ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in the business of supplying electric and natural gas service throughout most of Northern and Central California. (Unless the context otherwise requires, the Company or PG&E shall refer to Pacific Gas and Electric Company and its wholly owned and majority-owned subsidiaries.)
The Company's principal executive office is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000.
As of December 31, 1994, the Company had approximately $27.8 billion in assets. The Company generated approximately $10.4 billion in operating revenues for 1994. As of December 31, 1994, the Company had approximately 22,000 employees.
The Company's gas and electric utility operations, which include Diablo Canyon Nuclear Power Plant (Diablo Canyon) operations, represent the principal component of its business, contributing $10.2 billion in revenues in 1994 (98% of the Company's total revenues). The Company's utility operations contributed $2.20 of the Company's total 1994 earnings per share of $2.21. The Company's utility assets were $26.3 billion at December 31, 1994, representing 95% of the Company's total assets.
Diablo Canyon operations consist of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. In 1994, Diablo Canyon contributed $1.9 billion of revenues (18% of the Company's total revenues) and $1.04 in earnings per share (47% of the Company's total 1994 earnings per share). Diablo Canyon had assets of $6.0 billion at December 31, 1994 (22% of the Company's total assets).
The Company's utility service territory covers 94,000 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, 1994, the Company served approximately 4.4 million electric customers and 3.5 million gas customers.
The Company serves its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, the Diablo Canyon nuclear power plant with two units, 70 hydroelectric powerhouses with 111 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. The Company also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal and cogeneration. In addition, the Company is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling and transmitting power.
To ensure a diverse and competitive mix of natural gas supplies, the Company purchases gas from both Canadian and United States suppliers. In 1994, about 53% of the Company's gas supply came from fields in Canada, about 42% came from fields in other states (substantially all from the U.S. Southwest) and about 5% came from fields in California.
The Company's utility operations also include Pacific Gas Transmission Company (PGT), a wholly owned gas pipeline subsidiary of the Company. 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 Canadian-U.S. border to the Oregon-California border. PGT had assets of approximately $1.2 billion at December 31, 1994. PGT's revenues in 1994 were approximately $175 million, excluding revenues related to services provided to the Company.
Currently, the Company's utility operations, other than Diablo Canyon, are regulated primarily under the traditional cost-based approach to ratemaking. However, as discussed below (see "Competition and Industry Restructuring" and "Proposed Regulatory Reforms"), a number of proposals are being considered which would shift utility regulation from traditional cost-of-service based concepts to concepts based upon market competition and benchmarks.
Diablo Canyon operations are conducted under an alternative performance-based approach to ratemaking, as a result of the Diablo Canyon rate case settlement (Diablo Settlement), effective in 1988. Under this approach, revenues for the plant are based primarily on the amount of electricity generated, rather than on the costs associated with the plant's operations.
PG&E Enterprises (Enterprises), a wholly owned subsidiary of the Company, is the parent company for the nonregulated portion of the Company's business. Enterprises, through its subsidiaries and affiliates, engages in nonutility electric generation, power plant operations and services, gas and oil exploration and production and real estate development. Enterprises generated approximately $250 million in revenues in 1994 and contributed $.01 of the Company's total 1994 earnings per share of $2.21. Enterprises had assets of $1.5 billion at December 31, 1994.
COMPETITION AND INDUSTRY RESTRUCTURING
Under traditional utility regulatory schemes, utilities have been accorded the exclusive right to serve customers within designated areas in return for the commitment to provide service to all who request it. Regulation was designed in part to take the place of competition to ensure that utility services were provided at fair prices.
Recent changes in both the gas and electric industries have allowed competition to develop in the gas supply and electric production segments of the Company's business. A number of reforms at both the federal and state level have been proposed. These reforms are designed to restructure regulation in the energy supply industry and promote competition by providing electric and gas customers with purchasing options.
GAS INDUSTRY
The current regulatory framework for natural gas service was established in California in 1988. This framework segmented customers into core (all residential customers and smaller commercial customers that do not exceed certain volume limitations) and noncore (industrial and commercial customers that exceed certain volume limitations) classes, and unbundled utilities' gas transportation and procurement services which allowed noncore customers to purchase gas directly from producers, aggregators and marketers and separately negotiate transportation services. Similarly, in 1992 the Federal Energy Regulatory Commission (FERC) instituted regulatory changes which required interstate pipelines, including PGT, to unbundle sales services from transportation services and established programs providing for the reallocation of pipeline capacity.
As a result of these regulatory changes, the Company no longer provides combined procurement and transportation services to most of its noncore customers. Instead, many of these customers now procure their own gas supplies and then purchase transportation service from the Company. As a result, the Company has restructured its own gas operations to accommodate its decreased gas supply and transportation requirements. The Company has terminated its long-term Canadian gas purchase contracts and entered into new, more flexible arrangements for the purchase of the Company's reduced gas supply requirement and is continuing its efforts to permanently assign or broker its commitments for firm gas transportation capacity on interstate pipelines which it once held to serve its noncore customers.
The changes in the supply and transportation segments of the gas industry will likely result in increased competition. The FERC has conditionally approved the expansion of an interstate pipeline's existing system into the Company's service territory. See "Gas Utility Operations -- Other Competitive Pipeline Projects" below. If built, this pipeline will compete directly for transportation service to the Company's noncore customers and may result in the loss of sales on the Company's gas transportation system. If the Company's
gas customers leave the Company's system by moving to an alternative intrastate delivery system, the Company will need to recover the fixed costs of its gas supply and delivery system over fewer units of sales. Unless costs are reduced or imposed as transition charges on exiting customers, the price per unit for remaining customers would go up, further exacerbating the competitive pressures.
ELECTRIC INDUSTRY
While the restructuring of the electric industry is still evolving, recently effected and currently proposed changes at both the federal and state levels are expected to bring increased competition into the electric generation business. The Company performs the functions of electricity production, transmission, distribution and customer service. However, the Company already obtains one-third of its electrical power supply from generation sources outside its service territory and from qualifying facilities (QFs), small power producers or cogenerators who meet certain federal guidelines which qualify them to supply generating capacity and electric energy to utilities, owned and operated by independent power producers (IPPs). It is expected that new power plant projects will be increasingly undertaken by IPPs rather than utilities. In addition, the recently enacted National Energy Policy Act of 1992 (Energy Act) reduces various restrictions on the operation and ownership of IPPs and provides them and other wholesale suppliers and purchasers with increased access to electric transmission lines throughout the United States.
At the state level, in April 1994 the California Public Utilities Commission (CPUC) issued a proposal on electric industry restructuring which seeks to lower energy prices and provide customers with a choice of electric generation suppliers (known as direct access). In addition, where competition does not exist, the CPUC proposes to move electric utilities from traditional regulation, under which the utilities' revenues are set by regulators so as to cover the utilities' costs and provide a fair rate of return, to performance-based ratemaking (PBR). The shift to PBR is intended to provide stronger incentives for efficient utility operations, management and investment.
Under its April 1994 proposal, the CPUC would unbundle electric services and, on a phased-in basis over time, provide to electric utility retail customers the option to choose from a range of electric generation providers, including utilities, beginning in 1996. This plan is termed "direct access." Utilities serving a given territory would still be obligated to provide transmission and distribution services on a nondiscriminatory basis to customers choosing direct access service from another generation provider, thereby engaging in the practice known as retail wheeling. Coinciding with these changes, the CPUC foresees development of a competitive spot market for electric generation and an increasing need for inter-regional coordination of the electric grid, and elimination of existing resource planning and procurement approaches.
If as a result of restructuring a substantial number of the Company's customers were to elect electric generation alternatives under a retail wheeling system, the Company's recovery of its purchased power obligations to QFs and its investment in its electric generation assets would be dependent on prices charged to remaining customers, transition charges that may be imposed on existing customers, and the Company's ability to reduce its costs. While the CPUC proposal contemplates that some stranded costs of utility generating facilities be recovered through a "competition transition charge," the CPUC has not specified whether other costs, such as regulatory assets and QF obligations, might be recovered through such a charge or how such charge would be allocated to and collected from customers. See "Proposed Regulatory Reforms -- Electric Industry Restructuring Proposal" below.
THE COMPANY'S RESPONSE TO THE NEW COMPETITIVE ENVIRONMENT
The restructuring of the electric and gas industries has led to a greater emphasis on the Company's ability to offer its services at competitive prices. Currently, the Company's average gas prices for residential, commercial and industrial customers are among the lowest utility gas prices in California. The Company's residential electric bills are at the middle of the scale nationally. However, the Company's prices per kWh are high when compared with national averages. The Company's prices for industrial customers average approximately 7.0 cents per kWh, which is comparable to prices charged by the other major California
utilities, but above the industrial electric prices in many other states. The Company's electric prices include the costs for generation, transmission, distribution and customer service.
The Company has taken several significant steps to address the issues raised by the new competitive environment in the energy industry. These steps include proposals to modify the existing regulatory process and to provide the Company additional pricing flexibility for those customers with the most competitive options. These proposals, together with various cost containment measures implemented by the Company, are intended to help position the Company to effectively compete in the restructured electric and gas industries. With this goal in mind:
-- The Company has proposed to extend through 1996 its electric rate freeze, which began in 1993.
-- The Company has announced a five-year goal of reducing its system average electric rate to 10 cents per kWh or less, which would constitute about a 25% reduction in the Company's system average electric rate after adjusting for inflation.
-- In December 1994, the Company, the CPUC's Division of Ratepayer Advocates (DRA), the California Attorney General and other parties proposed to modify the Diablo Settlement to reduce the price paid for electricity generated at Diablo Canyon over the next five years. See "Diablo Canyon -- Diablo Settlement" below.
-- The Company has requested CPUC approval to implement a statewide three-year experimental program under which California utilities would offer certain industrial customers and other large energy users the option to receive electricity from competitive suppliers, starting as early as January 1, 1996.
-- The Company has proposed instituting PBR for determining base revenues, under which electric and natural gas base revenues would be determined annually by formula rather than through general rate cases (GRCs), attrition rate adjustments (ARAs) and Cost of Capital proceedings. The Company has also proposed a core gas procurement incentive mechanism (CPIM) that would substitute for reasonableness reviews of certain costs. The CPIM would measure the Company's gas procurement costs against market benchmarks and would provide for the sharing between ratepayers and shareholders of variances from a preset range around the market benchmark.
-- The Company has reduced electric rates for certain of its largest industrial customers through an economic stimulus rate that the Company proposes to extend through the end of 1996.
-- The Company has planned reductions in annual spending in 1995 of approximately $600 million from 1993 spending levels.
-- The Company has refinanced debt and preferred stock over the last three years resulting in annual savings of approximately $97 million in financing costs.
-- Through its wholly owned subsidiary, Enterprises, the Company has taken steps to position itself to compete in the nonregulated energy business. In 1994, Enterprises and Bechtel Enterprises, Inc. acquired J. Makowski Co., Inc. (Makowski), a company engaged in the development of natural gas-fueled power generation projects and natural gas distribution, supply and underground storage projects. In addition, Enterprises, in partnership with Bechtel Enterprises, Inc., is in the process of forming a company to develop, build, own and operate international nonutility generation projects.
While it is difficult to predict the ultimate outcome of the ongoing changes that are taking place in the utility industry, the Company believes that the end result will involve a fundamental change in the way it conducts its business. The changes may impact financial operating trends and add volatility to the Company's earnings. The Company is actively seeking regulatory and operational changes that will allow the Company to provide energy services in a safe, reliable and competitive manner while achieving strong financial performance.
CALIFORNIA RATEMAKING MECHANISMS
The ratemaking mechanisms currently applied by the CPUC in setting the Company's rates are discussed below. As more fully discussed below (see "Proposed Regulatory Reforms -- Company's Proposals"), the Company has filed proposals with the CPUC requesting alternatives to certain aspects of the current regulatory approach to setting rates. If adopted, those proposals would significantly alter the existing ratemaking mechanisms. In addition, the Company proposes to continue through 1996 its freeze on retail electric rates, first implemented in 1993, which impacts the application of certain of these ratemaking mechanisms in current rate proceedings (see "Current Rate Proceedings" below).
BASE REVENUE MECHANISMS
Under the CPUC's Rate Case Plan, the CPUC sets the Company's base revenue requirements for both electric and gas operations in the GRC proceeding. Base revenue is revenue intended to recover the Company's fixed costs and non-fuel variable costs and to provide a return on invested capital. (Fuel revenue requirements, intended to recover the Company's fuel and fuel-related costs, are set as part of the Energy Cost Adjustment Clause (ECAC) proceeding for electric operations and the Biennial Cost Allocation Proceeding (BCAP) for gas operations, as discussed below.) In the GRC, revenues and expenses are determined on a forecast or future test-year basis, rather than on a historic-year basis. The Company files a GRC application once every three years, with a decision issued approximately 13 months after the application is filed. The Company's current rates are based on its 1993 GRC. The Company filed its 1996 GRC application in December 1994, for rates effective January 1, 1996.
The ARA adjusts base rates in the years between GRC decisions to partially offset attrition in earnings due to changes in non-fuel operating expenses and capital costs. Labor expenses and nonlabor maintenance and operation expenses are indexed, and a prescribed amount is allowed for recovery of expenses related to changes in depreciation, income taxes, financing costs, rate base growth and other items. The ARA improves the Company's ability to earn its authorized rate of return for utility operations in the years between GRCs. The cost of capital incorporated in an ARA, including authorized return on equity, is determined separately by the CPUC in the annual Cost of Capital consolidated proceeding which reviews financing costs and adopts capital structures for all California energy utilities.
In May 1993, the DRA and various special interest groups filed a joint petition with the CPUC requesting suspension, for an indefinite period, of the ARA mechanism. The petition requests that any future attrition rate increases be considered only upon application for such relief and only if the then current rate of inflation exceeds 6% on an annual basis. The petition recommends that any attrition rate adjustment authorized in such cases be limited to inflation above the 6% threshold level. The CPUC has not acted on the DRA's petition, but its staff has recommended that the petitioners raise the matter in the Company's 1996 GRC.
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 or ARA proceeding. 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, and are recovered from or returned to customers through higher or lower future rates. ERAM rate adjustments are made as part of the ECAC proceeding described below.
ELECTRIC FUEL REVENUE MECHANISMS
The ECAC provides for recovery of 91% of recorded (or actual) electric fuel and fuel-related energy costs, and for collection of revenues attributable to Diablo Canyon generation. Differences between the sum of actual costs and Diablo Canyon revenues recoverable through ECAC, and the revenues intended to cover such amounts, accumulate in a balancing account, usually with interest, and are recovered from or returned to ratepayers through ECAC adjustments to future rates. ECAC rate adjustments are set once a year, based on a January 1 effective date, to recover the adjustment amount over a forward-looking calendar test year. Revenue adjustments resulting from the California Alternate Rates for Energy (CARE) program (formerly known as
the Low Income Rate Assistance, or LIRA, program) and the ERAM are consolidated with the ECAC adjustment in the annual ECAC proceeding. The CARE program provides for discount residential rates for customers who qualify under low-income criteria, with the direct costs of CARE electric rate discounts funded through revenue adjustments made in the ECAC proceeding. Rates are subject to a further ECAC adjustment effective May 1 if the required adjustment would be more than 5% of total annual electric revenues.
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. The amount of Diablo Canyon revenues recovered through the ECAC is determined under the Diablo Settlement and is not subject to reasonableness review. See "Diablo Canyon -- Diablo Settlement" below.
The Annual Energy Rate (AER) mechanism provides for recovery of 9% of forecasted electric fuel and fuel-related costs, without balancing account protection for actual costs that are higher or lower than forecasted. Thus, the AER mechanism places the Company at partial risk for variations between actual and forecasted electric energy costs. To minimize the revenue risk resulting from the potential for substantial swings in energy-related expenses, the increase or reduction in earnings due to operation of the AER is limited to a change in return on equity of 1.4 percent.
GAS FUEL REVENUE MECHANISMS
The BCAP is the major rate proceeding for the Company's natural gas service. As part of this proceeding, the gas fuel revenue requirement and gas transportation revenue requirement are adopted, based on forecasts and assumptions for the upcoming two-year period. The gas fuel revenue requirement provides for the recovery of the cost of the gas procured for core customers; the gas transportation revenue requirement provides for the recovery of the cost of providing gas transportation service for all gas customers and other costs incurred in providing gas service, and also includes the gas base revenue requirement set in the GRC and adjusted by the ARA mechanism.
Both the gas fuel revenue requirement and the gas transportation revenue requirement set in the BCAP include amounts accumulated in several associated balancing accounts. The main balancing account associated with the gas fuel revenue requirement is the Purchased Gas Account (PGA), which accumulates differences between the actual cost of gas procured for core customers and the revenues intended to recover those costs. The main balancing accounts associated with the gas transportation revenue requirement are the core and noncore Gas Fixed Cost Accounts (GFCAs), which generally accumulate differences between the actual transportation revenues and the authorized transportation revenue amounts for the core and noncore customer classes, respectively. In the case of the noncore GFCA, only 75% of any overcollection or undercollection of revenues is included in rates.
BCAP rate adjustments may also include amounts accumulated in the Interstate Transition Cost Surcharge (ITCS) balancing account. Demand charges for interstate gas transportation capacity held by a utility which are not fully recovered under the operation of the CPUC's capacity brokering rules accumulate in the ITCS account and are recovered as authorized by the CPUC. Unrecovered demand charges will be allocated to customers on an equal cents-per-therm-usage basis, subject to a limit on the amount that can be allocated to core customers.
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. Revenue allocation (also referred to as cost allocation) is based primarily on forecasts of demand and use by each customer class. The BCAP also includes the rate design process, in which it is determined how specific costs are recovered from customers, with rates set accordingly.
Generally, a BCAP filing is made on August 15 of every other year for rates to be effective on April 1 of the following year. An interim filing, referred to as a trigger filing, is permitted to set new rates for the second year of the BCAP period if amortization of accumulated overcollections or undercollections in balancing accounts would change either bundled core rates or noncore transportation rates by more than 5%.
In December 1992, the CPUC announced proposed rules which would (i) extend the gas ratemaking cycle from two to three years and (ii) reduce the amount of balancing account protection provided for noncore transportation revenues. Other than accepting comments from interested parties, the CPUC has taken no further action on the proposed rules.
OTHER RATE ADJUSTMENT MECHANISMS
Under the Customer Energy Efficiency (CEE) ratemaking mechanism adopted in 1990, the Company is authorized to recover in rates some of the energy savings resulting from and costs of certain of its CEE, or Demand Side Management (DSM), programs. CEE rate adjustments resulting from shareholder incentives earned on CEE programs are determined as part of the Annual Earnings Assessment Proceeding (AEAP), a consolidated proceeding established by the CPUC to authorize shareholder earnings for the Company and the other California energy utilities arising out of the previous year's DSM program accomplishments. AEAP rate adjustments will be consolidated with any other rate changes effective on January 1 of each year. See "Customer Energy Efficiency/Demand Side Management Programs" below.
The Catastrophic Events Memorandum Account (CEMA) permits utilities to record for eventual recovery through rates the reasonable costs they incur in restoring service, repairing or replacing facilities and complying with government orders following a catastrophic event which is declared a disaster by the appropriate federal or state authorities. The utility must seek recovery of costs accumulated in the CEMA through a GRC or other formal rate-setting application, with recovery subject to a reasonableness review by the CPUC.
PROPOSED REGULATORY REFORMS
A number of proposals have been made by both the CPUC and the Company to effect reforms to the current regulatory approach to setting rates for California utilities. The most significant of these proposed reforms are detailed below.
ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL
In April 1994, the CPUC issued an order instituting a rulemaking and investigation (OIR/OII) on electric industry restructuring. The proposal, which is subject to comment and modification, involves two major changes in electric industry regulation.
The first would move electric utilities from traditional ratemaking to PBR. The second would unbundle electric services and provide electric utility retail customers the option to choose from a range of electric generation providers, including utilities. The CPUC characterized this approach as customer direct access. Under the CPUC's proposal, customer direct access to power supplies would be phased in over a six-year period from 1996 to 2002. Utilities would still be obligated to provide transmission and distribution services to all customers.
To ensure an orderly transition that maintains the financial integrity of the utilities, the CPUC proposed that uneconomic costs of utility generating assets (i.e., costs which are above market and could not be recovered under market-based pricing) be recovered through a competition transition charge (CTC). However, the OIR/OII did not specify which costs might be recovered through such a transition charge or how such a charge would be allocated to and collected from customers.
In June 1994, the Company filed its initial comments on the CPUC's proposal. The Company's response generally supported the CPUC's direct access approach to restructuring the energy services industry, but proposed an implementation schedule for direct access beginning in 1996, with direct access service available to all customers by 2008. The Company indicated that if its proposed implementation schedule is adopted, it will request recovery of certain incurred and committed costs through the CTC, but will not request recovery of transition costs associated with its electric generation facilities. The Company also indicated that it did not intend to shift costs between customer classes. For direct access customers, the Company proposed that it be given the pricing flexibility to compete and sell unbundled electric power while assuming the market risk of competitive pricing. The Company indicated that its proposed schedule, coupled with pricing flexibility, will
permit the Company sufficient time to reduce its generation costs and recover its investment in facilities built to meet its long-standing utility service obligations.
Under the Company's proposed implementation schedule for direct access, industrial and large commercial customers (which represented approximately 30% of the Company's electric generation revenues in 1994) would be eligible for direct access in the period 1996 through 2002. The remaining non-residential customers (which represent approximately 31% of 1994 electric generation revenues) would be eligible in the period 2003 through 2006. Residential customers (which represent approximately 39% of 1994 electric generation revenues) would be eligible in 2007 and 2008.
In its response, the Company proposed that unless and until a policy decision is made to discontinue existing environmental or social benefit programs, the costs of those programs should be allocated to all electric customers, including those who elect direct access, and included as a separately identified component on customers' bills. The Company also proposed to retain an ongoing obligation to provide electric power for residential customers, but suggested that the utility should be obligated to provide electric supply only on a best efforts basis to non-residential direct access customers that decide to return to the Company for their power supply and on terms of service to be negotiated.
In November 1994, the Company filed testimony with the CPUC on uneconomic assets and obligations which would result from the CPUC's proposed electric industry restructuring. The Company indicated that the CTC should be permitted to provide for three types of costs: (1) utility-owned generation assets and obligations resulting from power purchase agreements other than contracts with QFs, (2) QF power purchase obligations, and (3) generation-related regulatory assets. The Company also indicated that it would not seek CTC recovery for the first of these categories -- costs associated with utility-owned generation assets and non-QF obligations -- if direct access is phased in over a 12-year period consistent with the proposal made by the Company in June 1994 and if pricing flexibility was provided to allow the Company to successfully compete to provide energy services to direct access eligible customers.
The Company has since filed revised testimony which reflects the proposed agreement to modify the pricing provisions of the Diablo Settlement. See "Diablo Canyon -- Diablo Settlement" below. If the agreement is approved, it would reduce the amount of potential transition costs associated with the Company's generation assets.
The table below sets forth the Company's revised estimates of the CTC which reflects the proposed settlement amounts for Diablo Canyon.
ILLUSTRATION OF PG&E'S POTENTIAL CTC* USING PG&E'S COMPETITIVE PROXY PRICE AND REVISED DIABLO PRICING
- --------------- * The calculations reflected in the table are based on numerous assumptions, variables and estimates of future prices, energy supplies and economic trends. The CTC shown should be viewed only as preliminary estimates. The adopted CTC could be higher or lower depending on the method and assumptions selected by the CPUC for deriving the CTC.
These CTC estimates were determined by comparing the future revenue requirements of generation assets (including Diablo Canyon at the proposed modified prices) and power purchase obligations over a twenty-year and thirty-year period, respectively, with the revenues computed at the assumed market price.
The revenue requirement for Diablo Canyon and all Company-owned generation assets included a return on investment. The actual amount of uneconomic assets and obligations will depend upon the final form of regulatory changes adopted by the CPUC and the actual market price of electricity. CTC recovery less than the amount estimated by the Company will not equate to the loss, if any, the Company may record as a result of the electric industry restructuring. See "Financial Impact of the Electric Industry Restructuring Proposal" below.
In December 1994, the CPUC issued an interim decision in the OIR/OII. The decision set a schedule under which the CPUC would propose a policy decision in March 1995, with a final policy decision effective no earlier than September 1995. However, on March 21, 1995, the CPUC announced that it was postponing issuance of its proposed policy statement to allow additional time for analysis of the extensive record developed in the OIR/OII. It is expected that, when it is issued, the CPUC's proposed policy statement will be subject to hearings and state legislative review before it can be implemented.
The CPUC's December 1994 interim decision also established a public working group to comment on unbundling and cost recovery, social programs and resource procurement under several different models for restructuring which involve direct access or a supply pool for use by wholesale and/or retail purchasers of electricity. The working group, which consisted of the energy utilities and any other parties who joined voluntarily, submitted its report to the CPUC in February 1995.
In an effort to allow large energy users to begin exercising choice among electricity suppliers while public policy issues are resolved in the OIR/OII, the Company has requested CPUC approval to implement an experimental program under which California utilities would offer certain customers the option to receive electricity from competitive suppliers beginning as early as January 1996. See "Company's Proposals -- Experimental Procurement Service for Customer-Identified Electric Supply" below.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL
The transition to a competitive market environment may affect the Company's future revenues and cash flows. In the event that recovery of the Company's costs and investments becomes unlikely or uncertain due to competitive pressures or regulatory changes, it could cause the Company to write off applicable portions of its regulatory assets. The final CPUC determination of uneconomic costs and the method and amount of recovery could adversely affect the Company's returns on its investments in electric generation assets. If future electric generation revenues are insufficient to recover the Company's investments and QF obligations, the Company would recognize a loss upon the determination of the competitive price for electricity resulting from the electric industry restructuring. The book value of the Company's generation assets, excluding Diablo Canyon, is approximately $2.7 billion at December 31, 1994. The net book value of the Company's investment in Diablo Canyon is approximately $5.2 billion at December 31, 1994.
The Company currently accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $3.7 billion of regulatory assets, including balancing accounts, as of December 31, 1994. If the OIR/OII is adopted as proposed by the CPUC or the Company determines that future electric generation rates will no longer be based on cost-of-service, the Company will discontinue application of SFAS No. 71 for the electric generation portion of its operations. If such discontinuance should occur, the Company would write off all applicable generation-related regulatory assets to the extent that transition cost recovery is not assured. The regulatory assets attributable to electric generation, excluding balancing accounts of approximately $700 million which are expected to be recovered in the near term, are estimated to be $1.6 billion at December 31, 1994. This amount could vary depending on the allocation methods used.
The final determination of the financial impact will depend on the form of regulation, including transition mechanisms, if any, adopted by the CPUC and the groups of customers affected. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations.
COMPANY'S PROPOSALS
Experimental Procurement Service for Customer-Identified Electric Supply
In February 1995, the Company requested CPUC approval to implement a statewide three-year experimental program under which California utilities would offer industrial customers and other large energy users the option to receive electricity from competitive suppliers, starting as early as January 1, 1996. The Company's proposed program would include the following key features:
-- A group of large electricity users would be permitted to enter into individually negotiated "buy/sell" agreements with alternative suppliers of electricity. This "buy/sell" proposal would be modeled to a large extent after the "customer identified gas" (CIG) program implemented by the CPUC in 1991 as part of its restructuring of the natural gas industry. The utility would purchase electricity on behalf of each participating customer. The electricity would be purchased from any supplier chosen by the customer, at a price previously negotiated by the customer. The utility then would resell the electricity to the customer at the customer's negotiated price, as part of a bundled retail sale to that customer. For customers who elect to purchase energy from alternative sources located outside the Company's service territory, the Company will agree to use a portion of its transmission capacity (up to 50 megawatts (MW) at the Oregon-California border to accommodate purchases on behalf of customers whose suppliers deliver at that point. The Company will accept and buy power delivered to its other points of interconnection, and amounts in excess of 50 MW at the Oregon-California border interconnection, only if transmission capacity is available.
-- The number of the Company's customers eligible to participate in the experiment would increase each year. The experimental program initially would apply in 1996 to customers with annual average demand above 7,500 kilowatts (kW) (approximately 30 customers). In 1997 customers with annual average demand above 4,000 kW (approximately 50 additional customers) would be eligible for the program, joined in 1998 by customers with annual average demand above 2,000 kW (approximately 110 additional customers).
-- Utilities would be permitted to negotiate agreements with customers to compete with alternative suppliers of electricity. Lower revenues to the utility resulting from such individually negotiated contracts would not be offset through rate increases to other customers, putting shareholders at risk for any loss of revenue resulting from the experimental program. The Company estimates that if, upon full implementation of the experiment, all eligible customers who might find it economic participated in the buy/sell program and were able to use alternative suppliers to meet their entire load requirements, the maximum annual revenues that could be lost to the Company, net of generation costs saved as a result of customers' participation in the buy/sell program, is approximately $21 million.
-- Customers participating in the "buy/sell" experiment would receive a predetermined credit on their utility bills which is based on prices paid to QFs for energy and capacity. This credit is used as a proxy for the market price of electricity. Added to participating customers' bills would be the cost of power they negotiated with an alternative supplier.
-- The participating customers' prices would remain fully "bundled," a full package of services at one price. This would mean that issues such as unbundling, recover of transition costs, funding of social and environmental programs and resolution of state and federal jurisdictional matters would not have to be resolved prior to commencement of the experimental program.
-- At the conclusion of the three-year experimental program, the information gained could be used by public policy makers to evaluate the benefits of customer choice.
PBR
In March 1994, the Company filed an application with the CPUC requesting that it adopt the Company's proposed Regulatory Reform Initiative (RRI). The Company's RRI included, among other things, a PBR proposal. While the guiding principles behind the Company's RRI proposal are not affected by the OIR/OII, many of the specifics would change. Once the details of the CPUC's electric industry restructuring plan are
sufficiently definitive, the Company proposes to revise its RRI filing to reflect the CPUC's plan. The Company expects to seek a revised RRI that includes PBR for determining base revenues annually by formula rather than through GRCs, ARAs and Cost of Capital proceedings.
CPIM
Specific proposals regarding a gas procurement mechanism were not included in the Company's March 1994 RRI filing. However, in December 1994, the Company filed an application for approval of the CPIM, a three-year experimental gas procurement incentive mechanism for core procurement purchases. The CPIM reflects an agreement with the DRA and would, among other things, replace traditional reasonableness review of gas costs with a comparison to a market-based benchmark.
The CPIM covers all of the Company's purchases of commodity gas and pipeline capacity for its core and core subscription customers. (Core subscription customers are noncore customers who elect to receive combined procurement and transportation service from the Company.) The CPIM does not cover any gas base costs, including amounts associated with storage operations, gas and pipeline capacity purchased for the Company's power plants or out-of-state pipeline capacity beyond that reserved for the core and core subscription customers.
Under the CPIM, the reasonableness of the Company's core gas purchases is determined by a comparison of actual costs against a market benchmark. The Company is either rewarded or penalized depending on whether its actual incurred costs fall below or above the benchmark and a tolerance band, or reasonableness zone. The Company would recover all costs that fall within the reasonableness zone; ratepayers and shareholders would share the costs or savings if actual costs fall above or below the reasonableness zone.
The Company proposed an expedited schedule under which the CPUC would approve the CPIM by May 1995. However, protests have been filed requesting hearings or workshops on the Company's CPIM application, and it is not clear when a CPUC decision will be issued.
Pricing Flexibility Proposals
The Company has filed testimony in its 1995 electric rate design window (RDW) proceeding proposing beneficial rate options for certain industrial, commercial and agricultural customers who might otherwise not take service from the Company. The CPUC's GRC plan establishes the RDW as a forum for considering certain rate design changes in years between GRCs. The Company's proposals are narrowly focused to provide beneficial options to some customers. Specifically, the Company proposes several standard contracts for commercial and industrial customers which offer prices based upon the cost of the customer's alternatives or, in some cases, specified discounts from the Company's rates. (These contracts are similar to those contemplated in the Large Electric Manufacturing Class proposal that was included in the Company's March 1994 RRI filing.) In addition, the Company proposes rate options which would establish discounts from the current rates charged to certain agricultural customers. Although the Company's RDW filing seeks to have any revenue shortfall associated with these rate options allocated to all customers in future revenue allocation proceedings, in other instances in which the CPUC has approved similar rate options, revenue shortfalls have been allocated, in whole or in part, to shareholders.
With respect to gas service, the Company filed a petition with the CPUC in June 1994 requesting authorization to implement an optional long-term competitive noncore gas transportation tariff which would be offered to the Company's largest gas transport customers under a ten-year firm service agreement. The Company's petition indicated that its shareholders would bear the risk of any revenue shortfalls attributable to differences between the long-term rate option and the customer's otherwise applicable standard rate. In September 1994, the CPUC issued a decision approving the Company's proposed long-term noncore gas transportation tariff, but subject to certain conditions that were not contemplated by the Company's original proposal. The Company has filed a petition for rehearing of that decision, and indicated that if the CPUC continues to insist upon its proposed conditions as the basis for its approval of the proposed tariff, the Company intends to decline to implement the proposed tariff and would not voluntarily accept the tariff as modified by the CPUC.
As an alternative service option, in October 1994 the Company began offering a standard 59-month interruptible transportation service, at a rate comparable to that requested under the noncore gas transportation tariff proposal, to noncore customers with potential transportation alternatives. A potential competitor of the Company has filed a complaint at the CPUC challenging the Company's use of this service option on several grounds. The CPUC has not yet acted on the complaint.
CURRENT RATE PROCEEDINGS
In August 1994, the Company announced that it would extend through 1995 its freeze on retail electric rates which began in 1993. The Company also announced that it would continue its annual $70 million economic stimulus rate reduction through 1995 for its largest business customers. (The Company has since proposed to extend its electric rate freeze and the economic stimulus rate reduction through 1996.)
In December 1994, the CPUC approved the continuation of the electric rate freeze through 1995 and issued its decisions in the Company's ARA and ECAC proceedings. In order to accomplish the electric rate freeze, the effects of the CPUC decisions on the Company's various electric rate proceedings were consolidated, resulting in a net change in electric rates of zero, effective January 1, 1995 (see "1995 Revenue Changes" below).
1995 REVENUE CHANGES
The following table summarizes the various rate case decisions that became effective on January 1, 1995.
SUMMARY OF RATE CASE DECISIONS EFFECTIVE JANUARY 1, 1995 (IN MILLIONS)
ARA Proceeding. In December 1994, the CPUC issued a resolution authorizing the Company to implement an ARA to keep the Company's retail electric rates unchanged through 1995, consistent with the Company's 1995 electric rate freeze. The CPUC authorized the Company to forgo the electric rate increase of approximately $170 million that otherwise would have occurred on January 1, 1995 as authorized in the Company's 1993 GRC. In addition, the CPUC adopted the Company's proposal to decrease electric base revenues in an amount equal to the increase in revenues approved by the CPUC in the Company's 1995 Cost of Capital proceeding and ECAC proceeding (as described below), and the increase in revenues contemplated by the proposed settlement in the Helms proceeding (see "Electric Utility Operations -- Helms Pumped Storage Plant" below), such that electric rates will not increase through the end of 1995. The Company is implementing base cost reductions which are reflected in the decreased base revenues.
The CPUC also authorized the implementation of an ARA which results in an increase of $69 million for gas base rates. Combined with the previously authorized increases of $33 million relating to the 1995 Cost of Capital proceeding and $31 million for partial recovery of amounts accrued in the ITCS balancing account (see "Gas Utility Operations -- Restructuring of Interstate Gas Supply Arrangements -- Recovery of Interstate Transportation Demand Charges" below), and approval of the Company's request to reduce authorized funding for gas CEE programs in 1995 by $33 million, gas revenues increased, effective January 1, 1995, by approximately $100 million, or 4.7% over rates previously in effect.
Also in December 1994, the CPUC granted the Company's request for reductions of approximately $100 million in authorized funding levels for 1995 electric CEE programs and $17 million for electric research development and demonstration (RD&D) programs. The request for such reductions was made as part of the Company's efforts to control costs under its electric rate freeze plan.
1995 Cost of Capital Proceeding. As part of its ruling in the annual generic Cost of Capital proceeding for California's major energy utilities, the CPUC authorized the Company to set rates in 1995 to provide a utility return on common equity of 12.10%. This represents an increase from the 11.00% return on common equity allowed in 1994. The higher return on common equity is intended to recognize increased interest rates as well as increased risks associated with the CPUC's OIR/OII on electric industry restructuring in California. The decision authorizes a utility capital structure of 48.00% common equity, 5.50% preferred stock and 46.50% long-term debt, which represents an increase from 47.50% in the current equity component of the Company's capital structure. The combined authorized costs of debt, preferred stock and the 12.10% return on common equity results in an overall return on rate base of 9.79% for 1995, compared with the 9.21% authorized for 1994. The decision increased revenue requirements by approximately $105 million for electric rates and $33 million for gas rates, effective January 1, 1995. However, consistent with the Company's current electric rate freeze, the electric revenue increase authorized in this proceeding was offset by a decrease in base revenues, such that electric rates will not increase through the end of 1995.
ECAC. In December 1994, the CPUC issued a decision in the Company's 1995 ECAC proceeding which adopted all of the Company's proposals to continue the electric rate freeze currently in effect, including a $158 million ECAC increase, a base rate decrease approved in the ARA proceeding described above, an early refund of $84 million in CEE program dollars collected from ratepayers but not spent in 1993 and 1994, and deferral of collection of approximately $444 million of ECAC costs forecasted to be undercollected as of December 31, 1995. In granting the deferral, the decision continued imposition of the three conditions placed on the first deferral in the 1994 ECAC proceeding: (i) reinstatement of the AER mechanism, which places shareholders at risk for 9% of any deviations from forecasted operations, (ii) no interest on the estimated revenue requirement deferral, and (iii) written notification to all parties if the Company forecasts that rates would need to rise an additional 5% or more to amortize the undercollection.
In its decision the CPUC agreed with the Company that the forgoing of interest on the deferral was limited to the adopted deferral amount and not to undercollections resulting from forecast error. The decision also makes it clear that the deferral would not be considered a transition cost in any restructuring of the electric industry, but should be separately collected from the customers receiving electric service during the period in which the deferred amounts were incurred.
The ECAC decision also approved continuation of the Company's economic stimulus rate reduction, an annual $70 million rate reduction offered to the Company's largest business customers. The rate reduction, originally offered in July 1993, was developed to help attract and retain major employers in Northern and Central California.
Although the ability of the Company to recover the ECAC balancing account undercollection has been impacted by the Company's freeze on retail electric rates, the proposed modification of the price for Diablo Canyon power will assist in reducing the ECAC balance. The Company currently believes that the ECAC balance will be collected in rates over the near term.
BIENNIAL COST ALLOCATION PROCEEDING
In July 1994, the CPUC approved the Company's request for an increase of $162 million (9.3%) in core gas rates effective July 15, 1994. The Company had requested the increase in an interim, or trigger, filing as permitted under the BCAP mechanism to set new rates for the second year of the BCAP period. During the first half of the applicable BCAP period (November 1992 -- October 1993), actual gas costs were higher than the forecasted costs used to adopt rates and actual gas sales were less than expected, leading to unrecovered gas and related fixed costs.
In November 1994, the Company filed an application with the CPUC in its 1995 BCAP requesting a gas rate increase of approximately $173 million annually for the two-year test period beginning October 1, 1995, and ending September 30, 1997. The Company's request reflects a $53 million annual increase in procurement
revenues and a $120 million annual increase in transportation revenues. If the Company's request is adopted, rates would be effective September 15, 1995. A final CPUC decision is expected in the third quarter of 1995.
1996 GENERAL RATE CASE
The Company filed its 1996 GRC application in December 1994 for base rates effective January 1, 1996. The application, as updated by the Company since the original filing, requests no change in electric revenues and a $163 million decrease in gas revenues, compared to rates in effect in 1995. The electric and gas requests will be consolidated with other proceedings, including the BCAP, the ECAC and the Cost of Capital proceedings, to determine the revenues to be collected from customers in 1996. (The request included in the original application to increase revenues by $13 million for the California, or in-state, portion of the Pipeline Expansion (see "Gas Utility Operations -- PGT/PG&E Pipeline Expansion Project" below) will be considered in a separate proceeding.) Since the Company anticipates that the CPUC will have implemented the Company's proposed PBR mechanism for determining base revenues before January 1, 1997, the Company's GRC application does not request the adoption of an ARA for the years 1997 and 1998.
In March 1995, the DRA submitted its report on the Company's GRC application. The DRA recommendation, which is subject to further revision, proposes an overall revenue requirement which is significantly lower than that requested by the Company. The DRA recommends that the Company reduce its electric revenue requirement by $434 million (compared with the Company's request for no change), and its gas revenue requirement by $292 million (compared with the Company's request for a $163 million reduction). A significant portion of the difference between the revenue requirement requested by the Company and that recommended by the DRA relates to administrative and general expenses and the level of wages and benefits paid to Company employees.
Hearings on the 1996 GRC are expected to begin in April 1995, with a final decision on the application expected in December 1995.
WORKFORCE REDUCTION RATE MECHANISM
In March 1993, the CPUC authorized the establishment of a memorandum account to record all costs and savings incurred in connection with the Company's 1993 workforce reduction program, subject to a reasonableness review. In October 1993, the Company filed a report with the CPUC to update the forecasted costs and savings associated with the workforce reduction program. As proposed in its filing with the CPUC, the Company's net revenue requirement savings expected to be achieved during the 1993 GRC cycle through the workforce reduction program are being passed on to ratepayers over a two-year period beginning January 1, 1994. These estimated savings total approximately $156 million.
The total cost of the 1993 workforce reduction program was $264 million, net of a curtailment gain relating to pension benefits. As a result of the Company's freeze on electric rates in 1994, the Company expensed $190 million of such costs relating to electric operations. The amount relating to gas operations was deferred for future rate recovery and is being amortized as savings are realized. At December 31, 1994, $31 million remained to be amortized.
CUSTOMER ENERGY EFFICIENCY/DEMAND SIDE MANAGEMENT PROGRAMS
The Company has long been active in the implementation of CEE and other DSM programs which encourage customers to implement energy-efficient measures. These measures allow the Company to defer capital expenditures in connection with generation, transmission and distribution facilities, reduce operating costs, reduce the environmental impact of operations and provide service options to customers. In addition, these measures help to minimize the use of existing fossil fueled generation. Since the mid-1970s, the Company has expended over $1.5 billion on DSM programs, allowing the Company to avoid the need for approximately 1,600 MW of new generating capacity.
Since 1990, the CPUC has permitted the Company to earn shareholder incentives on its CEE programs. For resource programs which are designed to produce positive net benefits (i.e., the net present value of the avoided energy, capacity, transmission and distribution costs of the programs exceeds the cost of the CEE
program), the shareholder incentive is a percentage of the positive net benefits. For certain service programs, including the Company's direct weatherization and energy efficiency education programs, the shareholder incentive is 5% of the cost of the programs.
In a 1993 decision, the CPUC determined that shareholder incentives on resource programs will be based on actual measured energy savings rather than forecasted savings, beginning with the 1994 DSM programs. The decision also concluded that, starting with the 1994 programs, shareholder incentives will be recovered in rates in four equal installments over a ten-year period, and the amount recoverable will be subject to the outcome of periodic measurement and evaluation studies. Beginning in 1994, the amount of shareholder incentives authorized for the Company and other California utilities will be determined annually in the AEAP. In early 1994, the Company filed the first annual AEAP application, requesting shareholder incentives for its 1993 CEE programs. The CPUC granted the Company's request of $14.9 million in shareholder incentives to be recovered over a three-year period. The Company estimates that it will earn approximately $15 million (after-tax) in shareholder incentives from the 1994 CEE programs. In accordance with the 1993 decision, the 1994 shareholder incentive will be collected in four installments over a ten-year period, and will be adjusted based on the results of measurement and evaluation studies.
In October 1994, the CPUC issued a decision establishing the incentive mechanism and incentive level for DSM programs in 1995 and beyond. The shareholder incentive level is established at 30% of the net benefits of the resource programs. However, the utilities must guarantee the overall cost effectiveness of their residential and non-residential portfolio of programs. If a portfolio is not cost-effective, the utility must refund to ratepayers the amount by which the costs of the programs exceed the resource benefits of the portfolio. If the actual accomplishments of a portfolio fall below a minimum performance standard established for the portfolio, the entire portfolio will be ineligible for shareholder incentives.
The Company plans to spend approximately $150 million on CEE programs in 1995, compared to the $235 million spent on 1994 programs. The new shareholder incentive mechanism and the requirement of ex post measurement of energy savings over the 10 years makes an estimate of earnings over that period difficult at this time. The Company currently estimates it will earn approximately $57 million in shareholder incentives over the 10-year period as a result of the 1995 programs. The Company is permitted to recover, through a balancing account, up to a maximum of 130% of the program expenses authorized for resource programs.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
The Company continues to require capital for improving its existing generation, transmission and distribution facilities to maintain their efficiency and reliability, to extend their useful lives and to comply with environmental laws and regulations. Expenditures for these purposes, including the allowance for funds used during construction (AFUDC) were approximately $1.1 billion for 1994. New investments in nonregulated businesses totaled $328 million in 1994.
The following table sets forth the estimated total capital requirements, consisting of capital expenditures for the utility functions, Diablo Canyon and the nonregulated investments of Enterprises and amounts for maturing debt and sinking funds for the years 1995 through 1999.
CAPITAL REQUIREMENTS (IN MILLIONS)
(See footnotes on following page)
- ---------------
(1) Utility expenditures are shown net of reimbursed capital and include California electric and gas operations and existing operations of the gas pipeline from Canada to California. Utility expenditures also include amounts relating to the expansion of PGT's pipeline system in 1995 through 1996 to provide additional deliveries in the Pacific Northwest. Capital expenditures relating to such further expansion total approximately $34 million. PGT is also considering a further expansion of its system which, if warranted by market demand at the time, could require capital expenditures of approximately $180 million during 1996 and 1997, which amount is not included in the table above.
(2) Utility expenditures include AFUDC. Expenditures for Diablo Canyon and the in-state portion of the PGT/PG&E Pipeline Expansion (see "Gas Utility Operations -- PGT/PG&E Pipeline Expansion Project" below) include capitalized interest.
(3) Enterprises' actual capital expenditures may vary significantly depending on the availability of attractive investment opportunities.
(4) In July 1994, the Company approved a plan for the disposition of DALEN Resources Corp. (DALEN), formerly PG&E Resources Company.
(5) U.S. Generating Company's expenditures include commitments by the Company 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 $100 million and $114 million in 1995 and 1996, respectively. There are no current commitments to make contributions in 1997 or thereafter.
(6) "Other" includes development and investment activity for international power generation, real estate and corporate development activities.
Most of the utility capital expenditures for 1995 through 1999 are associated with short lead time, modest capital expenditure projects aimed at providing the facilities required by new customers and at the replacement and enhancement of existing generation, transmission, distribution and common utility facilities to maintain their efficiency and reliability and to comply with environmental laws and regulations. One exception is the seismic retrofit of part of the Company's general office complex in downtown San Francisco.
The Company estimates that, in addition to the capital expenditure objectives referred to above, its total capital requirements for the years 1995 through 1999 will include approximately $2,251 million for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt. In January 1995, the Board of Directors authorized the Company to redeem or repurchase up to $153 million of mortgage bonds. In addition, $85 million remains from a previous authorization to repurchase medium-term notes. In 1994, the Company redeemed or repurchased $135 million of mortgage bonds, medium-term notes and Eurobonds. Redemptions and repurchases were financed in part by the issuance in 1994 of $30 million of medium-term notes and $63 million of redeemable preferred stock.
The funds necessary for the Company's 1995-1999 capital requirements 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.
The Company conducts a continuing review of its capital expenditures and financing programs. The programs and estimates above are subject to revision 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.
ELECTRIC UTILITY OPERATIONS ELECTRIC OPERATING STATISTICS The following table shows the Company's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
- ---------- (1) Includes energy supplied through the Company's system by the City and County of San Francisco for San Francisco's own use and for sale by San Francisco to its customers, by the Department of Energy for government use and sale to its customers, and by the State of California for California Water Project pumping, as well as energy supplied by QFs and purchases from other utilities. (2) Includes energy output from Modesto and Turlock Irrigation Districts' own resources. (3) Represents energy required for pumping operations. (4) Includes use by business units other than the Electric Supply business unit.
- ------------ (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, 1994, the Company owned and operated the following generating plants, all located in California, listed by energy source:
- ----------
(1) Several fossil fuel steam units (527 MW) were on long-term standby reserve during 1994. The units require a 12-18 month reactivation time, and are included as unavailable capacity in the Control Area Net Capacity table below. Effective December 31, 1994, 12 units, totaling 1342 MW (including the 527 MW on long-term standby reserve), were retired in place.
(2) Listed to show capability; subject to relocation within the system as required.
(3) The Geysers 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. See "Geothermal Generation" below.
To transport energy to load centers, the Company as of December 31, 1994, owned and operated approximately 18,450 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 34,209,000 kilovolt-amperes (kVa). Energy is distributed to customers through approximately 105,527 circuit miles of distribution system and distribution substations having a capacity of approximately 22,091,000 kVa.
The following table sets forth the available capacity for the control area (the area served by the Company and various publicly owned systems in Northern California) at the date of peak (including reduction for scheduled and forced outages and based on actual water conditions) by various sources of generation available to the control area and the total amount of generation provided by these sources during the year ended December 31, 1994.
- ----------
(1) The maximum control area peak demand to date was 19,607,000 kW which occurred in August 1993. (2) The reserve capacity margin at the time of the 1994 control area peak, taking into account short-term firm capacity purchases from utilities located outside the Company's service area: spinning reserve (capability already connected to the system and ready to meet instantaneous changes in demand) to the control area peak was 6.7% of the peak demand and total reserve (spinning reserve and capability available within a short period of time) was 14.3%. (3) Represents actual year net generation from sources shown.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
At present, California's long-range electric resource planning is coordinated between the California Energy Commission (CEC) and the CPUC. Every two years, the CEC prepares an Electricity Report that includes load forecasts and resource assumptions for a 20-year period. The CPUC conducts 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 (as described below). In making this determination, the CPUC gives great weight to the load forecasts and resource assumptions included in the CEC's Electricity Report.
The CEC has not yet adopted the complete 1994 Electricity Report (ER94). However, the CEC has adopted ER94 forecasts for energy loads and peak demands. The forecast for area electric peak demand (on a CEC area basis) indicates an increase from approximately 16,300 MW in 1994 to approximately 21,400 MW in 2013, reflecting a compound annual growth rate of 1.4%. The forecast for area electric energy load indicates an increase from approximately 88,600 gigawatt-hours (GWh) in 1994 to 116,100 GWh in 2013, reflecting a compound annual growth rate of 1.4%. The Company's current energy and peak demand forecasts after 2000 are higher than the CEC's ER94 forecast, primarily due to the Company's more optimistic economic and demographic assumptions.
For the remainder of this decade, the Company anticipates adding between 600 and 750 MW of electric resources. These resources will be comprised of (i) up to 265 MW of new purchases or company-owned resources resulting from the 1993 BRPU solicitation, assuming a recent FERC order finding the 1993 BRPU solicitation unlawful is not upheld, (ii) approximately 308 MW of new QF purchases to come on line by the end of 1996, (iii) between 49 and 200 MW of generation and DSM resources resulting from the integrated bid solicitation, (iv) improvements in its existing generating system, including 20 MW of upgrades of the hydroelectric system, and (v) further developments in regional operations efficiency from the Company's existing transmission lines from the Pacific Northwest. The Company currently plans no new major construction projects for electric supply before the year 2000, other than projects already under development.
The future of electric resource acquisition is being addressed in the electric industry restructuring OIR/OII. However, future additions to satisfy electric supply needs in the Company's service territory likely will be determined largely through a competitive resource procurement process open to all potential suppliers. The Company has indicated its willingness to forgo competing in this process to build new generation resources if the CPUC grants the Company significant flexibility in conducting the planning and procurement process.
The CEC committee conducting proceedings relating to the CEC's ER94 expanded the proceeding to include an extensive analysis of how changes in the structure of the electric industry may affect the achievement of California's energy policies. It is presently unclear to what extent considerations relating to electric industry restructuring will impact the content and timing of the final ER94.
In 1993, the CPUC issued a decision in a DSM proceeding (see "General -- Customer Energy Efficiency/Demand Side Management Programs" above) which selected the Company to conduct an integrated bidding pilot program in which both resource generation and DSM bidders compete in the procurement process. The CPUC ordered the Company to conduct a pilot bid program for between 49 and 200 MW. The Company issued a request for bids in December 1994 and expects to file contracts in early 1996 for approval by the CPUC.
ELECTRIC RESOURCES
QF GENERATION
Under the Public Utility Regulatory Policies Act of 1978 (PURPA), the Company is required to purchase electric energy and capacity produced by QFs. The CPUC established a series of power purchase agreements which set the applicable terms, conditions and price options. A QF must meet certain performance obligations, depending on the contract, prior to receiving capacity payments. The total cost of both energy and capacity payments to QFs is recoverable in rates. The Company's contracts with QFs expire on various dates from 1995 to 2026. Under these contracts the Company is required to make payments only when energy is supplied or when capacity commitments are met.
In 1994, the Company negotiated the early termination or temporary suspension of seven QF contracts at a cost of $155 million, to be paid over a six-year period beginning in 1994. The amount has been deferred with the expectation that it will be recovered in future rates.
Payments to QFs are expected to vary in future years. QF deliveries in the aggregate accounted for approximately 21% of the Company's 1994 total electric energy requirements and no single contract accounted for more than 5% of the Company's electric energy needs.
The amount of energy received from QFs and the total energy and capacity payments made under these agreements were:
As of December 31, 1994, the Company had approximately 5,900 MW of QF capacity under CPUC-mandated power purchase agreements. Of the 5,900 MW, approximately 4,600 MW were operational. Development of the balance is uncertain but it is estimated that only 300 MW of the remaining contracts will become operational. The 5,900 MW of QF capacity consists of 3,300 MW from cogeneration projects, 1,500 MW from wind projects and 1,100 MW from other projects, including biomass, geothermal, solar and hydroelectric.
GEOTHERMAL GENERATION
Because of declining geothermal steam supplies, the Company's geothermal units at The Geysers Power Plant (Geysers) are forecast to operate at reduced capacities. The consolidated Geysers capacity factor is forecast to be approximately 33% in 1995, which includes forced outages, scheduled overhauls and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 56% in 1994. The Company expects steam supplies at the Geysers to continue to decline.
The Company has entered into new steam sale agreements with several of its steam suppliers which allow the Company to alter the operation of its units to more economically utilize the existing installed capacity and partially offset the impact of the declining steam supplies at the Geysers. The new agreements permit the steam suppliers to furnish lower pressure steam and require that they make payments to the Company to compensate for the declining steam supply to the Company's units.
WESTERN SYSTEMS POWER POOL
In 1991, the FERC approved an agreement among 40 utilities (including the Company) operating in 22 states and British Columbia for a permanent Western Systems Power Pool (WSPP). The entities participating in the WSPP may, on a voluntary basis, buy and sell surplus power and transmission capacity by posting quotes daily on a computer "bulletin board." The prices are negotiable but cannot exceed ceilings approved by the FERC. The permanent WSPP agreement approved by the FERC, among other things, imposes cost-based ceilings calculated from pool-wide average costs and allows QFs to participate in the pool if they waive their rights under PURPA to be paid avoided cost prices for transactions performed within the pool. The FERC order approving the permanent WSPP agreement was challenged in the U.S. Court of Appeals for the District of Columbia Circuit on the basis that the cost-based ceilings were improperly calculated and that the FERC exceeded its authority in conditioning QF participation in the pool. The Court of Appeals affirmed the FERC's authority to set cost-based ceilings and, at the request of the FERC, remanded the QF participation issues to the FERC for further consideration. In February 1994, the FERC ordered WSPP to permit QFs to participate on the same basis as other members without being required to waive their rights under PURPA.
ELECTRIC TRANSMISSION POLICIES
Beginning in 1993, the FERC implemented the Energy Act by establishing a number of policies with respect to transmission service, transmission pricing and Regional Transmission Groups (RTGs).
TRANSMISSION ACCESS AND PRICING
In 1993, the FERC held that eligible entities were entitled to receive network transmission service unless the transmitting utility was unable to provide it. Eligible entities under the Energy Act include electric utilities, federal power marketing agencies or any entity generating power for resale. Network transmission service generally involves delivery from multiple generators to multiple loads for a single charge. The FERC later held that network service could be priced based on the ratio of the load served by the network service to the entire load served by the transmitting utility's transmission system.
In 1994, the FERC held that any utility providing service under an open-access transmission tariff (i.e., a filed tariff offering transmission service at specified rates and terms to all eligible entities) must provide transmission service to transmission customers on the same basis on which the utility provides transmission service to its own customers. This means the service must be comparable in terms of price, in terms of quality,
and with respect to all the uses the transmitting utility makes of its own transmission system. The Company currently intends to file an open-access tariff by May 1, 1995.
In October 1994, the FERC issued a policy statement on transmission pricing. The new policy permits increased flexibility in transmission pricing methodology and rate design in instances where the transmitting utility is basing rates on a traditional embedded cost revenue requirement. In return utilities must meet the comparability of service standard described above. The FERC will also consider deviations from embedded cost revenues, but only from entities which have already filed open-access comparable service transmission tariffs. The FERC regards market-based pricing for transmission as disfavored, believing transmission to be a monopoly.
Consistent with the intent of the Energy Act to promote competition in the wholesale power markets through increasing transmission access, in December 1994, the Company filed with the FERC for its approval an agreement to provide network transmission service to a power marketer, Destec Power Services (DPS). Under this agreement, the Company will provide flexible wholesale network transmission from generators who market their power through DPS. Many of these generators will be QFs which already have power purchase agreements to sell to the Company, but which have surplus power not covered by such agreements which can be marketed by DPS. The FERC is expected to act on the DPS agreement shortly. In March 1995, the Company entered into a similar agreement with another marketer, Power Exchange Corp. (PXC), which agreement has been filed with the FERC for approval. The services and rates under the PXC agreement are identical to those in the DPS agreement. However, the Company will provide transmission service under the PXC Agreement only for power bought or sold by PXC under contracts entered into before such time as the Company's open-access tariff has been filed and effective for two years. For all power contracts PXC enters into after that date, it must rely on transmission service under the Company's open-access tariff.
REGIONAL TRANSMISSION GROUPS
In 1993, the FERC issued a policy statement on RTGs, voluntary associations of transmission owners and wholesale transmission users, that would facilitate transmission access, coordinate transmission planning, and resolve disputes. In May 1994, the Western Regional Transmission Association (WRTA) became the first RTG to file its governing agreement at the FERC. The Company was one of the founding members of WRTA and supported FERC's approval of the bylaws. The FERC conditionally accepted the WRTA bylaws, but added two requirements. First, the FERC required either WRTA itself or all WRTA members to file comparable service open access tariffs providing transmission service to all other members. Second, the FERC required WRTA to file a single coordinated regional transmission plan and to update that plan as necessary. WRTA has filed a revised set of bylaws essentially accepting those conditions, which FERC will rule on within the next few months.
STRANDED COSTS RULEMAKING
In June 1994, the FERC issued a Notice of Proposed Rulemaking relating to stranded costs. These are fixed costs (typically for generation) which a utility may be unable to recover because of customers leaving the system. The proposed rules cover stranded costs for wholesale transactions and propose in the alternative either no role for FERC regarding retail stranded costs or only a limited role. A decision is expected sometime in 1995.
CPUC TRANSMISSION POLICIES
In September 1990, the CPUC issued an order instituting investigation into the development of transmission policies for (i) transmission access and allocation of transmission costs for a utility buying non-utility power; and (ii) transmission access, cost allocation and pricing issues for non-utility power producers who require transmission-only service from a utility. In September 1992, the CPUC issued a decision in the first phase of the investigation. The decision adopted certain policies and procedures on an interim basis which permit the Company to consider the expected transmission impacts of non-utility power purchases as it selects new QF resources through a competitive bidding process. Among other things, the decision provided that ratepayers, as opposed to utility shareholders, will bear prudently incurred costs of the most cost-effective transmission upgrades necessary to accommodate purchases from winning bidders. The recent BRPU
solicitation proceeded under these rules and enabled bidders in one utility's service territory to bid into another utility's auction.
A second phase of the investigation to consider certain broader long-term transmission access and cost issues is currently on hold pending the outcome of the CPUC's electric industry restructuring OIR/OII.
ELECTRIC REASONABLENESS PROCEEDING
Recovery of costs through the ECAC are subject to a CPUC determination that such costs were incurred reasonably. Under the current regulatory framework, annual reasonableness proceedings are conducted on a historic calendar year basis.
In August 1993, the DRA filed a report on the Company's ECAC expenses for the 1991 record period, which questioned the Company's execution of amendments to three power purchase agreements with Texaco, Inc. for three QFs. In its report and in testimony filed in February 1994, the DRA asserted that the Company improperly agreed to extend the construction time under these agreements and recommended that the CPUC find these extensions unreasonable. Although no payments are at issue in the 1991 record period, the DRA argues that certain capacity payments under the contracts should be disallowed in subsequent year proceedings over the 15-year term of the contracts. In its August 1993 report, the DRA indicated that this disallowance over the 15-year term of the contracts would approximate $80 million. In its report on ECAC expenses for the 1992 and 1993 record periods, the DRA recommended disallowances of approximately $3.5 million and $3.0 million, respectively, for two of these agreements.
HELMS PUMPED STORAGE PLANT
Helms, 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, became commercially operable in June 1984. As a result of the damage caused by the rupture and the delay in the operational date, the Company incurred additional costs which are not yet included in rate base and lost revenues during the period the plant was under repair. Excluding the costs of the conduit rupture already reserved by the Company and the amount received in settlement of litigation with the supplier of the plant's generators, the remaining unrecovered costs of Helms (after adjustment for depreciation) and revenues discussed above totaled approximately $104 million at December 31, 1994.
In October 1994, the Company and the DRA filed a joint motion seeking CPUC approval of a proposed all-parties settlement (Helms Settlement) resolving the treatment of remaining unrecovered Helms costs. The Helms Settlement would permit recovery of $48.9 million of Helms plant costs and $14.6 million of prior revenue requirements to be included in the Company's rate base on January 1, 1995. However, in connection with the Company's rate freeze for 1995, the revenue requirement for 1995 would not increase, as a result of other unrelated base revenue reductions. An additional amount of $35.3 million, representing revenues lost during the time the generators were being repaired, would be transferred to the ERAM account and amortized over the life of Helms, to 2034. Under the Helms Settlement, the Company would also agree not to seek recovery of the costs associated with the 1982 water conduit rupture, estimated to be $72.4 million. The Company took a charge against earnings for such costs in 1990.
As noted above (see "General -- 1995 Revenue Changes"), in December 1994, the CPUC issued a resolution authorizing the Company to implement an ARA to keep the Company's retail electric rates unchanged through 1995. In its resolution, the CPUC adopted the revenue requirement increase of approximately $12 million that is contemplated by the Helms Settlement, and authorized a decrease in base revenues. The CPUC also authorized the collection in 1995 of $2 million as part of the amortization through ERAM of revenues lost during the time the generators were being repaired. The CPUC noted that because the Helms Settlement is still pending before the CPUC, the amount adopted in the resolution may be subject to further adjustment depending upon the final decision in the Helms proceeding.
GAS UTILITY OPERATIONS
GAS OPERATIONS
The Company owns and operates an integrated gas transmission, storage and distribution system in California. At December 31, 1994, the Company's "vintage" system consisted of approximately 5,300 miles of transmission pipelines, three gas storage facilities and approximately 35,400 miles of gas distribution lines. In addition, in November 1993, the Company placed in service a third transmission pipeline of approximately 400 miles (Line 401) as the in-state portion of the PGT/PG&E Pipeline Expansion. See "PGT/PG&E Pipeline Expansion Project" below.
The Company's peak day send-out of gas on its integrated system in California during the year ended December 31, 1994 was 3,801 million cubic feet (MMcf). The total volume of gas throughput during 1994 was approximately 948,000 MMcf, of which 307,000 MMcf was sold to direct end-use or resale customers, 298,000 MMcf was transported by PG&E for its fossil-fueled electric generating plants, and 343,000 MMcf was transported customer-owned gas.
The California Gas Report, which presents the outlook for natural gas requirements and supplies for the State of California through the year 2010, is prepared annually by the California electric and gas utilities as a result of a CPUC order. The 1994 report forecasts the Company's gas demand from 1994 through 2010. (Beginning in 1996, the report will be issued biennially.)
The 1994 report forecasts growth in gas throughput served by the Company of 1.4% per year from 1994 through 2010. While this is a lower growth rate than the 1.8% shown for the same period in last year's forecast, most of the difference is due to higher power plant gas demand in 1994 than previously forecasted, as a result of lower than expected rainfall. Much of the forecasted growth in gas demand, outside of utility electric generation, is related to a more optimistic forecast of industrial output in the service territory and expected growth in the use of natural gas vehicles as a result of the Company's natural gas vehicle programs and state and federal clean air regulations.
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, have the ability to purchase gas directly from gas producers, using unregulated private pipelines or interstate pipelines, bypassing the Company's system entirely. The report forecasts a total bypass volume of 126 billion cubic feet for 1994. The forecast assumes that bypass which began in 1991 will change little from the 1994 level and does not include any potential bypass from the proposed Mojave Pipeline Company expansion project. See "Other Competitive Pipeline Projects" below.
GAS OPERATING STATISTICS
The following table shows the Company'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, the Company implemented its CIG program. Sales included approximately 105,000 MMcf, 130,000 MMcf and 50,000 MMcf in 1993, 1992 and 1991, respectively, of gas procured by the Company 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 in-state portion of the Pipeline Expansion of 79,749 MMcf and 7,205 MMcf for 1994 and 1993, respectively.
(4) Includes gas transportation revenues from PGT and oil and gas revenues from Enterprises.
- ------------
(1) Over 100% indicates colder than normal.
NATURAL GAS SUPPLIES
The objective of the Company's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs and fosters competition among suppliers.
Under current CPUC regulations, the Company purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual and operational constraints. During the year ended December 31, 1994, approximately 53% of the Company's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by PGT, a wholly owned subsidiary of the Company, approximately 5% was purchased from various California producers, and approximately 42% was purchased from other states (substantially all U.S. Southwest sources and transported by El Paso Natural Gas Company (El Paso) or Transwestern Pipeline Company (Transwestern)). The following table shows the volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by the Company from these sources during each of the last five years.
- ----------
(1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges and other pipeline assessments, including direct bills allocated over the quantities received at the California border. The average prices for California gas include only commodity gas prices delivered to the Company'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 noncore customers and some core customers to purchase gas directly from producers, aggregators or marketers, and separately negotiate gas transportation with their utilities; and (iv) places the utilities at risk for collecting a portion of the transportation revenues associated with their noncore markets. Under the CPUC's capacity brokering program implemented in 1993, the Company is required to make available for brokering all interstate pipeline capacity not reserved for its core customers and core subscription customers. Noncore customers, marketers and shippers, and the Company's electric department can bid for such capacity.
In addition, in April 1992, the FERC issued its Order 636, which required interstate pipelines to unbundle sales services from transportation services, established various programs providing for reallocation of
pipeline capacity and adopted various mechanisms by which pipelines may recover transition costs arising from the restructuring of their services. Under the Order 636 capacity allocation rules, firm capacity holders were permitted to exercise a one-time opportunity to "relinquish," i.e., permanently abandon, some or all of their transportation capacity, either by paying a negotiated exit fee or through a third party assuming the obligations of the existing transportation agreement. Thereafter, firm capacity holders may also "release" some or all of their capacity, i.e., give up capacity rights to third parties for a limited period of time. Releasing capacity holders remain liable on their existing contracts, but will receive a credit for the acquiring third parties' demand charge payments, the amounts of which will depend on the percentage of full rate paid by the acquiring third party.
The Company's compliance with these regulatory changes allowed many of the Company's noncore customers to arrange for the purchase and transportation of their own gas supplies. These changes resulted in a decrease in the amount of gas required to be purchased by the Company and a related decrease in the Company's need for firm transportation capacity, and contributed to the need to restructure the Company's gas supply arrangements.
RESTRUCTURING OF CANADIAN GAS SUPPLY ARRANGEMENTS
DECONTRACTING PLAN
Until November 1993, PG&E purchased Canadian natural gas from PGT, which in turn purchased such gas from Alberta and Southern Gas Co. Ltd. (A&S), a wholly owned subsidiary of PG&E. A&S had commitments to purchase minimum quantities of gas from Canadian producers under various contracts, most of which extended through 2005. As a result of the regulatory restructuring discussed above, negotiations were conducted to terminate A&S's contracts with Canadian gas producers, restructure A&S's contracts with Canadian pipelines and gas processors and settle all litigation and claims arising from such contracts. Those negotiations resulted in the implementation of a Decontracting Plan, effective November 1, 1993. Approximately 190 Canadian gas producers representing nearly 100% of the total volume of the gas supply of A&S participated in the Decontracting Plan.
Under the Decontracting Plan, the Canadian producers' contracts with A&S, the sales agreement between A&S and PGT, and PG&E's service agreement with PGT each were terminated, effective on November 1, 1993. Participating producers released A&S, PGT and PG&E from any claims they may have had that resulted from the termination of the former arrangements as well as any prior claims related to these contracts. The total amount of settlement payments paid to the producers was approximately $210 million.
As part of the overall A&S decontracting process, A&S' operations have been significantly reduced. A&S permanently assigned substantial portions of its commitments for transportation capacity with NOVA Corporation of Alberta (NOVA) through October 2001 and Alberta Natural Gas Company Ltd (ANG) through October 2005 to third parties and approximately 600 MMcf per day (MMcf/d) of capacity on each of these pipelines to PG&E for use in the servicing of PG&E's core and core subscription customers. A&S currently holds remaining capacity of approximately 300 MMcf/d on each of these pipelines with total annual demand charges of approximately $15 million for which it is continuing its efforts to assign or broker. It is currently anticipated that A&S will complete the permanent assignment to others of substantially all of its NOVA and ANG capacity by November 1995.
The FERC has approved a transition cost recovery mechanism (TCRM) for PGT under which most costs which were incurred to restructure, reform or terminate the sales arrangements between A&S and PGT and underlying A&S gas supply contracts, or to resolve claims by gas suppliers related to past or future liabilities or obligations of PGT or A&S, are eligible for recovery in PGT's rates. Under the TCRM (1) 25% of such costs are absorbed by PGT; (2) 25% are recovered by PGT through direct bills (substantially all to PG&E as PGT's principal customer); and (3) 50% are recovered by PGT through volumetric surcharges over a three-year period. Costs associated with A&S's commitments for Canadian pipeline capacity do not qualify as transition costs recoverable under this mechanism.
In May 1994, the FERC approved PGT's application seeking recovery of $154 million under the TCRM, which is 75% of the $206 million in estimated settlement payments expected to be paid to Canadian gas producers as of the time PGT filed its application. PGT has also sought recovery of an additional $14 million under the TCRM. This amount represents 75% of additional settlement payments to producers and certain costs related to A&S' wind-down of its gas aggregation and supply business as a result of the decontracting process. In February 1995, the FERC held that this amount was eligible for recovery under the TCRM. The CPUC and other parties have until April 3, 1995 to challenge the prudency of this amount. If no such challenge is made, the amount will be recovered under the TCRM.
In November 1993, PG&E paid PGT approximately $51 million in payment of a direct bill charged by PGT for transition costs under the TCRM. PG&E sought recovery in its most recent BCAP application of this amount and the volumetric surcharges to be billed to PG&E. As part of proposed gas settlement agreements discussed below (see "Gas Reasonableness Proceedings -- Proposed Gas Settlements"), the DRA has agreed that it will not seek any disallowance relating to costs incurred by PG&E in connection with its Canadian restructuring/decontracting activities once those costs are approved by the FERC.
FINANCIAL IMPACT OF DECONTRACTING PLAN AND LITIGATION
The Company incurred transition costs of $228 million in 1993, consisting of settlement payments made to producers in connection with the implementation of the Decontracting Plan and amounts incurred by A&S in reducing certain administrative and general functions resulting from the restructuring. Of these costs, the Company deferred $143 million for future rate recovery. In addition, the Company recorded a reserve of $31 million in 1993 related to A&S's remaining commitments for Canadian transportation capacity. Accordingly, the Company expensed $93 million in 1993 and a total of $23 million in prior years.
RESTRUCTURING OF INTERSTATE GAS SUPPLY ARRANGEMENTS
CURRENT GAS TRANSPORTATION AND PROCUREMENT ARRANGEMENTS
The Company's firm transportation agreement with PGT for up to 1,066 MMcf/d runs through October 31, 2005. The Company's firm transportation agreement with El Paso for up to 1,140 MMcf/d runs through December 31, 1997. The agreements include provisions for fixed demand charges for reserving firm capacity on the pipelines. The firm transportation reservation charges associated with the Company's firm capacity on PGT and El Paso are approximately $50 million and $130 million per year, respectively.
In April 1992, the Company executed firm transportation agreements with Transwestern to transport 200 MMcf/d of San Juan basin gas supplies into the Company's southern gas system, of which approximately 150 MMcf/d is to be used to meet the Company's gas sales demands and approximately 50 MMcf/d is for use by the Company's electric department. The demand charges associated with the entire Transwestern capacity are currently approximately $30 million per year.
RECOVERY OF INTERSTATE TRANSPORTATION DEMAND CHARGES
Pursuant to FERC rules on capacity relinquishment and release and the CPUC's capacity brokering program, the Company retained approximately 600 MMcf/d on each of the PGT and El Paso systems to support its core and core subscription customers and made amounts not needed to support such customers available for capacity release and brokering to other potential shippers beginning in 1993. Under the CPUC's capacity brokering program, noncore customers, or their gas suppliers, are able to make firm interstate transportation arrangements to deliver gas at the Company's interconnections with the interstate pipelines.
The Company has permanently assigned portions of the capacity it no longer uses and is continuing its efforts to assign or broker the remaining unused capacity. During 1994, the Company has been able to broker a portion of its unused capacity, including limited amounts of that held for its core and core subscription customers when such capacity was not being used. Amounts brokered have generally been on a short-term basis, most of which were at a discounted price. Based on the current demand for Canadian gas, the Company believes it will be able to broker or assign substantially all of its unused capacity on PGT by the end of 1995; however, due to lower demand for Southwest pipeline capacity, the Company cannot predict the volume or price of the capacity on El Paso and Transwestern that will be brokered or assigned.
Interstate transportation capacity which cannot be marketed at the full rate results in unrecovered demand charges. Under the CPUC brokering rules, the CPUC has authorized the use of the ITCS to account for unrecovered demand charges associated with interstate pipeline obligations in existence at the time the decision creating the ITCS was issued in November 1991. To the extent the Company is unable to broker its firm interstate capacity above core and core subscription reservations at the full as-billed rate, or to broker such capacity at all, the Company has been authorized to accumulate unrecovered demand charges for El Paso and PGT in the ITCS account for later review and allocation among customer classes.
Ultimate recovery of unrecovered interstate pipeline demand charges accumulated in the ITCS will be subject to CPUC reasonableness review. There may be instances where the CPUC may not allow full recovery with respect to discounted rates, such as rates given to a customer in a negotiated discount gas transportation contract entered into pursuant to the Company's EAD procedure. The CPUC has indicated that if an EAD rate discount results in a shortfall in recovery of ITCS costs contained in the otherwise applicable tariff rate, the Company will not recover those ITCS costs from other customers.
In November 1994, the CPUC issued a decision on the Company's application seeking recovery of amounts accumulated in the ITCS. The Company's application sought to have $60.7 million, which represents the revenue requirement for the estimated amount accrued in the ITCS account for the period August 1, 1993 through August 31, 1994, recovered in noncore rates over a 12-month period beginning September 1, 1994. In its decision, the CPUC indicated that it did not have a sufficient record to resolve contested issues regarding the total amount of the Company's unrecovered costs of interstate pipeline capacity to allocate to noncore customers. However, citing the fact that legitimate unrecovered costs continue to accrue at a substantial rate, the decision authorized the Company to increase rates to all noncore customers on December 1, 1994 through a rate designed to collect approximately one-half of the accumulated demand charges for unbrokered or discounted capacity on an interim basis, subject to refund should ITCS costs prove to have been caused by improper acts of the Company. (This amount was included in the rate adjustments effected January 1, 1995. See "General -- Current Rate Proceedings -- 1995 Revenue Changes" above.) The CPUC also set the matter for hearing at the earliest practicable date to consider protests filed by El Paso. El Paso contends that the Company is inducing customers to move from the El Paso pipeline system to the Company's Pipeline Expansion by discounting rates on the Pipeline Expansion and recouping those discounts through the ITCS. The Company expects to seek recovery of the balance of the ITCS amounts originally sought in the hearing on this matter, which is scheduled for September 1995.
Currently, the Company is not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account. The Company is authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings, which are currently under way.
In January 1994, the DRA issued its report on the reasonableness of the Company's gas procurement and operating activities for the 1992 record period. In its report, the DRA argued that the Company imprudently entered into firm transportation agreements with Transwestern in 1992 and recommended a disallowance of the associated demand charges of approximately $18 million paid by the Company during the record period, of which $4.5 million related to capacity for the Company's electric department. The DRA asserted that the Transwestern capacity was unnecessary to meet the expected needs of the Company's core customers and that the Company should not have contracted for such capacity. Hearings on this issue were concluded in January 1995, with a decision expected in late 1995.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through the Company'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 the Company's Canadian gas procurement activities during 1988 through 1990. The CPUC found that the Company could have saved its customers money if it had bargained more aggressively with its existing Canadian suppliers or bought cheaper gas from other Canadian sources. The CPUC concluded that it was appropriate for the Company to take a substantial portion (up to 700 MMcf/d) of its Canadian gas at its then-existing price, but that the Company could have met the remainder of its demand for Canadian gas at lower prices, either from the same suppliers or with purchases from other available Canadian natural gas sources. The decision orders a disallowance of $90 million of gas costs, plus accrued interest estimated at approximately $25 million through December 31, 1993. The CPUC also issued a final decision on the Company's non-Canadian gas operations during 1988 through 1990, ordering a disallowance of $8 million.
The Company filed a request for rehearing of the CPUC's decision ordering a disallowance in connection with the Company's Canadian gas procurement activities in 1988-1990, which was denied in November 1994. In December 1994, the Company 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 the Company's rights under the United States Constitution. The complaint seeks injunctive and declaratory relief.
PROPOSED GAS SETTLEMENTS
A number of other reasonableness issues related to the Company's gas procurement practices and supply operations for periods dating from 1988 through 1994 are still under review by the CPUC. The DRA recommended disallowances of $142 million and a penalty of $50 million and indicated that it was considering additional recommendations for pending issues. The Company and the DRA have signed settlement agreements to resolve most of these issues for a $68 million disallowance.
Significant issues covered by the gas settlement agreements include (i) the Company's purchases of Canadian, Southwest and California gas for its electric department in 1991 and 1992 and its core customers from 1991 through May 1994; (ii) issues not related to gas procurement which arise from the DRA's investigation of A&S, and the proposed investigation of ANG, a former affiliate of the Company, for the period 1988 through May 1994; (iii) the effects the Company's Canadian gas procurement costs may have had on amounts paid by the Company for Northwest power purchases for 1988 through 1992 and for power purchased from geothermal and QF producers during 1991 and 1992; (iv) the Company's gas storage operations for 1991 and 1992; (v) the Company's Southwest gas procurement activities for 1988 through 1990; and (vi) Canadian gas restructuring transition costs billed to PG&E by PGT through FERC-approved rates.
Agreements with the DRA do not constitute a CPUC decision and are subject to modification by the CPUC in its final decisions. The gas settlement agreements are expressly conditioned upon CPUC approval. Upon such approval, the Company would return approximately $68 million to its ratepayers.
The proposed gas settlement agreements do not resolve issues related to the effect the Company's Canadian gas procurement costs during the 1988 through 1990 period may have had on the price the Company paid to geothermal and QF producers during those years. Hearings on those issues have not yet been scheduled by the CPUC. The proposed gas settlement agreements also do not resolve the reasonableness of the Company's subscription to Transwestern pipeline capacity or the costs accrued in the Company's ITCS account.
FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS
The Company accrued approximately $135 million and $61 million in 1994 and 1993, respectively, for gas reasonableness matters including the CPUC decisions for the years 1988 through 1990 and issues covered by
the gas settlement agreements. The Company believes that the ultimate outcome of these matters will not have a significant impact on its financial position or results of operations.
PGT/PG&E PIPELINE EXPANSION PROJECT
In November 1993, PGT and the Company placed in service an expansion of their natural gas transmission systems from the Canadian border into California (Pipeline Expansion). The 840-mile combined pipeline 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. At December 31, 1994, the Company's total investment in the Pipeline Expansion project was approximately $1,627 million. The $1,627 million consisted of $786 million for the facilities within California (i.e., in-state portion) and $841 million for the facilities outside California (i.e., interstate, or PGT, portion).
The conditions of the CPUC's approval of the construction of the in-state portion of the Pipeline Expansion place the Company at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross- over" ban under which volumes delivered from the incremental PGT portion of the Pipeline Expansion must be transported at an incremental in-state expansion rate. Incremental rate design is based on the concept that expansion shippers, not existing ratepayers, bear the incremental costs of the expansion facilities. Capacity on the PGT portion of the Pipeline Expansion is fully subscribed under long-term firm transportation contracts. However, to date, shippers have only executed long-term firm transportation contracts for approximately 40% of the in-state capacity, and the Company continues negotiations for the remainder of that capacity. The CPUC has authorized the Company to provide as-available service on the in-state portion of the Pipeline Expansion, which provides additional revenues to recover the incremental costs of the expansion.
In February 1994, the CPUC issued a decision on the Company's request for an increase in the cost cap for the in-state portion of the Pipeline Expansion and its interim rate filing. The cost cap represented the maximum amount determined by the CPUC to be reasonable and prudent based on an estimate of the anticipated construction costs at that time. The CPUC granted the Company's request to increase the cost cap to $849 million, but set interim rates based on the original cost cap of $736 million, subject to adjustment within the newly approved cost cap after the outcome of a reasonableness review of capital costs. The CPUC's decision finds that given market conditions at the time, the Company was reasonable in constructing the Pipeline Expansion. The CPUC has denied rehearing of this decision.
In September 1994, the Company filed an application with the CPUC requesting that the CPUC find reasonable the full capital costs of the in-state portion of the Pipeline Expansion (estimated to be $813 million) and its initial operating expenses. The Company's request for a $13 million increase in revenues from the in-state portion of the Pipeline Expansion, compared to rates in effect in 1994, will also be considered in this proceeding. A decision in this proceeding is not expected until 1996.
In its 1991 order approving the PGT portion of the Pipeline Expansion, the FERC concluded that PGT had not sufficiently demonstrated that shippers would not be subject to discriminatory restraints on access into California or on the PGT portion of the Pipeline Expansion as a result of the "cross-over" ban imposed by the CPUC. As a result, the FERC reduced PGT's approved rate of return on equity until such time as PGT demonstrates that neither its rates or transportation policies nor those of the Company result in unduly discriminatory restraints. In March 1994, the FERC allowed PGT to implement, subject to refund, an increase in the nominal return on equity to 12.75%, but reaffirmed the lower 10.13% return on equity it implemented as an incentive for PGT to seek removal of unduly discriminating restraints.
In February 1994, PGT filed a general rate case with the FERC which proposed, among other things, that the lower return on equity imposed by the FERC be removed and PGT be allowed to determine rates for all of its facilities on an equity rate of return of 13%. In March 1994, the FERC approved PGT's proposal to determine rates based on the higher rate of return, subject to refund, pending the outcome of hearings in PGT's rate case, and authorized the rate change to begin in September 1994. Hearings in PGT's rate case are scheduled to begin in April 1995.
The Company believes that resolution of the rate proceedings pending at the CPUC and FERC will not have a significant impact on its financial position or results of operations.
OTHER COMPETITIVE PIPELINE PROJECTS
In March 1993, Mojave Pipeline Company (Mojave), which is a subsidiary of El Paso, filed a request seeking FERC authorization for construction of a 475 MMcf/d transportation-only pipeline expansion of its interstate natural gas pipeline. Mojave indicated that it intends to place the proposed expansion into service by January 1, 1996. The expansion would extend Mojave's system from its current terminus in Bakersfield, California, through California's Central Valley to Sacramento and the San Francisco Bay Area. Mojave's filing indicated that 433 MMcf/d of the firm service capacity provided by the proposed expansion would be provided to customers located in the Company's service territory, with approximately 257 MMcf/d of that amount to be used to provide gas service that currently is not provided by the Company. The remaining 176 MMcf/d represents service to customers currently served by the Company.
In November 1994, the FERC issued an order, approving, with conditions, Mojave's expansion application and granting Mojave a permit to construct, subject to further environmental review. In response to Mojave's original application, the Company had requested that the FERC establish a mechanism to reimburse the Company for costs arising from bypass associated with Mojave's proposed expansion. In its order approving Mojave's expansion, the FERC rejected the Company's claim that the Mojave expansion will result in lost revenues of between $204 million and $223 million. Instead, the FERC estimated the amount would not likely exceed $5 million per year for 15 years. The FERC also rejected the Company's request to be relieved of up to $86 million in charges for El Paso capacity to account for reduced load resulting from Mojave's proposed expansion, concluding instead that such amount could not exceed $19.5 million. The FERC concluded that these costs did not justify rejection of Mojave's application, but it was unable to determine whether and what amount of compensation is owed to the Company by Mojave. The FERC also directed the Company, Mojave and El Paso to provide information explaining whether a connection exists between the Company's obligation to purchase service from El Paso and Mojave's service to the customers Mojave intends to serve within the Company's service territory, and specifying what type and volume of load the Company will lose as a direct result of the bypass by Mojave.
In December 1994, the Company filed its response to the FERC's order. In its response, the Company affirmed that a direct connection exists between the Company's obligation to purchase service from El Paso and Mojave's service to bypassing end users. The Company included a list of current and future natural gas customers that the Company believes might be targeted by Mojave for bypass transportation service. The Company also updated its request for compensation as a result of the Mojave bypass, asking the FERC to relieve the Company of up to $66 million in El Paso capacity charges and require Mojave to pay the Company $135 million in lost revenues associated with the proposed bypass.
In March 1994, the FERC denied several requests for rehearing of its order approving Mojave's expansion. The FERC deferred to a subsequent order consideration of the Company's request for relief from El Paso capacity charges and compensation from Mojave.
The Company also faces competition from various other pipeline projects completed in recent years to serve the enhanced oil recovery market in Southern California and other customers. In 1992, projects sponsored by Mojave and the Kern River Gas Transmission Company commenced commercial operations, and both Transwestern and El Paso put into service expanded pipeline facilities from the San Juan Basin in New Mexico to the California border. These projects provide additional capacity to some of the same markets served by the Pipeline Expansion. Some of the gas available from the U.S. Southwest over these projects is priced equal to or lower than the price of Canadian gas available over the Pipeline Expansion, due in part to federal tax credits available for certain San Juan gas production.
STORAGE SERVICE
The Company has generally provided natural gas storage service only in conjunction with its procurement and transportation services. In February 1993, the CPUC adopted policies and rules for permanent unbundled
gas storage programs for noncore customers, and an unbundled storage program for the Company was approved by the CPUC in May 1994. Storage service for core customers remains bundled with procurement and transportation services.
In September 1994, the Company began offering unbundled storage to noncore customers for varying terms of one year or less. Customers bid to purchase this storage capacity, with available capacity awarded to the highest bids first. To the extent the Company does not recover the full costs allocated to this noncore storage program, the CPUC authorized a Noncore Storage Balancing Account in which these unrecovered costs are accumulated for later review and allocation among customer classes. The CPUC also approved negotiated discounted rates for storage services for noncore customers under certain circumstances, but provided that a portion of any revenue shortfalls attributable to such discounted rates may not be recovered from other customers. To date, the Company has not offered storage service at discounted rates.
DIABLO CANYON
DIABLO CANYON OPERATIONS
Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. As of December 31, 1994, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 78% and 80%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next five years. This schedule 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.
In November 1994, the Nuclear Regulatory Commission's (NRC) Atomic Safety and Licensing Board issued its decision approving the Company's request to change the operating license expiration dates for both units at Diablo Canyon. Diablo Canyon Units 1 and 2 were originally licensed to operate for 40 years commencing on the date the construction permit for the respective unit was issued, which occurred in April 1968 and December 1970, respectively. In 1982, the NRC determined that the 40-year term of operation for nuclear power plants may instead begin upon issuance of the first operating license. License amendments were issued in March 1994 to extend the operating license expiration date for Units 1 and 2 to September 2021 and April 2025, respectively.
DIABLO SETTLEMENT
In December 1994, the Company, the DRA, the California Attorney General and several other parties representing energy consumers agreed to a memorandum of understanding and draft settlement agreement to modify the pricing provisions of the Diablo Settlement. All other terms and conditions of the Settlement Agreement would remain unchanged. The parties have filed the proposed modification with the CPUC and will seek expedited CPUC approval of the proposed change.
Under the proposed modification, the price for power produced by Diablo Canyon would be reduced from the current level and would be as shown in the following table. Based on Diablo Canyon's current operating
performance, the proposed modification would result in approximately $2.1 billion less revenue over the next five years, compared to the original pricing provisions of the Diablo Settlement.
DIABLO CANYON PRICE (CENTS) PER KWH
- --------------- * Assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo Canyon price will increase using the same formula specified in the Diablo Settlement. The proposed modification provides the Company with the right to reduce the price below the amount specified if it so chooses.
The parties to the proposed modification agree that the difference between the Company's revenue requirement under the original terms of the Diablo Settlement and the proposed new prices will be applied to the ECAC balancing account until the ECAC undercollection as of December 31, 1995 (see "General -- Current Rate Proceedings -- 1995 Revenue Changes -- ECAC" above) is fully amortized. As a result, the Diablo Canyon price reductions would help achieve amortization of the ECAC undercollection. In addition, the parties agree that the prices for the period through December 31, 1999 are reasonable and shall be the basis for the recovery of the Company's ECAC revenue requirement pursuant to the pricing of Diablo Canyon power.
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 this "performance based" approach, the Company 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. The Company's earnings are affected directly by plant performance and costs incurred. Earnings relating to Diablo Canyon will fluctuate significantly as a result of refueling or other extended plant outages, plant expenses and the effects of a peak-period pricing mechanism. See "Diablo Canyon Operations" above for the plant refueling schedule.
The settlement decision explicitly affirmed that Diablo Canyon costs and operations no longer should be subject to CPUC reasonableness reviews. The decision states that, to the extent permitted by law, the CPUC intends that this decision be binding upon future Commissions, based upon a determination that taken as a whole the settlement produces a just and reasonable result, and that the settlement has been approved based on the reasonable reliance of the parties and the CPUC that all of the terms and conditions will remain in effect for the full term of the settlement, ending 2016. However, the decision states that the CPUC cannot bind future Commissions in fixing just and reasonable rates for Diablo Canyon.
Under the Diablo Settlement, revenues are based on a pre-established price per kWh consisting of a fixed component (3.15 cents per kWh) and an escalating component for each kWh of electricity generated by the plant. As noted above, the Company has proposed modifying the price for the years 1995 through 1999. After 1999, the escalating component will be adjusted by the change in the consumer price index plus 2.5%, divided by two. During the first 700 hours of full-power operation for each unit during the peak period (10 a.m. to 10 p.m. on weekdays in June through September), the price is 130% of the stated amount to encourage the Company to utilize the plant during the peak period. During the first 700 hours of full-power operation for each unit during the non-peak period of the year, the price is 70% of the stated amount. At all other times, the price is 100% of the stated amount.
If power generation drops below specified capacity levels, the Company may trigger an annual revenue floor provision, or under certain conditions, seek abandonment of the plant (discussed below). Floor payments ensure that the Company will receive some revenue, even if the plant stops producing power. Floor payments
are based on the prices set in the agreement at a 36% capacity factor from 1988 through 1997 (reduced by 3% each time the floor provision is exercised and not repaid) with the capacity factor decreasing in the future. Floor payments must be refunded to customers under specified circumstances.
If actual operation falls below the floor capacity factor in three consecutive years, whether or not the floor payment provision has been triggered, the Company must file for abandonment or explain why continued application of the settlement is appropriate. In the event there is a prolonged plant outage and the Company files for abandonment, the Company may ask for recovery of the lesser of (a) floor payments allowed for ten years, less any years of floor payments already received and not repaid, or (b) $3 billion, reduced by $100 million per year of operation on January 1 of each year starting in 1989.
The Diablo Settlement provides that certain Diablo Canyon costs, including decommissioning costs, be recovered over the term of the Diablo Settlement, including a full return on such costs through base rates.
NUCLEAR FUEL SUPPLY AND DISPOSAL
The Company has purchase contracts for, and an inventory of, uranium concentrates and contracts for conversion of uranium to uranium hexafluoride, uranium enrichment and fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, enrichment services and conversion services will be satisfied through existing long-term contracts through 1998, 1999 and 2001, respectively. The Company is also negotiating contracts for alternative uranium supply and enrichment services through 2002. Fuel fabrication contracts for the two units will supply their requirements for the next five operating cycles for each unit. These contracts are intended to ensure long-term fuel supply, but permit the Company the flexibility to take advantage of short-term supply opportunities. In most cases, the Company's nuclear fuel contracts are requirements-based, with the Company's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear 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 waste. The Nuclear Act sets a national policy for the disposal of nuclear waste from commercial reactors, and establishes a timetable for the DOE to choose one or more sites for the deep underground burial of wastes from nuclear power plants. Under the Nuclear Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Act mandates that one or more such permanent disposal sites be in operation by 1998, although DOE has indicated that such sites may not be in operation until 2010. DOE is also considering providing interim storage in a monitored retrievable storage facility earlier than 2010. However, under DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel is not likely to be accepted by DOE for interim or permanent storage before 2011, at the earliest. At the projected level of operation for Diablo Canyon, the Company's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. In the event an interim or permanent DOE storage facility is not available for Diablo Canyon's spent fuel by 2006, the Company will examine options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. Such additional temporary spent fuel storage may be necessary in order for the Company to continue operating Diablo Canyon beyond approximately 2006, and may require approval by the NRC and other regulatory agencies.
In June 1994, a number of utilities (including the Company), state utility commissions and state attorneys general filed lawsuits seeking declaratory and injunctive relief against the DOE's alleged failure to meet its obligations under the Nuclear Act. Action on the lawsuits has been deferred pending issuance of a DOE policy statement on the same subject.
In July 1988, the NRC gave final approval to the Company's plan to store radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the unit. The license amendment issued by the NRC allows storage of spent fuel rods at Humboldt until a federal repository is established. The Company has agreed to remove all nuclear waste as soon as possible after the federal disposal site is available.
INSURANCE
The Company is 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. If the nuclear plant of a member utility is damaged or increased costs for business interruption are incurred due to a prolonged accidental outage, the Company may be subject to maximum retrospective premium assessments of $28 million (property damage) and $7 million (business interruption), in each case per policy period, if losses exceed premiums, reserves and other resources of NML or NEIL.
The federal government has enacted laws that require all utilities with nuclear generating facilities with a capacity of 100 MW or more to share in payment of claims resulting from a nuclear incident. The Price-Anderson Act limits industry liability for third-party claims resulting from any nuclear incident to $8.9 billion per incident. Coverage of the first $200 million is provided by a pool of commercial insurers. If a nuclear incident results in public liability claims in excess of $200 million, the Company may be assessed up to $159 million per incident with payments in each year limited to a maximum of $20 million per incident; payments in excess are deferred to the next calendar year.
DECOMMISSIONING
The estimated cost of decommissioning the Company's nuclear power facilities is recovered in base rates through an annual allowance. For the year ended December 31, 1994, the amount recovered in rates for decommissioning costs was $54 million. The estimated total obligation for decommissioning costs is approximately $1.1 billion in 1994 dollars (or $4.5 billion in future dollars); this obligation is being recognized ratably over the facilities' lives. This estimate considers the total costs of decommissioning and dismantling plant systems and structures and includes a contingency factor for possible changes in regulatory requirements and waste disposal cost increases.
As of December 31, 1994, the Company had accumulated external trust funds with an estimated fair value of $617 million, based on quoted market prices, to be used for the decommissioning of the Company's nuclear facilities. Corresponding amounts are included in accumulated depreciation and 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.
The CPUC reviews the funding levels for the Company's decommissioning trust in each GRC. Based upon the trust's then-current asset level, and revised earnings and decommissioning cost assumptions, the CPUC may revise the amount of decommissioning costs it has authorized in rates for contribution to the trust. To date the CPUC has not revised the funding levels initially established in 1987. However, to comply with tax law requirements, the Company anticipates that the CPUC will revise the funding levels no later than the 1997 tax year to reflect then-current earnings assumptions and decommissioning cost estimates.
PG&E ENTERPRISES
Enterprises is the parent company established to oversee the Company's unregulated non-utility business activities. Enterprises was established in 1988 and is a wholly owned subsidiary of the Company. Enterprises' activities are conducted through the entities described below.
NON-UTILITY ELECTRIC GENERATION
A wholly owned Enterprises subsidiary is a general partner in U.S. Generating Company (USGen), a California general partnership. A subsidiary of Bechtel Enterprises, Inc., Bechtel Generating Company, Inc., is the other general partner of USGen. USGen develops and manages non-utility electric generation facilities that compete in the U.S. power generation market and sell power to utilities other than the Company. Enterprises' ownership interest in projects developed by USGen varies by project. Profits and losses realized by USGen are distributed in proportion to the partners' relative interests in the project from which those
profits or losses are derived. USGen is currently involved in eight operational plants and five projects under construction. The total generating capacity of these 13 plants is 2,238 MW. Enterprises' share of capacity from those projects is approximately 971 MW. The projects are typically financed with a combination of equity commitments from the project sponsors and non-recourse debt.
In August 1994, USGen negotiated and completed the acquisition of Makowski on behalf of Enterprises and Bechtel Enterprises, Inc. Makowski is a Boston-based company engaged in the development of natural gas-fueled power generation projects and natural gas distribution, supply and underground storage projects. Makowski is currently involved in five operational plants. (USGen is also involved in one of these plants.) With the acquisition of Makowski, Enterprises' affiliates are involved in a total of 12 plants in operation and 5 plants under construction, with total generating capacity of 3,298 MW. Enterprises' share of capacity from all 17 plants is approximately 1,389 MW.
In addition, Enterprises is in the process of forming, in conjunction with Bechtel Enterprises, Inc., a company to develop, build, own and operate international nonutility generation projects.
U.S. Operating Services Company (USOSC), a California general partnership, provides operations and maintenance services for power facilities managed by USGen and to third parties in the independent power production business. An Enterprises subsidiary and a subsidiary of Bechtel Group, Inc. are the general partners of USOSC. Enterprises' economic interest in USOSC projects varies by project.
GAS AND OIL EXPLORATION AND PRODUCTION
DALEN, a wholly owned indirect subsidiary of Enterprises, is engaged in natural gas and oil exploration and production primarily in the Gulf Coast, east Texas, Anadarko and Rocky Mountain regions of the U.S.
In July 1994, the Company approved a plan for the disposition of DALEN through an initial public offering of DALEN's common stock, subject to favorable market conditions. In February 1995, the Company confirmed its intent to sell DALEN in 1995, either through an initial public offering or a private sale. The Company's decision is based upon the Company's determination that oil and gas exploration and production activities do not fit within its revised long-term corporate strategy. In anticipation of the disposition, DALEN entered into multiple contracts in June 1994 to sell $130 million of its oil and gas properties, resulting in a net pretax gain of $2 million. As of December 31, 1994, DALEN had assets of approximately $490 million.
REAL ESTATE DEVELOPMENT
PG&E Properties, Inc. (Properties), a wholly owned subsidiary of Enterprises, develops real estate in the Company's service territory, focusing on residential lot creation. It also develops offices, industrial buildings, retail outlets and apartments.
ENVIRONMENTAL MATTERS AND OTHER REGULATION
ENVIRONMENTAL MATTERS
The Company is 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. The Company has undertaken major compliance efforts with specific emphasis on its purchase, use and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Company's bulk waste handling and storage facilities.
ENVIRONMENTAL PROTECTION MEASURES
The Company's estimated expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. Capital expenditures for environmental protection are currently estimated to be approximately $39 million, $93 million, $85 million, $69 million and $66 million for 1995, 1996, 1997, 1998 and 1999, respectively, and are included in the Company's five-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. In addition, PGT estimates its capital expenditures for environmental protection will be approximately $10 million in 1995, primarily for NOx emission reduction and dry low emission equipment, and approximately $1.8 million in 1996.
Air Quality
The Company'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 the Company operates fossil fuel fired 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 are scheduled to begin in 1996. Certain retrofits will not be required if the smaller generating units are operated for emergency purposes only after 2000. One rule may also require additional expenditures of up to $1.5 million in the San Luis Obispo County Air Pollution Control District, depending on air quality progress in that district. The Company currently estimates that compliance with these NOx rules could require capital expenditures of approximately $300 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 the Company'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 the Company's natural gas compressor stations. The Company currently estimates that the total cost of complying with these rules will be approximately $25 to $55 million over five years.
In the Company's 1993 GRC, the CPUC established an Air Quality Adjustment mechanism under which the Company may seek cost recovery in rates for NOx reduction projects during 1994 and 1995. However, by the time the retrofits are operational, the Company may either be subject to PBR or one of several restructuring proposals currently under consideration by the CPUC. Therefore, the mechanism for ratemaking treatment of these costs is uncertain at this time.
In 1990 Congress passed extensive amendments to the Federal Clean Air Act. The Environmental Protection Agency (EPA) has issued numerous regulations for the implementation of these amendments. The Company is currently assessing the impact of the regulations. Generally, existing or proposed state and local air quality requirements are more stringent than the new federal requirements, which should therefore have little impact on the Company. However, stringent federal air monitoring requirements mandated the installation of monitoring equipment to measure emissions from the fossil fuel fired generating plants. The cost of complying with the monitoring requirements totalled approximately $22 million in 1994.
Water Quality
The Company's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Company's fossil fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and has been reviewed by the Central Coast Regional Water Quality Control Board (Regional Board). The Regional Board has not yet made a final decision on the report and has requested that the Company continue the marine monitoring program. In the event that Diablo Canyon does
not comply with the thermal limitations and in the unlikely event that major modifications are required (e.g., cooling towers), significant additional construction expenditures could be required.
A thermal effects study of the Company's Pittsburg and Contra Costa Power Plants was submitted to the San Francisco and Central Valley Regional Water Quality Control Boards in December 1992. In general, the study found no significant adverse effects associated with the thermal discharge at either plant. Additionally, several fish species listed or proposed for listing as endangered species may be found in the waters near these 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.
Pursuant to the federal Clean Water Act, the Company is required to demonstrate that the location, design, construction and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. The Company has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. However, if in the future there are changes in available technology, these findings are subject to further review by various agencies. Thus, construction expenditures or operational changes may be necessary to meet a more stringent future standard.
Oil Spill Prevention
The Company operates three marine terminals, approximately 92 large aboveground fuel tanks with a capacity of approximately 18 million barrels and approximately 50 miles of fuel pipelines. These facilities are used for the transport, handling and storage of residual fuel oil and diesel fuels, both of which are used at the Company's power plants. The Company continues to assess its need to operate oil handling and storage facilities as part of its efforts to reduce exposure to oil handling risks and operational expenses without sacrificing electric system reliability.
Under the federal Clean Water Act Spill Prevention Control and Countermeasure (SPCC) regulations, many of the Company's power plants, substations and service centers must install and maintain facilities to prevent the release of oil and other hazardous materials to surface waters. Capitalized SPCC project costs for 1995 and 1996 are estimated to be approximately $2 million.
In addition, activities associated with the transport, storage and handling of petroleum products are regulated by the federal Oil Pollution Act of 1990 (OPA) and the California Oil Spill Prevention and Response Act of 1990 (OSPRA). Under these laws, the Company is required to demonstrate $500 million of financial responsibility, which it demonstrates through a combination of insurance and self insurance.
Regulations under OPA and OSPRA require development of Oil Spill Emergency Response Plans utilizing worst case planning scenarios. Plans must include contracting for response resources to respond to the worst case scenarios. The Company is a member of the Clean Bay, Clean Seas and Humboldt Bay oil spill response organizations and the Marine Preservation Association through which it can obtain the services of the Marine Spill Response Corporation, a national oil spill response organization.
Company expenditures to comply with OPA and OSPRA requirements in 1995 and 1996 are estimated to total less than $2 million.
HAZARDOUS MATERIALS AND HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
The Company assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. Generally, these compliance costs are recovered through the GRC process. However, as discussed below, the CPUC has established a separate mechanism for recovery of certain hazardous waste remediation costs.
The EPA, the California Department of Toxic Substances Control (DTSC), and associated regional and local agencies have comprehensive rules which regulate the manufacture, distribution, use and disposal of
polychlorinated biphenyls (PCBs). The Company has established programs and has committed resources to achieve compliance with these rules. In 1982, the EPA adopted new regulations greatly restricting the use of PCBs in electrical equipment. The regulations have resulted in the early retirement and replacement of certain equipment. Since Company operations generate PCB-contaminated waste which requires special handling, the Company has contracted with EPA-approved firms for the disposal or recycling of PCB waste. The Company estimates that PCB disposal will cost approximately $8 million in 1995 and 1996.
The Company has a comprehensive program to comply with the many hazardous waste storage, handling and disposal requirements promulgated by the 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. As part of this general compliance effort, the Company has initiated programs to address three specific environmental issues: (i) wastewater holding ponds, (ii) underground storage tanks, and (iii) historic hazardous waste sites, including former manufactured gas plant sites.
Wastewater evaporation ponds contain materials such as compressor cooling water blowdown from gas compressor stations. The Company has replaced the old ponds with new evaporation ponds that meet new standards for leak monitoring, detection and containment. Capital expenditures for this work in 1995 are estimated to be approximately $0.9 million. Closure and post-closure expenditures for these ponds, including groundwater remediation, health risk assessments and management plans, may approximate $30 million for a 30-year period.
Underground storage tanks are the subject of federal and California regulatory programs directed at identifying and eliminating the possibility of leaks. The Company has approximately 270 underground tanks, some of which must be upgraded to meet new standards. The tanks contain hazardous materials such as gasoline, waste automotive crankcase oil, transformer fluid or oily wastewater. The Company has an ongoing program to improve leak monitoring, test each tank for leakage and, if necessary, sample soil and water from the surrounding area and remediate any contamination detected. Costs for testing, remediation and tank replacement in 1995 and 1996 are estimated to be approximately $4.6 million.
A third 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 plant facilities produced lampblack and tar residues, byproducts of a process that the Company and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Company's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. The Company has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which the Company operated in its service territory. The Company owns all or a portion of 29 of these manufactured gas plant sites. The Company has begun a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which the Company owns. The Company currently estimates that this program may result in expenditures of approximately $30 million over the period 1995 through 1996. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if the Company is found to be responsible for clean up at sites it does not currently own.
Manufactured gas plant sites at which the Company 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. The Company will perform a groundwater remedial action at its former Sacramento manufactured gas plant site during 1995 at a cost of up to $3 million. The DTSC must approve the groundwater remedial action design plan proposed for this site before it is implemented. The Company has accrued a $7.3 million liability at December 31, 1994 for the Sacramento gas plant site.
In addition to the manufactured gas plant sites, the Company may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the
environment because of an actual or potential release of hazardous substances. The Company has been designated as a PRP under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales site is a former used oil recycling facility at which the Company is one of nine PRPs named in an EPA order requiring groundwater remediation at the site. The Company has also entered into an Administrative Order with the EPA to address soil contamination at the site. The Company has accrued a $6.4 million liability at December 31, 1994 for the Purity Oil Sales site. Although the Company has not been named as a PRP with respect to the Casmalia site near Santa Maria, California, the EPA has notified the Company and approximately 65 other generators who allegedly sent the largest volumes of waste to the site that action is needed to clean up and close the site. The Company is working with other alleged generators to evaluate measures which may need to be taken at the site. The Company has accrued a $1.9 million liability for the Casmalia site. Although the Company has not been formally designated a PRP with respect to the Geothermal Industries, Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed the Company and other parties to initiate measures with respect to the study and remediation of that site. The Company has accrued a liability of $9.8 million for the Geothermal Industries, Incorporated site.
In addition to the sites discussed above, the Company 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. The Company has also received a demand from the California Attorney General seeking reimbursement of cleanup costs incurred by the State of California at the Company's former Jibboom Street power plant in Sacramento, California. In addition, the Company has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Company is responsible for performing or paying for remedial action at sites the Company no longer owns or never owned.
The overall costs of the hazardous materials and hazardous waste compliance and remediation activities described above are difficult to estimate due to uncertainty concerning the extent of environmental risks and the Company's responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. However, based on the information currently available, the Company has an accrued liability as of December 31, 1994 of $95 million for hazardous waste remediation costs. The ultimate amount of such costs may be as much as $235 million if, among other things, the Company is held responsible for cleanup at additional sites, other PRPs are not financially able to contribute to these costs, or further investigation indicates that the extent of contamination and affected natural resources is greater than anticipated at sites for which the Company is responsible.
Potential Recovery of Hazardous Waste Compliance and Remediation Costs
In May 1994, the CPUC issued a decision in the Southern California Gas Company's (SoCal Gas) environmental reasonableness proceeding. The final decision adopts the settlement and proposed ratemaking mechanism for hazardous waste remediation costs which was previously submitted by the Company and other interested parties. 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. The mechanism provides that 70% of the ratepayer portion of the Company's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. The Company can seek to recover hazardous substance cleanup costs under the new mechanism in any rate proceeding it deems most appropriate.
The final decision in the SoCal Gas proceeding permits the Company to seek recovery under the new mechanism of environmental cleanup costs previously recorded in balancing accounts under the old recovery mechanism. Accordingly, in its 1995 BCAP, the Company is seeking recovery of $10.5 million in environmental cleanup costs under the new mechanism, which amount represents the gas department's allocation of such previously recorded cleanup costs.
To the extent that hazardous waste compliance and remediation costs are not recovered through insurance or by other means, the Company may apply for recovery through ratemaking procedures established by the CPUC and, assuming continuation of these procedures, expects that most prudently incurred hazardous waste compliance and remediation costs will be recovered through rates. As of December 31, 1994, the Company has a deferred charge of $83 million for hazardous waste remediation costs, which represents the minimum amount of such costs expected to be recovered under the current ratemaking mechanisms. The Company believes that the ultimate outcome of these matters will not have a significant adverse impact on its financial position or results of operations.
In December 1992, the Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Company 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, the Company's carriers neither admitted nor denied coverage, but requested additional information from the Company. The amount of recovery from insurance coverage, if any, cannot be quantified at this time.
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 Commission 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.
The CPUC proceeding was subsequently bifurcated into two phases -- one focusing on EMF related to electric power and the other on EMF generated by cellular telephone transmitters. In the electric power phase, 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 will be 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 over the next four years.
As part of its effort to educate the public about EMF, the Company provides interested customers with information regarding the EMF exposure issue. The Company also provides a free field measurement service to its customers which informs customers about EMF levels at different locations in and around their residences or commercial buildings.
The Company and other utilities are involved in litigation concerning EMFs. The Company is named as a defendant in three pending civil lawsuits. Plaintiffs allege personal injury resulting from exposure to EMFs and diminution in property value due to the presence of EMFs from nearby high voltage lines.
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, the Company may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant depending on the particular mitigation measures undertaken, especially if relocation of existing power lines is ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In October 1991, the CPUC issued an Order Instituting Investigation/Order Instituting Rulemaking on Low Emission Vehicles (LEVs) to investigate policy issues surrounding electric and natural gas utility involvement in the market associated with LEVs, specifically natural gas vehicles (NGVs) and electric vehicles (EVs). Hearings in Phase I of the LEV proceeding were conducted in August 1992, and examined long-term utility involvement in LEV programs in relation to California's environmental, energy and
transportation goals. The Company generally proposed that its long-term role in the LEV market be that of a fuel supplier, transporter and distributor.
In July 1993, the CPUC issued a decision in Phase I of the LEV proceeding. The decision recognized a significant role for the Company in the LEV market and directed the Company to file a request for funding for a six-year program (1995-2000). In August 1994, the Company requested approximately $41 million in funding for the Company's fleet and market development activities for NGVs and EVs over the six-year period. Joint hearings on all utilities' LEV funding requests were held in the fall of 1994, with a Phase II decision expected by mid-1995.
As noted above (see "Proposed Regulatory Reforms -- Company's Proposals -- PBR"), the Company proposes to revise its RRI filing to reflect the CPUC's electric industry restructuring plan once the details of the CPUC's plan are sufficiently definitive. The Company anticipates that in its revised filing it will recommend that LEV program costs be funded as part of environmental and social benefit programs generally, with LEV funding included in the rate component related to such programs.
The decision in the Company's 1993 GRC extended NGV funding of $8.5 million per year pending a final decision in the LEV proceeding described above, and authorized $1.8 million for EV programs. The Company is using the NGV funds to install additional natural gas refueling facilities, to purchase or convert additional NGVs for the Company's fleet, and to provide incentives and assistance in converting additional customer vehicles to NGVs. The Company and its customers currently operate nearly 2,700 NGVs.
OTHER REGULATION
CALIFORNIA PUBLIC UTILITIES COMMISSION
In addition to its jurisdiction over rate matters, the CPUC has the authority, among other things, to establish rules and conditions of service, to authorize disposition of utility property, to establish rules and policies governing utility facilities, to regulate securities issues, to prescribe rates of depreciation and uniform systems of accounts and to regulate transactions between the Company and its subsidiaries and affiliates.
CALIFORNIA ENERGY COMMISSION
The Company also is subject to the jurisdiction of the CEC. The CEC has developed programs for forecasting peak demands and energy requirements, is encouraging and requiring certain types of energy conservation, has developed energy shortage and contingency plans, and is developing and coordinating a program of energy research and development. In addition, the CEC has statutory authority to certify future thermal-electric power plant sites and related facilities 50 MW and above within California. The Governor of California is currently in the process of submitting to the California State Legislature a plan to reorganize the CEC. Under that plan, the CEC would be consolidated into the existing Department of Conservation to create a new Department of Energy and Conservation, the head of which would be appointed by the Governor.
FEDERAL ENERGY REGULATORY COMMISSION
The Company is subject to regulation by the FERC under the Federal Power Act as a "public utility" as defined in the Act. The FERC has authority, among other things, to regulate the Company's rates and terms and conditions for sales of electricity for resale and transmission of electricity in interstate commerce, and to prescribe rates of depreciation and uniform systems of accounts. The FERC also regulates the terms and conditions of interstate pipeline transportation service utilized by the Company to transport gas it purchases outside California. In addition, the FERC regulates PGT's rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of PGT's facilities and PGT's accounting, among other things.
FERC-HYDROELECTRIC LICENSING
Most of the Company's hydroelectric facilities are subject to licenses issued under Part I of the Federal Power Act, with various expiration dates to the year 2033 and involving a total normal operating capability of 2,703 MW. Helms adds an additional capacity of 1,212 MW. As the initial licenses for these projects expire,
they become susceptible to competition for a new license. In the years prior to 1986, several governmentally run utilities, claiming a statutory "preference" in their favor superior to the Company, had filed competing applications for four of the Company's projects. Federal legislation enacted in 1986 eliminated any preference for governmentally run utilities in hydroelectric relicensing proceedings commenced after 1986.
The 1986 law provided options for resolving relicensing competitions. The Company elected to pay the competing applicants for the four projects a "reasonable" settlement consisting of their costs incurred to pursue the licenses and a potential additional amount ranging from 0% to 100% of the Company's remaining net investment in the relevant project. In return, the competing applicants are required to withdraw their competing license applications. The FERC approved the settlement agreement for two projects. In October 1992, the FERC issued an order requiring the Company to pay compensation of $1.9 million to the competing applicants for the remaining two projects, representing the costs incurred preparing their applications. The FERC declined to award the competing applicants any additional compensation. In December 1993, the Company paid the amount called for in the FERC order, and in October 1994, the U.S. Court of Appeals affirmed that order. The Company expects to recover the costs of all FERC-awarded compensation through rates.
NUCLEAR REGULATORY COMMISSION
The Company also is subject to the jurisdiction of the NRC as to operation of its nuclear generating plants.
ITEM 2.
ITEM 2. PROPERTIES.
Information concerning the Company's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of the Company are subject to the lien of an indenture which provides security to the holders of the Company'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, the Company 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 the Company, filed a complaint in the U.S. District Court, Eastern District of California, against the Company and PGT, on behalf of themselves and purportedly as a class action on behalf of all natural gas customers of the Company during the period of February 1988 through October 1993. The complaint alleges that the purchase of natural gas in Canada was accomplished in violation of various antitrust laws which resulted in increased prices of natural gas for the Company's customers.
The complaint alleges that the Company could have purchased as much as 50% of the Canadian gas on the spot market instead of relying on long-term contracts and that the damage to the class members is at least as much as the price differential multiplied by the replacement volume of gas, an amount estimated in the complaint as potentially exceeding $800 million. In addition, the complaint indicates that the damages to the class could include over $150 million paid by the Company to terminate the contracts with the Canadian gas producers in November 1993. The complaint seeks recovery of three times the amount of the actual damages pursuant to the antitrust laws.
In August 1994, the federal district court issued a decision granting the Company's motion to dismiss the federal and state antitrust claims and the state unfair practices claims against the Company and PGT. The only remaining claims did not seek monetary damages. In addition, the Court granted plaintiffs' motion seeking class certification.
In dismissing the antitrust claims, the Court determined that the prices the Company paid for Canadian gas had been filed with, reviewed and approved as reasonable by various federal and state regulatory authorities, and as a result, the plaintiffs were barred from claiming that those rates were too high. The Court also held that the CPUC's oversight of the Company's gas acquisition costs constitutes state action which immunizes the Company from a private antitrust lawsuit such as this one.
In September 1994, plaintiffs filed an amended complaint with the Court. A&S, the Company's wholly owned Canadian gas purchasing subsidiary, is added as a defendant in the amended complaint. In essence, the amended complaint restates the claims in the original complaint, and in addition alleges that the defendants, through anticompetitive practices, foreclosed access over the PGT pipeline to alternative sources of gas in Canada by certain customers of the Company. A new motion to dismiss was filed by the Company in November 1994.
The Company believes that the ultimate outcome of the antitrust litigation will not have a significant adverse impact on its financial position.
HINKLEY COMPRESSOR STATION LITIGATION
In May 1993, a complaint was filed in San Bernardino County Superior Court on behalf of a number of individuals seeking recovery of an unspecified amount of damages for personal injuries and property damage allegedly suffered as a result of exposure to chromium near the Company's Hinkley Compressor Station, located along the Company's gas transmission system in San Bernardino County, as well as punitive damages. The original complaint has been amended, and additional complaints have been filed, to include additional plaintiffs. The complaints plead several causes of action, including negligence, negligent and intentional misrepresentation, fraudulent concealment, strict liability and violation of California's Safe Drinking Water and Toxic Enforcement Act of 1986 (Proposition 65).
The plaintiffs contend that between 1951 and 1966 the Company discharged Chromium VI-contaminated wastewater into unlined ponds, which led to chromium percolating into the groundwater of surrounding property. The plaintiffs further allege that the Company disposed of the chromium in those ponds to avoid costly alternatives. In 1987, the Company undertook an extensive project to remediate potential groundwater chromium contamination. The Company has incurred substantially all of the costs it currently deems necessary to clean up the affected groundwater contamination. In accordance with the remediation plan approved by the regional water quality board, the Company will continue to monitor the affected area and periodically perform environmental assessments.
The Company has reached an agreement with plaintiffs pursuant to which plaintiffs' actions will be submitted to binding arbitration for resolution of issues concerning the cause and extent of any damages suffered by plaintiffs. Under the terms of the agreement, the Company will pay an aggregate amount of no more than $400 million in settlement of such plaintiffs' claims, including $50 million paid to escrow to date. In turn, those plaintiffs, and their attorneys, agree to indemnify the Company against any additional losses the Company may incur with respect to related claims pursued by the identified plaintiffs who do not agree to this settlement or by other third parties who may be sued by the identified plaintiffs in connection with the alleged chromium contamination.
In January 1995, ten representative cases began arbitration before two judges. At the conclusion of the arbitration, the parties began a process of mediation in an attempt to settle the remaining 625 cases, based on the results of the arbitration. If the mediation is not successful, the parties will proceed to arbitrate another 25 to 30 more cases. Following that, the parties will attempt to mediate the remaining cases. This process will continue until all cases are arbitrated or settled.
As of December 31, 1994, the Company had a remaining reserve of $50 million against any future potential liability in this case. The Company believes the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations.
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 the Company on behalf of themselves and purportedly as a class action on behalf of 47 counties with which the Company has gas or electric franchise contracts. Franchise contracts require the Company 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, the Company 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 the Company 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 the Company.
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 the Company's motion for summary judgment in the class action lawsuit. The plaintiffs may appeal that ruling. Consistent with the agreement between the parties noted above, the plaintiffs refiled a separate action covering just the issue of whether the Company properly computed its franchise payments, assuming that the Company has been using the correct methodology. Plaintiffs have not indicated damages to be sought in that separate action, but they are not anticipated to be material.
Should the counties win the issue of franchise fee calculation methodology, the Company's annual system-wide county franchise fees could increase by approximately $15 million. Damages for alleged underpayments in prior years could be as much as $117 million (exclusive of interest, estimated to be $28 million as of December 31, 1994).
The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations.
CITIES FRANCHISE FEES LITIGATION
On May 13, 1994, the City of Santa Cruz filed a complaint in Santa Cruz County Superior Court against the Company on behalf of itself and purportedly as a class action on behalf of 107 cities with which the Company has certain electric franchise contracts. The complaint alleges that, since at least 1988, the Company has intentionally underpaid its franchise fees to the cities in an unspecified amount.
The complaint alleges that the Company 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 the Company'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 the Company 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. The case is in discovery and no trial date has been set.
Should the cities prevail on the issue of franchise fee calculation methodology, the Company's annual system-wide city electric franchise fees could increase by approximately $17 million. Damages for alleged underpayments in prior years could be as much as $114 million (exclusive of interest, estimated to be $23 million as of December 31, 1994).
The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations.
TIME-OF-USE METER LITIGATION
On July 21, 1994, Milton L. Grinstead, Michael Davis, Joan A. Williamson, Frank H. Lacy, and Matthew Doerksen filed a complaint in the Stanislaus County Superior Court against the Company on behalf of themselves and purportedly as a class action on behalf of all of the Company's customers, for "refund of unlawfully charged fees." The complaint has been amended to broaden the alleged class to include customers of the Turlock Irrigation District (TID), which purchases power from the Company, on the theory that TID customers' rates have been affected by the Company's alleged failure to notify its customers of the best available rate.
The complaint alleges that the Company improperly failed to notify its customers of the most favorable rates available to each particular customer. The complaint focuses on the "time-of-use" billing option, which allows customers to save money by shifting their electricity use to off-peak hours when electricity is cheaper. Plaintiffs contend that all customers could have saved an average of $50-$75 per month per customer had they been placed on time-of-use rates. The complaint seeks damages estimated to be in excess of $16 billion. The amended complaint also includes a claim for $100 billion in "exemplary" damages, alleging that the Company's failure to properly advise customers of the "time-of-use" billing option and other rates was "wilful."
The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations.
NORCEN LITIGATION
On March 17, 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 the Company and PGT. Norcen Marketing signed a 30-year Firm Service Agreement with PGT for transportation of 47,022 million Btus per day (MMBtu/d) on the PGT portion of the Pipeline Expansion. The annual demand charges under the contract currently are approximately $8.1 million. Norcen Energy is a guarantor of the 30-year transportation contract between PGT and Norcen Marketing.
The complaint alleges that PGT and the Company wrongfully induced Norcen Energy and Norcen Marketing to enter into the 30-year contract by concealing legal action taken by the Company 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 further alleges breach of representations to plaintiffs that the Company would not "unreasonably" build its Pipeline Expansion with less than "sufficient" firm subscription. The complaint also alleges breach of an agreement between PGT and a Norcen predecessor named Bonus Gas Processors Corp. (Bonus) relating to the installation of additional capacity. The complaint generally charges the Company with monopolizing the capacity on the original PGT facilities from Kingsgate to Malin and wrongfully preventing Norcen Energy and Norcen Marketing (apparently based on rights allegedly acquired from Bonus) from utilizing the existing PG&E transmission system to provide gas to customers in Northern California.
The complaint alleges various antitrust, contractual, and other claims against the defendants and seeks rescission, restitution and recovery of unspecified damages. In a pleading filed in June 1994, the plaintiffs indicate a claim for $140 million (before trebling) based on defendants' allegedly exclusionary business behavior, as well as an unspecified amount of contract damages. Based on available information, plaintiffs' out-of-pocket contract damages appear to be less than $10 million.
On September 19, 1994, the U.S. District Court, Northern District of California, granted PGT's and the Company's motion to dismiss all federal antitrust claims in the complaint in this case, and dismissed the remaining state antitrust and contract claims for lack of jurisdiction. On October 18, 1994, Norcen 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. On November 18, 1994, PGT and the Company filed motions to dismiss the amended complaint.
The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations.
POTTER VALLEY HYDROELECTRIC PROJECT
On January 19, 1995, the FERC issued a decision finding that the Company had not violated the FERC's April 1994 order relating to a fish screen and bypass facility for the Company's Potter Valley Hydroelectric Project, reversing the compliance order issued by the FERC in September 1994 indicating such a violation had occurred. Accordingly, no fines will be imposed in connection with the matters cited in the September compliance order.
PGT UNIT 4C COMPRESSOR UNIT PERMIT
PGT owns and operates the 4C Solar Mars compressor unit near Sandpoint, Idaho (Unit 4C). In connection with an upgrade of Unit 4C in 1986, PGT applied for and received a construction permit from the State of Idaho Department of Environmental Quality. At the time PGT received the construction permit, it was determined that no permit for the modification was needed under the federal Prevention of Significant Deterioration (PSD) program, then being administered in Idaho by the State.
In the process of applying for a permit under the 1990 Clean Air Act, PGT conducted a review of its environmental permits and discovered information which now causes it to question whether a construction permit incorporating PSD requirements may have been required prior to the 1986 upgrade. PGT is in the process of discussing this information with the State of Idaho. If it is finally determined that such a permit was required, PGT may be required to apply for and obtain a PSD permit for Unit 4C and/or to retrofit Unit 4C. PGT may also be subject to fines and penalties which could exceed $100,000, but it cannot be determined with any certainty at present whether a fine will ultimately be imposed or what the amount of any such fine would be.
The Company believes that the ultimate outcome of this matter will not have a significant 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 the Company are as follows:
All officers serve at the pleasure of the Board of Directors. All executive officers have been employees of the Company for the past five years. In addition to their current positions, the executive officers had the following business experience during that period:
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Information responding to Item 5 is set forth on page 43 under the heading "Quarterly Consolidated Financial Data" in the Company's 1994 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
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 12 under the heading "Selected Financial Data" in the Company's 1994 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 results of operations and liquidity and capital resources is set forth on pages 13 through 20 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the Company's 1994 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 Company's 1994 Annual Report to Shareholders on page 44 and pages 21 through 43 under the headings "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity and Preferred Stock," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data," 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 the Company is included in a separate item captioned "Executive Officers of the Registrant" contained on page 47 in Part I of this report. Other information responding to Item 10 is included on pages 3 through 5 under the heading "Nominees for Director" in the 1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which information is hereby incorporated by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11 is included on page 7 under the heading "Compensation of Directors" and on pages 11 through 18 under the heading "Executive Compensation" in the 1995 Proxy Statement relating to the 1995 Annual Meeting 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 8 and 19 under the headings "Security Ownership of Management" and "Principal Shareholders" in the 1995 Proxy Statement relating to the 1995 Annual Meeting 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 7 under the heading "Certain Relationships and Related Transactions" in the 1995 Proxy Statement relating to the 1995 Annual Meeting 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 1994 Annual Report to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31, 1994, 1993 and 1992.
Consolidated Balance Sheet at December 31, 1994 and 1993.
Statement of Consolidated Cash Flows for the Years Ended December 31, 1994, 1993 and 1992.
Statement of Consolidated Common Stock Equity and Preferred Stock for the Years Ended December 31, 1994, 1993 and 1992.
Statement of Consolidated Capitalization at December 31, 1994 and 1993.
Schedule of Consolidated Segment Information for the Years Ended December 31, 1994, 1993 and 1992.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data.
Report of Independent Public Accountants.
2. Report of Independent Public Accountants.
3. Consolidated financial statement schedules:
II -- Consolidated Valuation and Qualifying Accounts for the Years Ended December 31, 1994, 1993 and 1992.
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.
4. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation effective as of July 26, 1994 (Form 10-Q for quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1).
3.2 By-Laws dated January 1, 1995.
4. First and Refunding Mortgage dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Firm Transportation Service Agreement between the Company and Pacific Gas Transmission Company dated October 26, 1993 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and general terms and conditions.
10.2 Transportation Service Agreement as Amended and Restated Between the Company and El Paso Natural Gas Company dated November 1, 1993 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate schedule T-3, and general terms and conditions.
10.3 Diablo Canyon Settlement Agreement dated June 24, 1988 (Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1), Implementing Agreement dated July 15, 1988 (Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1) and portions of the California Public Utilities Commission Decision No. 88-12-083, dated December 19, 1988, interpreting the Settlement Agreement (Form 10-K for fiscal year 1988 (File No. 1-2348), Exhibit 10.4).
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5).
*10.5 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6).
*10.6 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to non-union employees, as amended September 21, 1994, effective April 1, 1995.
*10.7 Performance Incentive Plan of Pacific Gas and Electric Company (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.10).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended September 21, 1994, effective January 1, 1995.
*10.9 Pacific Gas and Electric Company Supplemental Executive Retirement Plan, as amended through October 16, 1991 (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Stock Option Plan, as amended effective as of September 16, 1992 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.13).
*10.11 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13).
*10.12 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.13 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
- ---------------
* 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.
*10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.18).
*10.16 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.17 Pacific Gas and Electric Company Long-Term Incentive Program (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.21).
11. Computation of Earnings Per Common Share (Form 8-K dated March 2, 1995 (File No. 1-2348), Exhibit 11).
12.1 Restated Computation of Ratios of Earnings to Fixed Charges.
12.2 Restated Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
13. 1994 Annual Report to Shareholders (portions of the 1994 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity and Preferred Stock," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data," included only) (except for those portions which are expressly incorporated herein by reference, such 1994 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein).
21. Subsidiaries of the Company (not included because the Company's subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" under Rule 1-02(v) of Regulation S-X as of the end of the year covered by this report).
23. Consent of Arthur Andersen LLP.
24.1 Resolution of the Board of Directors authorizing the execution of the Form 10-K.
24.2 Powers of Attorney.
27. Financial Data Schedule (Form 8-K dated March 2, 1995 (File No. 102348), Exhibit 27).
99. Information required by Form 11-K with respect to the Savings Fund Plan for Employees of Pacific Gas and Electric Company, as permitted by Rule 15d-21. - --------------- * 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 $.30 per page, which fee covers only the Company's reasonable expenses in furnishing such exhibits.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K during the quarter ended December 31, 1994 and through the date hereof:
1. October 13, 1994
Item 5. Other Events
-- Helms Pumped Storage Plant -- Proposed Settlement
2. October 21, 1994
Item 5. Other Events
-- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case Settlement
-- Performance Incentive Plan -- Year-to-Date Financial Results
3. October 28, 1994
Item 5. Other Events
-- California Public Utilities Commission Proceedings
-- 1995 Cost of Capital Proceeding
-- Long-Term Noncore Gas Transportation Tariff/Gas Transmission Jurisdiction
4. November 17, 1994
Item 5. Other Events
-- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case Settlement
5. November 23, 1994
Item 5. Other Events
-- California Public Utilities Commission Proceedings
-- Electric Industry Restructuring
-- Restructuring of Gas Supply Arrangements -- Recovery of Interstate Transportation Demand Charges
-- Energy Cost Adjustment Clause
-- 1995 Cost of Capital Proceeding
-- PGT/PG&E Pipeline Expansion Project -- Other Competitive Interstate Pipeline Projects
-- Diablo Canyon Nuclear Power Plant
-- Diablo Canyon Rate Case Settlement
-- Diablo Canyon License Amendment
6. December 5, 1994
Item 5. Other Events
-- Proposed Modification of Diablo Canyon Pricing Mechanism
7. December 19, 1994
-- California Public Utilities Proceedings
-- Electric Industry Restructuring
-- 1996 General Rate Case
8. January 4, 1995
Item 5. Other Events
-- Performance Incentive Plan -- 1995 Target
-- California Public Utilities Commission Proceedings
-- 1995 Electric Rate Stabilization/Attrition Rate Adjustment
-- ECAC
-- 1988 - 1990 Gas Reasonableness Proceedings
9. January 19, 1995
Item 5. Other Events
-- Performance Incentive Plan -- 1994 Financial Results
-- 1994 Consolidated Earnings (unaudited)
-- Common Stock Dividend
-- California Public Utilities Commission Proceedings -- Core Procurement Incentive Mechanism
10. February 21, 1995
Item 5. Other Events
-- California Public Utilities Commission Proceedings--Experimental Procurement Service for Customer-Identified Electric Supply
11. March 2, 1995
Item 7. Financial Statements, Pro Forma Information and Exhibits
-- 1994 Financial Statements
-- Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
-- Exhibits
INDEMNIFICATION UNDERTAKING
For purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into the registrant's Registration Statement on Form S-8 No. 33-23692 (filed August 12, 1988):
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in a successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND COUNTY OF SAN FRANCISCO, ON THE 27TH DAY OF MARCH, 1995.
PACIFIC GAS AND ELECTRIC COMPANY (Registrant)
By GARY P. ENCINAS ----------------------------------- (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.
* By GARY P. ENCINAS --------------------------------- (Gary P. Encinas, Attorney-in-Fact)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors of Pacific Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements and the schedule of consolidated segment information included in the Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Annual Report on Form 10-K and have issued our report thereon dated February 6, 1995. Our report on the 1994 consolidated financial statements includes an explanatory paragraph that describes the uncertainties regarding the ultimate outcome of the electric industry restructuring, as discussed in note 2 to the consolidated financial statements. In addition, our report includes an explanatory paragraph indicating that, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits other than pensions and for income taxes as discussed in notes 1 and 9 to the consolidated financial statements.
Our audits of the consolidated financial statements and the schedule of consolidated segment information were made for the purpose of forming an opinion on those statements taken as a whole. The supplemental 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 consolidated financial statements. The supplemental schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and the schedule of consolidated segment information 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 and schedule of consolidated segment information taken as a whole.
ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
San Francisco, California February 6, 1995
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
- --------------- (1) Company disposed of its investment in Alaska Natural Gas Transportation System in January 1993. (2) Construction on the gas transportation system was discontinued in 1983. The Company accrued and reserved AFUDC through January 1993, at which time the Company's subsidiary that was a partner in the partnership organized to build and operate the gas transportation system withdrew from that partnership. (3) Deductions consist principally of write-offs of expired leaseholds on reserved property. (4) Primarily due to development cost for power projects. (5) Deductions consist principally of write-offs, net of collections of receivables considered uncollectible.
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
EXHIBITS
TO
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1994
------------------
PACIFIC GAS AND ELECTRIC COMPANY
------------------
================================================================================
INDEX TO EXHIBITS
INDEX TO EXHIBITS--(CONTINUED)
- --------------- * 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.