumes delivered from the incremental PGT portion (PGT Expansion) of the Pipeline Expansion must be transported at an incremental PG&E Expansion rate. The costs of PG&E Expansion operations are recovered only from PG&E Expansion customers, through rates established in separate PG&E Expansion rate proceedings.
To date, shippers have executed long-term firm transportation contracts for approximately 40% of capacity on the PG&E Expansion. However, one of those shippers, which holds a substantial portion of the capacity held under long- term firm contracts, has an option to buy out its contract. The option is exercisable on or before May 1, 1997. PG&E will continue to market available capacity on the PG&E Expansion on both firm and as-available bases. Revenues are being collected on the basis of an interim revenue requirement, pending a final decision in the Pipeline Expansion Project Reasonableness case (PEPR).
In 1994, PG&E filed its application in the PEPR requesting that the CPUC find reasonable the full capital costs of the PG&E Expansion (estimated to be $810 million). In that proceeding, the ORA recommended a minimum of $100 million in capital costs be disallowed, while two intervenors jointly recommended a $237 million disallowance or reallocation of costs among customers. In addition, in 1996, a CPUC ALJ ordered consolidation of the market impact phase of the PEPR and the ITCS proceeding described above. An ALJ also ordered reopening of the 1993 PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding the decision to construct the PG&E Expansion. Were the CPUC to reverse its previous decision, which found that PG&E was reasonable in constructing the PG&E Expansion, the ultimate outcome could have an adverse impact on PG&E's ability to recover its cost for unused capacity on other pipelines as well as on its own intrastate facilities. Decisions in these proceedings are expected in 1997, if the matters are not otherwise resolved
as part of the Gas Accord. Under the Gas Accord, PG&E would agree to set rates for the PG&E Expansion based on total capital costs of $736 million.
The CPUC's decision in the 1997 Cost of Capital proceeding authorized a 1997 return on equity for PG&E Expansion operations of 11.6%, resulting in an overall rate of return of 8.99%. Authorized long-term debt levels for the PG&E Expansion will be reduced from their current 67% to 64% for 1997.
FERC RATEMAKING
In September 1996, the FERC approved a settlement of PGT's 1994 rate case. The major issue in this proceeding was whether PGT's mainline transportation rates should be equalized through the use of rolled-in cost allocations, or whether they should continue to reflect the use of incremental cost allocation to determine the rates to be paid by firm shippers. (Under incremental rates, a pipeline would generally charge higher rates to shippers contracting for capacity on newly-added expansion facilities as compared to shippers using depreciated pre-expansion facilities.) The settlement provides for rolled-in rates effective November 1996. To mitigate the impact of the higher rolled-in rates on shippers who were paying lower rates under contracts executed prior to construction of the PGT Expansion, most of the firm shippers who took service prior to such time receive a reduction from the rolled-in rate for a six-year period, while PGT Expansion firm shippers pay a surcharge in addition to the rolled-in rates to offset the effect of the mitigation. The settlement also provides for rates based on a return on equity of 12.2%. Several parties are seeking rehearing of the FERC order approving the settlement, but PGT currently expects the settlement to be upheld.
DIVERSIFIED OPERATIONS
In 1996, diversified operations primarily consisted of Enterprises. Enterprises participates in multiple domestic and international energy businesses. Enterprises, through its wholly owned subsidiary, PG&E Generating Company, has made the majority of its investments in nonregulated energy projects through U.S. Generating Company (USGen), in partnership with Bechtel Enterprises, Inc. (Bechtel). USGen, a California partnership, manages the development, construction, and operation of non-utility electric generation facilities that compete in the United States power generation market. Enterprises' average overall ownership in all the projects in which USGen participates is approximately 42 percent.
As of December 31, 1996, USGen's partners had ownership interests in 17 operating plants. The total generating capacity of these 17 plants is 3,375 MW, of which Enterprises' share is 1,424 MW. The projects were largely financed with a combination of equity or equity commitments from the project sponsors and non-recourse debt. USGen, through its affiliate, U.S. Operating Services Company (USOSC), provides contract operations and maintenance services to many of these facilities. USGen, through its affiliate, USGen Power Services, L.P., is also an active power marketer. USGen also manages approximately 5.6 million tons per year of coal deliveries to its plants and approximately 875 MMcf/d of Canadian and U.S. natural gas supplies for deliveries to its plants and to local gas distribution companies in the Northeast.
Enterprises' entry into the international market was also made in partnership with Bechtel. Enterprises and Bechtel formed International Generating Company, Ltd. (InterGen), which develops, owns, and operates international electric generation projects. However, in November 1996, Enterprises and Bechtel reached an agreement for Bechtel to acquire Enterprises' interest in InterGen. The Company expects to complete the sale in the first quarter of 1997 and to realize an after-tax gain. Enterprises has refined its international strategy to focus on select countries and to concentrate on end-use energy customers.
In 1995, Enterprises formed Vantus, a retail energy services provider, to assist customers in locating the most cost-effective electric and gas products and services. Vantus' energy services include power marketing for industrial and large commercial businesses nationwide. In 1996, Vantus opened new offices in the western United States to establish a presence and market its services in emerging energy markets.
PG&E ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS
The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection and the possible future impact of environmental compliance. This information reflects PG&E's current estimates which are periodically evaluated and revised. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of PG&E's responsibility, and the availability of recoveries or contributions from third parties. Future estimates and actual results may differ materially from those indicated below.
PG&E and its affiliates are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. PG&E has undertaken major compliance efforts with specific emphasis on its purchase, use, and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of PG&E's bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations have generally been recovered in rates.
ENVIRONMENTAL PROTECTION MEASURES
PG&E's estimated expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. PG&E's capital expenditures for environmental protection are currently estimated to be approximately $36 million, $50 million, and $72 million for 1997, 1998 and 1999, respectively, and are included in PG&E's three-year estimate of capital requirements shown above in "General--Capital Requirements and Financing Programs." Expenditures during these years will be primarily for oxides of nitrogen (NOx) emission reduction projects at PG&E's fossil-fueled generating plants and natural gas compressor stations as described below, which currently are expected to decline in the later years as the NOx reduction projects are completed.
Air Quality
PG&E's existing thermal electric generating plants are subject to numerous air pollution control laws, including the California Clean Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air Act, the three local air districts in which PG&E operates fossil-fueled generating plants adopted final rules that require a reduction in NOx emissions from the power plants of approximately 90% by 2004 (with numerous interim compliance deadlines). The first major retrofits began in 1995. Certain retrofits will not be required if the smaller generating units are operated for emergency purposes only after 2000. PG&E currently estimates that compliance with these NOx rules could require capital expenditures of up to $360 million over 10 years. This estimate assumes that most of the 170 MW and smaller boilers will be retired before the retrofits are required. Ongoing business and engineering studies could change this estimate.
Other air districts have adopted NOx rules for PG&E's natural gas compressor stations in California, and these rules continue to be modified. Eventually the rules are likely to require NOx reductions of up to 80% for many of PG&E's natural gas compressor stations. PG&E currently estimates that the total cost of complying with these rules will be up to $58 million over five years.
In PG&E's 1996 GRC, the CPUC included $11.5 million in 1996 rate base for the estimated $60 million cost of gas and electric NOx retrofit projects to be installed in 1996. In the future, PG&E's electric NOx costs may be recoverable as CTCs or through PBR, market pricing, or other means established as part of electric industry restructuring. Under AB 1890, NOx costs would be eligible for recovery as CTCs but only to the extent that those costs are found by the CPUC to be both reasonable and necessary to maintain the unit in operation
through 2001. With respect to gas NOx costs, under the proposed Gas Accord $42 million would be included in rates for gas NOx retrofit projects through 2002.
Water Quality
PG&E's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. PG&E's fossil-fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast Regional Water Quality Control Board (Central Coast Board). The Central Coast Board did not make a final decision on the report and requested that PG&E continue its thermal effects monitoring program. In 1995, the Central Coast Board requested that PG&E prepare an updated comprehensive assessment of Diablo Canyon's thermal effects and approved a reduced environmental monitoring program. The new comprehensive assessment is scheduled for completion in the fourth quarter of 1997. In the unlikely event that the Central Coast Board finds that Diablo Canyon's existing thermal limits are not protective of beneficial uses of the marine waters and that major modifications are required (e.g., cooling towers), significant additional construction expenses could be required.
Pursuant to the federal Clean Water Act, PG&E is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. PG&E has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. PG&E is currently preparing a new study for Diablo Canyon. The study is scheduled to be submitted to the Central Coast Board for review in 1999. In the event that the Central Coast Board finds that Diablo Canyon's cooling water intake structure does not meet the BTA requirements, significant additional expenses for construction or mitigation could be required. In addition, the promulgation or modification of federal, state, and regional water quality control plans may impose increasingly stringent cooling water discharge requirements on PG&E power plants in the future. Costs to comply with renewed permit conditions required to meet any more stringent requirements that might be imposed cannot be estimated at the present time.
Several fish species listed or proposed for listing as endangered species may be found in the waters near certain of PG&E's power plants. There are severe restrictions on the "taking" (e.g., harassing, wounding, or killing) of such species. Therefore, significant modifications could be required to plant operations (e.g., cooling towers) if a plant intake structure or thermal discharge is found to "take" an endangered species.
HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
PG&E assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. At present, these compliance and remediation costs (other than certain costs directly attributable to generation facilities) would generally be recovered through the GRC process or through a separate mechanism established by the CPUC in 1994 for recovery of certain hazardous waste remediation costs. At present, environmental remediation costs attributable to the decommissioning of generation facilities are included in rates as part of decommissioning costs. Under electric industry restructuring, remediation costs for generation facilities can be included as eligible CTCs that may be recovered during the transition period. It is not clear at this time what specific ratemaking mechanisms may be available for recovery of hazardous waste compliance and remediation costs after the transition period.
PG&E has a comprehensive program to comply with the many hazardous waste storage, handling, and disposal requirements promulgated by the United States Environmental Protection Agency (EPA) under the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with California's hazardous waste laws and other environmental requirements.
One part of this program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plants produced lampblack and tar residues, byproducts of a process that PG&E, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), PG&E's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. PG&E has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which operated in PG&E's service territory. PG&E owns all or a portion of 29 of these manufactured gas plant sites. PG&E has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which PG&E owns. PG&E currently estimates that this program may result in expenditures of approximately $8 million to $10 million over the period 1997 through 1998. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if PG&E is found to be responsible for cleanup at sites it does not currently own.
Manufactured gas plant sites at which PG&E has been designated as a potentially responsible party (PRP) under the California Hazardous Substance Account Act (California Superfund) include the Martin Service Center site and Midway/Bayshore sites in Daly City, California, the San Rafael site, and the Sacramento site.
In addition to the manufactured gas plant sites, PG&E may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the environment because of an actual or potential release of hazardous substances. PG&E has been designated as a PRP under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales site is a former used oil recycling facility at which PG&E is one of nine PRPs named in an EPA order requiring groundwater remediation at the site. PG&E has also entered into an Administrative Order with the EPA to address soil contamination at the site. PG&E has accrued a $4.5 million liability as of December 31, 1996, for the Purity Oil Sales site. With respect to the Casmalia site near Santa Maria, California, PG&E and several other generators of waste sent to the site have entered into an agreement with the EPA that requires these generators to perform certain site investigation and mitigation measures, and provides a release from liability for certain other site cleanup obligations. Court approval of the agreement is being sought. PG&E has accrued a $3.2 million liability as of December 31, 1996, for the Casmalia site. Although PG&E has not been formally designated a PRP with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed PG&E and other parties to initiate measures with respect to the study and remediation of that site. PG&E has accrued a liability of $12.5 million as of December 31, 1996, for the Geothermal Incorporated site.
In addition to the sites discussed above, PG&E has also been identified as a PRP at certain disposal sites under the California Superfund. These sites include the Emeryville Service Center site in Emeryville, California, and the GBF Landfill at Pittsburg, California. PG&E has also been sued for reimbursement of cleanup costs incurred by the State of California at PG&E's former Jibboom Street Station B power plant in Sacramento, California. In addition, PG&E has been named as a defendant in several civil lawsuits in which plaintiffs allege that PG&E is responsible for performing or paying for remedial action at sites PG&E no longer owns or never owned.
The cost of hazardous substance remediation ultimately undertaken by the Company is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Company had an accrued liability at December 31, 1996, of $170 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $400 million if, among other things, other PRPs are not
financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to the Company among a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.
POTENTIAL RECOVERY OF HAZARDOUS WASTE COMPLIANCE AND REMEDIATION COSTS
In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs. That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. However, under the proposed mechanism, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. Under the mechanism, 70% of the ratepayer portion of PG&E's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. PG&E can seek to recover hazardous substance cleanup costs under the new mechanism in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, PG&E has proposed that any hazardous waste cleanup costs related to electric generation facilities be removed from this mechanism and included in CTCs. In addition, PG&E has proposed that this mechanism no longer be used for electric generation-related cleanup costs after January 1, 1998.
PG&E expects to seek recovery of prudently incurred hazardous substance remediation costs through ratemaking procedures approved by the CPUC. The Company has recorded a regulatory asset at December 31, 1996, of $146 million for recovery of these costs in future rates. Additionally, PG&E will seek recovery of costs from insurance carriers and from other third parties.
In 1992, PG&E filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. PG&E had previously notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In the main, PG&E's carriers neither admitted nor denied coverage, but requested additional information from PG&E. Although PG&E has received some amounts in settlements with certain of its insurers, the ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time.
COMPRESSOR STATION LITIGATION
In 1996, litigation brought against PG&E relating to alleged chromium contamination near PG&E's Hinkley Compressor Station was settled for the aggregate sum of $333 million. The Hinkley Compressor Station is located along PG&E's gas transmission system in San Bernardino County, California. The plaintiffs had contended that between 1951 and 1966, PG&E discharged chromium- contaminated wastewater into unlined ponds, which led to chromium percolating into the groundwater of surrounding property.
Several other cases have been brought against PG&E seeking damages from alleged chromium contamination at PG&E's Hinkley, Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings--Compressor Station Chromium Litigation" for a description of the pending litigation.
ELECTRIC AND MAGNETIC FIELDS
In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks which may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled which raises the question of whether adverse health impacts might exist.
In November 1993, the CPUC adopted an interim EMF policy for California energy utilities which, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services.
As part of its effort to educate the public about EMF, PG&E provides interested customers with information regarding the EMF exposure issue. PG&E also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
PG&E and other utilities are involved in litigation concerning EMF. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. PG&E is named as a defendant in one pending civil appeal in which plaintiffs allege personal injury resulting from exposure to EMF.
In the event that the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility- related EMF exposures can be isolated from other exposures, PG&E may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant depending on the particular mitigation measures undertaken, especially if relocation of existing power lines is ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding which approved approximately $36 million in funding for PG&E's LEV program for the six-year period beginning in 1996. The CPUC's decision on electric industry restructuring finds that the costs of utility LEV programs should continue to be collected by the utility for the duration of the six-year period.
FORMATION OF PG&E CORPORATION
As previously noted, effective January 1, 1997, PG&E Corporation became the parent holding company of PG&E. PG&E's ownership interest in PGT and Enterprises was transferred to PG&E Corporation. The following financial information summarizes certain pro forma financial effects of the restructuring of PG&E. The restructuring resulted in PG&E becoming a separate subsidiary of PG&E Corporation with the present holders of PG&E common stock becoming holders of PG&E Corporation common stock. The pro forma balance sheet is as of December 31, 1996, and the pro forma income statement is for the twelve months ended December 31, 1996, as if the restructuring occurred December 31, 1996, and January 1, 1996, respectively. The restructuring was accounted for as an as-if pooling of interests.
- -------- (1) Reflects transfer of PGT and Enterprises from PG&E to PG&E Corporation in connection with restructuring. (2) Reflects dividends associated with PG&E Preferred Stock as a charge against retained earnings for PG&E and as a charge against net income for PG&E Corporation.
ITEM 2.
ITEM 2. PROPERTIES.
Information concerning PG&E's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of PG&E are subject to the lien of an indenture which provides security to the holders of PG&E's First and Refunding Mortgage Bonds.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
See Item 1 -- Business, for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, PG&E is subject to routine litigation incidental to its business.
ANTITRUST LITIGATION
On December 3, 1993, the County of Stanislaus and Mary Grogan, a residential customer of PG&E, filed a complaint in the U.S. District Court, Eastern District of California, against PG&E and PGT, on behalf of themselves and purportedly as a class action on behalf of all natural gas customers of PG&E during the period of February 1988 through October 1993. The complaint alleged that the purchase of natural gas in Canada was accomplished in violation of various antitrust laws and sought damages of as much as $950 million, before trebling. In August 1994, the District Court dismissed plaintiffs' antitrust claims, and in September 1994, the plaintiffs filed an amended complaint which added Alberta and Southern Gas Co. Ltd., PG&E's gas purchasing subsidiary, as a defendant. The amended complaint reiterated price fixing claims and also alleged that the defendants, through anticompetitive practices, foreclosed access over the PGT pipeline to alternative sources of gas in Canada.
On December 18, 1995, the District Court dismissed the plaintiffs' amended complaint with prejudice. In dismissing the lawsuit, the District Court determined that plaintiffs were barred from making price fixing allegations because gas rates had been reviewed by various federal authorities and the CPUC. The District Court also found that plaintiffs were barred from making foreclosure of access claims because the volume of imports of gas had been reviewed by federal authorities, and the CPUC had actively overseen the allocation of pipeline capacity. Plaintiffs have filed an appeal with the Court of Appeals.
The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position.
COUNTIES FRANCHISE FEES LITIGATION
On March 31, 1994, the Counties of Alameda and Santa Clara filed a complaint in Santa Clara County Superior Court against PG&E on behalf of themselves and purportedly as a class action on behalf of 47 counties with which PG&E has gas or electric franchise contracts. Franchise contracts require PG&E to pay fees on an annual basis to cities and counties for the right to use or occupy public streets and roads. The complaint alleges that, since at least 1987, PG&E has intentionally underpaid its franchise fees to the counties in an unspecified amount.
The complaint cites two reasons for the alleged underpayment of fees. Based on their interpretation of certain legislation, the plaintiffs allege that PG&E has been using the wrong methodology to compute the franchise fees payable to the plaintiff counties. The plaintiffs also allege that fees have been underpaid due to incorrect calculations under the methodology used by PG&E.
The parties agreed to stipulate to this case proceeding as a class action lawsuit regarding the issue of the correct payment methodology to be applied in calculating the franchise fees due to the plaintiffs. On March 14, 1995, the Superior Court granted PG&E's motion for summary judgment in the class action lawsuit. The plaintiffs appealed that ruling and on January 14, 1997, the Court of Appeal upheld the summary judgment
in PG&E's favor. The plaintiffs did not seek review of the Court of Appeal's ruling, and accordingly the summary judgment has become final, resolving the issue regarding the payment methodology.
Consistent with the agreement between the parties noted above, the plaintiffs refiled a separate action covering just the issue of whether PG&E properly computed its franchise payments, assuming that PG&E has been using the correct methodology. Plaintiffs may now reactivate this case, which had been stayed pending resolution of the challenge to the payment formula. Plaintiffs have not indicated damages to be sought in that separate action, but they are not anticipated to be material.
CITIES FRANCHISE FEES LITIGATION
On May 13, 1994, the City of Santa Cruz filed a complaint in Santa Cruz County Superior Court against PG&E on behalf of itself and purportedly as a class action on behalf of 107 cities with which PG&E has certain electric franchise contracts. The complaint alleges that, since at least 1987, PG&E has intentionally underpaid its franchise fees to the cities in an unspecified amount.
The complaint alleges that PG&E has asked for and accepted electric franchises from the cities included in the purported class, which provide for lower franchise payments than required by franchises granted by other cities in PG&E's service territory. Plaintiff asserts that this was done in an unlawfully discriminatory manner based solely on location. The plaintiff also alleges that the transfer of these franchises to PG&E by its predecessor companies was not approved by the CPUC as required, and, therefore, all such franchise contracts are void.
The Court has certified the class of 107 cities in this action, and approved the City of Santa Cruz as the class representative. On September 1, 1995, the Court denied PG&E's motions for summary judgment and class decertification in this case. The Court did bifurcate the issues in the case for trial such that the issue concerning whether PG&E engaged in unlawful discrimination in accepting certain franchise contracts with differing payment formulas would be tried first, to be followed by the issue relating to the validity of PG&E's current franchise contracts with the plaintiff cities.
On January 22, 1996, the Court granted PG&E's motion for summary judgment against five class member cities with respect to the cities' claims that the different franchise payment formulas in the 1937 Franchise Act constitute unlawful discrimination. On March 19, 1996, the Court granted PG&E's motion for judgment against the 31 charter cities who are members of the plaintiff class, including the class representative (the City of Santa Cruz). The Court determined that those cities had no basis for their claims against PG&E since their franchise fee structure was of their own choosing as a matter of "home rule" under the California Constitution.
At present, 71 general law cities remain as members of the plaintiff class. Given the Court's prior rulings, the only remaining triable issue relates to the validity of PG&E's current franchise contracts with the remaining plaintiffs. Trial has been postponed indefinitely pending plaintiffs' appeal of the rulings against them.
Should the cities prevail on the issue of franchise fee calculation methodology, PG&E's annual system-wide city electric franchise fees could increase by approximately $14 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $145 million (exclusive of interest). If the Court's rulings effectively eliminating certain cities' claims become final, PG&E's potential damages and increased fees would be significantly reduced. In that event, should the remaining plaintiffs prevail, PG&E's annual systemwide city electric franchise fees could increase by approximately $4 million and damages for the remaining plaintiffs for alleged underpayments could be as much as $39 million (exclusive of interest). The ultimate damages and/or increase in fees in any case might vary depending on the Court's interpretation of the plaintiffs' claims.
The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations.
NORCEN LITIGATION
In March 1994, Norcen Energy Resources Limited (Norcen Energy) and Norcen Marketing Incorporated (Norcen Marketing) filed a complaint in the U.S. District Court, Northern District of California, against PG&E and PGT. Norcen Marketing has a 30-year gas transportation contract with PGT, which is guaranteed by Norcen Energy. The complaint alleged that PGT and PG&E wrongfully induced Norcen Energy and Norcen Marketing to enter into the 30- year contract by concealing legal action taken by PG&E before the CPUC (requesting clarification that gas shipped on the PGT portion of the Pipeline Expansion should pay PG&E's incremental Expansion rates for in-state service) two days before Norcen Marketing's contract became binding. The complaint also alleged breach of representations to plaintiffs that PG&E would not "unreasonably" build its Pipeline Expansion with less than "sufficient" firm subscription and a breach of an agreement between PGT and a Norcen predecessor relating to the installation of additional capacity. In addition to state law contract claims, the complaint also alleged a series of federal and state antitrust claims related to the construction of the Pipeline Expansion and PG&E's alleged refusals to allow access to the original PGT and California transmission systems.
In September 1994, the District Court granted PGT's and PG&E's motion to dismiss all federal antitrust claims in the complaint originally filed in this case, and dismissed the remaining state law claims for lack of jurisdiction.
In October 1994, plaintiffs filed an amended complaint. The amended complaint reasserted part of the original complaint's antitrust claims, asserted new antitrust claims based on the same facts, and specifically alleged diversity jurisdiction for the state law contract claims. In July 1995, the District Court issued an order on PG&E's motion to dismiss the amended complaint. The order dismisses all of plaintiffs' federal and state antitrust claims, but does not dismiss various state law contract claims, including claims based on fraudulent inducement and breach of contract. Plaintiffs have the right to appeal the dismissal of the antitrust claims to the Court of Appeals. Plaintiffs still seek rescission of their gas transportation contracts and compensatory and punitive damages in connection with their remaining state law claims. The Company believes plaintiffs in this action might seek contract damages of approximately $100 million in this matter.
The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations.
CALIFORNIA ATTORNEY GENERAL INVESTIGATION
In February 1995, the California Attorney General (AG) initiated an investigation to determine whether PG&E and its consultant, Tenera, Inc. (Tenera), violated the Federal Clean Water Act and the California Water Code in connection with a 1988 study of the cooling water intake system at Diablo Canyon (1988 Study). The United States Department of Justice (DOJ) has since joined the AG's investigation. PG&E has been in discussions with the AG and the DOJ concerning the disposition of this matter and related litigation with the League For Coastal Protection and John W. Carter (collectively, the Diablo Canyon Environmental Litigation). See "Diablo Canyon Environmental Litigation" below. In those discussions, the AG and DOJ have indicated their belief that PG&E violated the Federal Clean Water Act, the California Water Code, and other provisions of California law in connection with the 1988 Study. The AG and DOJ have proposed a resolution of these matters that involves the payment by PG&E of civil penalties and mitigation project costs.
The Company believes that the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations.
DIABLO CANYON ENVIRONMENTAL LITIGATION
On October 13, 1995, the League for Coastal Protection (Coastal League) filed a lawsuit in San Francisco County Superior Court against PG&E and its consultant, Tenera, alleging violations of the California Business and Professions Code in connection with the 1988 Study. The 1988 Study is also the subject of an investigation by the AG and DOJ, as described above. The Coastal League alleges that PG&E and its consultant violated the law by making misrepresentations in connection with the 1988 Study. The Coastal League seeks an unspecified amount of damages related to restitution or disgorgement of improper or excessive profits, punitive damages, injunctive relief, and attorneys' fees.
On April 16, 1996, the Coastal League filed another lawsuit in the United States District Court, Northern District of California, against PG&E and Tenera, alleging violations of the federal Clean Water Act in connection with the 1988 Study. The Coastal League alleges that PG&E and Tenera withheld data from the 1988 Study and submitted misleading information to the state and federal agencies. The Coastal League seeks a judgment that PG&E has violated its discharge permit for Diablo Canyon, revocation of the permit, an order requiring restoration of the marine environment, an unspecified amount of civil penalties, and recovery of its litigation and attorneys' fees.
Also on April 16, 1996, PG&E received a copy of a complaint filed in a third case involving the 1988 Study. In this case, John W. Carter (Carter) alleges on behalf of himself and the United States and the State of California that PG&E, Tenera, and certain of their employees violated the federal and state False Claims Acts by filing an incomplete report in 1988 (i.e., the 1988 Study) and failing to correct it. The United States and the State of California have declined to prosecute this action, and it is maintained by Carter, who is represented by the same attorneys representing the Coastal League. The plaintiffs seek civil penalties, treble damages, a separate payment to Carter under the False Claims Acts, and attorneys' fees.
See "California Attorney General Investigation" above for a discussion of a possible resolution of this litigation.
The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations.
COMPRESSOR STATION CHROMIUM LITIGATION
PG&E has been named as a defendant in several civil actions filed in Southern California courts on behalf of more than 1,500 plaintiffs. These cases are Aguayo v. PG&E, filed March 15, 1995, in Los Angeles County Superior Court; Aguilar v. PG&E, filed October 4, 1996, in Los Angeles County Superior Court; Tate v. PG&E, filed October 29, 1996, in San Bernardino County Superior Court; and Adams v. Betz, filed September 21, 1994, in Los Angeles County Superior Court. In the Adams case, the claims remaining against PG&E arise from a cross-claim filed by Betz Chemical Company (Betz), the supplier of water treatment products containing chromium which are used at the gas compressor stations. All of these cases will be referred to collectively as the "Aguayo Litigation." Each of the complaints in the Aguayo Litigation allege personal injuries and seek compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of PG&E's gas compressor stations at Kettleman, Hinkley, and Topock, California. Betz also is named as a defendant in the Aguayo Litigation. The plaintiffs in the Aguayo Litigation include PG&E employees, former PG&E employees, relatives of PG&E employees or former employees, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations, alleging exposure to chromium at or near the compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim only loss of consortium or injury through the alleged exposure of their parents. PG&E is responding to the complaints and asserting affirmative defenses. PG&E will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged, and PG&E is attempting to gather information concerning the alleged type and duration of exposure, the nature of injuries alleged by individual plaintiffs, and the additional facts necessary to support its legal defenses, in order to better evaluate and defend this litigation.
The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
"Executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation are as follows*:
*All positions are with PG&E. **Mr. Shiffer will retire effective April 1, 1997.
All officers of PG&E Corporation and PG&E serve at the pleasure of the relevant Board of Directors. All executive officers of both companies have been employees of PG&E for the past five years. During that period, the executive officers had the following business experience as PG&E employees and/or officers, and/or PG&E Corporation officers*:
*All positions are with PG&E, unless otherwise noted.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Information responding to part of Item 5 is set forth on page 42 under the heading "Quarterly Consolidated Financial Data" in the 1996 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
PG&E has made no sales of unregistered equity securities in the last three years. PG&E Corporation has made the following sales of unregistered equity securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common stock. The shares were issued to nine former shareholders of Teco in connection with the acquisition by PG&E Corporation of Teco. PG&E Corporation owns all the outstanding shares of Teco as a result of the acquisition. The shares were issued in reliance upon the exemption from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the former shareholders of Teco represented that they were "accredited investors" as defined in Rule 501(a) under the Securities Act of 1933 and made other representations establishing the basis for the exemption. A legend as provided for by Rule 501 (d)(3) was placed on each of the stock certificates representing the shares of PG&E Corporation common stock received by the former shareholders of Teco.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
A summary of selected financial information for the Company for each of the last five fiscal years is set forth on page 8 under the heading "Selected Financial Data" in the 1996 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
A discussion of the Company's financial condition, changes in financial condition and results of operations is set forth on pages 9 through 19 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1996 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information responding to Item 8 is contained in the 1996 Annual Report to Shareholders on pages 20 through 43 under the headings "Statement of Consolidated Income," "Statement of Consolidated Cash Flows," "Consolidated Balance Sheet," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Statement of Consolidated Capitalization," "Statement of Consolidated Segment Information," "Notes to Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," and "Report of Independent Public Accountants," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information regarding executive officers of PG&E is included in a separate item captioned "Executive Officers of the Registrant" contained on pages 44 through 45 in Part I of this report. Other information responding to Item 10 is included on pages 2 through 5 under the heading "Election of Directors of PG&E Corporation and PG&E" and page 29 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11 is included on page 8 under the heading "Compensation of Directors" and on pages 19 through 27 under the heading "Executive Compensation" (excluding the sections thereunder entitled "Nominating and Compensation Committee Report on Compensation" and "Comparison of Five-Year Cumulative Total Shareholder Return") in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information responding to Item 12 is included on pages 10 and 28 under the headings "Security Ownership of Management" and "Principal Shareholders" in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13 is included on page 9 under the heading "Certain Relationships and Related Transactions" in the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, schedules of consolidated segment information, supplemental information, and report of independent public accountants contained in the 1996 Annual Report to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31, 1996, 1995, and 1994.
Statement of Consolidated Cash Flows for the Years Ended December 31, 1996, 1995, and 1994.
Consolidated Balance Sheet at December 31, 1996, and 1995.
Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities for the Years Ended December 31, 1996, 1995, and 1994.
Statement of Consolidated Capitalization at December 31, 1996, and 1995.
Schedule of Consolidated Segment Information for the Years Ended December 31, 1996, 1995, and 1994.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 53 of this Form 10-K.
3. Consolidated financial statement schedules:
II -- Consolidated Valuation and Qualifying Accounts for the Years Ended December 31, 1996, 1995 and 1994.
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.
- -------- * 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 as indicated and are hereby incorporated by reference. Exhibits will be furnished to security holders of the Company upon written request and payment of a fee of $0.30 per page, which fee covers only the Company's reasonable expenses in furnishing such exhibits. The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K during the quarter ended December 31, 1996 and through the date hereof:
1. October 16, 1996(1) Item 5. Other Events -- Performance Incentive Plan -- Year-to-Date Financial Results -- Common Stock Dividend Reduction
2. November 22, 1996(1) Item 5. Other Events -- Acquisitions and Dispositions
3.December 20, 1996(1) Item 5. Other Events -- Performance Incentive Plan -- 1997 Target
4. January 2, 1997(1)(2) Item 5. Other Events -- Holding Company Formation
5. January 7, 1997(1)(2) Item 5. Other Events -- Electric Industry Restructuring -- 1997 ECAC
6.January 16, 1997(1)(2) Item 5. Other Events --Performance Incentive Plan -- Year-to-Date Financial Results --1996 Consolidated Earnings (unaudited)
7.January 31, 1997(1)(2) Item 5. Other Events --Acquisition of Valero Energy Corporation --Acquisition of Teco Pipeline Company --Electric Industry Restructuring Cost Recovery Plan
8.February 19, 1997(1)(2) Item 7. Financial Statements, Pro Forma Financial Information and Exhibits --1996 Financial Statements
9.March 3, 1997(1)(2) Item 5. Other Events --Proposed Decision on Diablo Canyon Ratemaking Proposal - -------- (1)Filed under Commission File Number 1-2348 (PG&E) (2)Filed under Commission File Number 1-12609 (PG&E Corporation)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANTS HAVE DULY CAUSED THIS REPORT TO BE SIGNED ON THEIR BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND COUNTY OF SAN FRANCISCO, ON THE 4TH DAY OF MARCH, 1997.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant)
GARY P. ENCINAS GARY P. ENCINAS By _________________________________ By _________________________________ (Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in- Fact)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
GARY P. ENCINAS *By ________________________________ (Gary P. Encinas, Attorney-in- Fact)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors of PG&E Corporation:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in the PG&E Corporation Annual Report to Shareholders incorporated by reference in this Annual Report on Form 10-K, and have issued our report thereon dated February 10, 1997. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed in Part IV, Item 14. (a)(3) of this Annual Report on Form 10-K is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. The schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California February 10, 1997
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
- -------- (1) Deductions consist principally of write-offs. Reserve for deferred project costs is classified on the balance sheet in other deferred charges. Reserve for land costs is classified on the balance sheet in investment in nonregulated projects. (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. (3) Deductions consist principally of write-offs of expired leaseholds on reserved property. Deduction in 1995 results from sale of oil and gas properties.
INDEX TO EXHIBITS
- -------- * 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.
- -------- * 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.