ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
Pacific Gas and Electric Company (the Company) is an operating public utility engaged principally in the business of supplying electric and natural gas service throughout most of Northern and Central California, a territory with an estimated population of 12,800,000. As of December 31, 1993, the Company served approximately 4,400,000 electric customers and 3,600,000 gas customers. As of December 31, 1993, the Company (excluding subsidiaries) had approximately 23,000 employees.
The Company was incorporated in California in 1905. Its 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.
The Company's service territory covers 94,000 square miles, 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.
As of December 31, 1993, the Company had approximately $27 billion in assets. The Company generated approximately $10.6 billion in operating revenues for 1993. The Company's revenues come from three sources: traditional gas and electric utility operations, Diablo Canyon Nuclear Power Plant (Diablo Canyon) operations, and activities conducted through the Company's nonregulated subsidiary, PG&E Enterprises (Enterprises). The Company's traditional utility operations are generally regulated under the cost-based approach to ratemaking. Diablo Canyon operations are conducted under a performance based approach to alternative ratemaking, as a result of the Diablo Canyon rate case 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. Enterprises, a wholly owned subsidiary of the Company, is the parent company for the nonregulated portion of the Company's business, which includes non-utility electric generation facilities and natural gas and oil exploration and development.
The Company serves its electric customers with power generated by eight primarily natural gas-fueled power plants, ten combustion turbines, one nuclear power plant, 70 hydroelectric powerhouses, one hydroelectric pumped storage plant 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 has supply contracts of varying lengths with both Canadian and United States suppliers. In 1993, about 55% of the Company's gas supply came from fields in Canada, about 40% came from fields in other states (substantially all from the U.S. Southwest) and about 5% came from fields in California.
In February 1993, the Company announced a corporate reorganization to consolidate certain business units, operating regions and operating divisions. As a result of the reorganization, the Company is organized into five business units: Customer Energy Services (formerly known as the Distribution business unit), Electric Supply, Gas Supply, Nuclear Power Generation and Enterprises. The former Engineering and Construction business unit has been disbanded, with its functions assumed by the remaining business units. The business units will continue to be supported by Corporate Services departments, which provide essential corporate services and management functions.
COMPETITION
Under traditional utility regulatory schemes, utilities have been accorded the exclusive right to serve customers within designated areas in return for their 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.
The Company is currently experiencing increasing competition in both the gas and electric energy markets. Recent restructuring in both the gas and electric industries has resulted in the separation of the energy supply function from the energy services function in both the gas and electric businesses. These changes have allowed competition to flourish in the gas supply and electric production segments of the energy business.
As a result of regulatory changes in the gas industry, the Company no longer provides combined purchase and transportation services to many of its industrial and large commercial (noncore) gas customers. Instead, many noncore customers now purchase gas supplies directly from a gas shipper or producer, reserve interstate transportation capacity directly from an interstate pipeline, and then purchase intrastate transportation service from the Company once their gas arrives at the California border. In addition, an interstate pipeline company has proposed expanding its facilities into the Company's service territory. If approved, the expansion would allow that pipeline company to compete directly for intrastate transportation service to the Company's noncore customers. See "Gas Utility Operations -- Other Competitive Interstate Pipeline Projects" below.
If, in the restructured gas industry, the Company's gas customers elect to serve their own gas supply needs, reserve their own interstate transportation capacity, or leave the Company's system altogether by moving to an alternative intrastate delivery system, the Company may find that it needs to spread 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, or other measures are taken, the price per unit would go up and remaining customers would be asked to pay higher prices, further exacerbating the competitive pressures.
The restructuring of the natural gas industry has already had a significant impact on the Company's gas operations. In 1993, the Company terminated its long-term Canadian gas purchase contracts and entered into new, more flexible arrangements for the purchase of the Company's current lower gas supply requirements. In addition, the Company is continuing its efforts to permanently assign or broker its commitments for firm gas transportation capacity which it once held for its noncore customers.
Changes in the electric utility industry are following the pattern of change in the natural gas industry. The Company continues to perform 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, or 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). Future additions to satisfy electric supply needs in the Company's service territory will be determined largely through a competitive resource procurement process, a feature of the new competitive market for electric generation. It is expected that new power plant projects will be increasingly undertaken by IPPs rather than utilities, and indeed, the Company has indicated a willingness to forgo building new generation capacity in its service territory if the electric resource procurement process is appropriately reformed. In addition, federal regulators now have increased authority to order a utility to transport and deliver, or "wheel," energy for any wholesale purchaser or seller of power, and it is possible that the trend of increasing wholesale transmission access could lead to increased pressure for state regulators to mandate wheeling to retail customers. Whether states have authority to order retail wheeling is as yet undetermined. If future restructuring were to include retail wheeling whereby customers purchase energy directly from an IPP or other supplier and separately pay the Company to wheel the purchased power, the Company's power generation plants and resources would be subject to even greater competition from other available supply options.
Under current regulation, customer prices are based on an allocation among customer classes of the Company's approved cost-of-service revenue requirements. Currently, large industrial and commercial customers are most likely to have lower cost competitive gas supply and electric generation alternatives. If a substantial number of these customers were to elect those alternatives and leave the Company's system, the Company's recovery of its investment in production sources and distribution facilities would be dependent on prices charged to remaining customers and the Company's ability to reduce costs. This could lead to lower
shareholder returns. In addition, the continuing recession in California's economy has resulted in reduced growth in demand for the Company's products and services. California's current economic condition could also lead to increased regulatory resistance to, and reduced customer acceptance of, higher 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 current electric prices are less competitive than its gas prices. Although the Company's residential electric bills are at the low end of the scale nationally, the Company's prices per kilowatt-hour (kWh) are high when compared with national averages. The Company's prices for industrial customers average approximately 7.3 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 system average electric price, at 10.6 cents per kWh, is the highest in California and has increased slightly faster than inflation over the past five years. The Company's electric prices include the costs for generation, transmission, distribution and customer service.
In an effort to improve its ability to succeed in the face of greater competition, the Company has taken steps to improve service to customers, reduce costs and lower the price of gas and electric service. To help reduce its costs and maintain competitive prices, the Company has:
-- reduced its workforce by approximately 3,000 positions, which is expected to result in net revenue requirement savings of approximately $170 million during the three-year 1993 General Rate Case cycle and annual revenue requirement savings of at least $200 million beginning in 1996 (see "Current Rate Proceedings -- Workforce Reduction Rate Mechanism" below);
-- reduced its cost of capital by taking advantage of significantly lower interest rates to refinance a significant portion of its long-term debt and a portion of its preferred stock; and
-- obtained California Public Utilities Commission (CPUC) approval to freeze current electric rates through the end of 1994 and to reduce electric rates by $100 million for major businesses over an 18-month period beginning in July 1993 (see "Current Rate Proceedings -- Electric Rate Initiative" below).
The Company has also taken specific steps which will assist it in remaining competitive in the restructured gas industry.
-- In November 1993, the Company terminated its long-term Canadian gas purchase contracts and entered into new, more flexible arrangements for the purchase of the Company's current lower gas supply requirements. See "Gas Utility Operations -- Restructuring of Canadian Gas Supply Arrangements -- Decontracting Plan" below.
-- The Company has implemented gas rate design modifications intended to more accurately reflect the cost to serve each customer class. Although implementation of the new rates did not result in an overall increase in the Company's authorized revenues, upon implementation the overall gas transportation rates for large industrial noncore customers decreased by approximately 31% and the overall transportation rate for utilities using gas to generate electricity decreased by approximately 20%, while residential and smaller commercial (core) customer rates for bundled gas service (procurement and transportation) increased by approximately 5% compared to rates previously in effect.
-- The Company has entered into long-term gas transportation contracts providing discounted rates for certain major industrial customers. The CPUC has approved on an expedited basis eleven long-term contracts with existing customers, ten of those under the Expedited Application Docket (EAD) procedure. The eleven long-term contracts together represent approximately 7% of the Company's noncore transportation revenues and approximately 12% of the Company's transportation revenues from industrial and cogeneration customers. The Company is currently precluded from recovering in rates 25% of the revenue shortfalls resulting from discounts given in these contracts until the CPUC adopts final rules regarding noncore transportation pricing or approves recovery by the Company of such amounts as part of the Company's next gas ratemaking proceeding. See "California Ratemaking
Mechanisms -- Gas Revenue Mechanisms" below. At that time, the CPUC is expected to make a further determination as to the rate recovery of revenue shortfalls attributable to EAD contracts.
-- The Company has filed for approval new long-term gas transportation rates to be offered to its largest industrial and cogeneration customers. See "Long-Term Gas Transportation Rates" below. Approval of these rates will enable the Company to offer competitive long-term rates without the burden of the contract-by-contract approval required under the EAD procedure.
In addition, the Company is currently seeking fundamental changes in the overall regulatory regime under which it must operate in order to allow the Company greater flexibility to compete in today's markets and still achieve its pricing and earnings goals. In March 1994, the Company filed an application with the CPUC requesting it adopt the Company's Regulatory Reform Initiative (RRI). The RRI has three components. The first, performance based ratemaking for determining base revenues, would replace several traditional rate cases with a framework which includes a base revenue index and financial incentives tied to performance standards. The Company would manage its non-fuel costs in accordance with revenue determined by an external index, instead of having its actual or forecast costs subject to detailed CPUC review. The performance standards would provide the Company with significant incentives to maintain its quality of service, as well as to provide that service while lowering residential customers' bills as much as possible. The PBR proposal provides for the sharing between ratepayers and shareholders of earnings above or below a target utility return on equity that would be computed annually.
The second component of the RRI involves the creation of a Large Electric Manufacturing Class (LEMC) of customers. This proposal is intended to provide large manufacturing customers the price certainty and tariff options they need to be competitive, as well as the ability to negotiate customized contracts with the Company. The Company expects that the new tariff options will influence the LEMC customers' decisions to retain and/or expand their operations in California, and encourage other manufacturers to establish operations in the state. Also, the flexibility afforded by the LEMC proposal would allow a more prompt response to the LEMC customers' existing competitive alternatives, and thus help to avert the uneconomic bypass of the Company's electric system.
The third component involves the use of market benchmarks to evaluate gas procurement costs. A specific proposal regarding the third component is not included in the Company's March 1994 filing but is expected to be filed at a later date. See "Regulatory Reform Initiative" for more details regarding the RRI.
CALIFORNIA RATEMAKING MECHANISMS
The ratemaking mechanisms currently applied by the CPUC in setting the Company's rates are discussed below. As noted above (see "Competition"), the Company has filed an application with the CPUC requesting adoption of the RRI as an alternative to the current regulatory approach to setting rates. If adopted, the RRI would significantly alter the ratemaking mechanisms described below. In addition, the Company implemented its electric rate initiative in 1993, which impacted the application of certain of these ratemaking mechanisms in current rate proceedings (see "Current Rate Proceedings" below).
GENERAL RATE CASE AND ATTRITION MECHANISMS
General Rate Case (GRC). 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 offset the Company's fuel and fuel-related costs, are set as part of the Energy Cost Adjustment Clause proceeding for electric operations and the Biennial Cost Allocation Proceeding for gas operations, as discussed below.) The Company files a GRC application once every three years, with a decision issued approximately 13 months after the application is filed. In this proceeding, revenues and expenses are determined on a forecast or future test-year basis, rather than on a historic-year basis. A decision was issued in the Company's 1993 GRC in December 1992. In November 1993, the CPUC denied the petition filed in January 1993 by the CPUC's Division of Ratepayer Advocates
(DRA) and various special interest groups to modify the decision in the Company's 1993 GRC so as to reduce the authorized revenue requirements. Under the current GRC mechanism, the Company's next GRC, based on a 1996 test year, would be filed in late 1994. Pending adoption of the RRI, the Company will proceed to make that filing in 1994.
Attrition Rate Adjustment (ARA). The ARA adjusts base rates in the years between GRC decisions to partially offset attrition in earnings due to changes in 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 cost of capital, 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. Changes in fuel and fuel-related costs are addressed in the Energy Cost Adjustment Clause proceeding for electric operations and the Biennial Cost Allocation Proceeding for gas operations, both of which are discussed below. The ARA improves the Company's ability to earn its authorized rate of return for utility operations in the years between GRCs.
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 currently in place for the Company. The petition requests that any future attrition rate increases be considered only upon application by the Company for such relief and only if the then current rate of inflation exceeds 6% on an annual basis. Under such circumstances, the petition recommends that the level of any attrition rate adjustment ultimately authorized by the CPUC be limited only to inflation above the 6% threshold level. In June 1993, the Company filed its response to the petition stating that the current ARA mechanism is a necessary feature of the three-year GRC cycle even during periods of low inflation.
ELECTRIC REVENUE MECHANISMS
Energy Cost Adjustment Clause (ECAC). Starting in 1994 with the reinstatement of the Annual Energy Rate (AER) mechanism described below, the ECAC provides for recovery of 91% of the cost of fuel and purchased energy, fuel oil inventory carrying costs up to an authorized level, facility charges and certain gains or losses from the sale of fuel oil, and for collection of performance-based Diablo Canyon revenues. The remaining 9% of the energy costs are recoverable through the AER procedure described below. Differences between total ECAC revenues and the sum of actual electric energy costs recoverable through the ECAC and Diablo Canyon revenues accumulate in a balancing account, usually with interest, and are recovered from or returned to customers through subsequent ECAC rates. Also included in the ECAC proceeding are revenue adjustments resulting from the Low Income Rate Assistance program and the Electric Revenue Adjustment Mechanism described below. Recovery of costs included in the ECAC is subject to a determination that such costs were incurred reasonably. (Diablo Canyon costs are not subject to reasonableness review, but are recovered pursuant to the Diablo Canyon rate case settlement. See "Diablo Canyon -- Diablo Canyon Settlement" below.) ECAC rates are set once a year, based on a January 1 revision date, to recover electric energy-related costs based on a forward-looking calendar test year. ECAC rates also are subject to adjustment effective May 1 if the required adjustment would be more than 5% of total annual electric revenues. The Company's next ECAC application is expected to be filed on April 1, 1994.
Annual Energy Rate (AER). The AER mechanism, which had been suspended in August 1990, was reinstated by the CPUC in December 1993. The reinstatement of the AER mechanism places the Company at partial risk for variations between actual and forecasted energy expenses, since there is no specific balancing account associated with the AER. The AER provides for recovery of 9% of forecasted energy costs and the amounts collected under the AER will not be adjusted if actual costs differ from the amounts authorized. To minimize the revenue risk resulting from the potential for substantial swings in energy-related expenses, the allowable pre-tax earnings fluctuation (up or down) resulting from the AER procedure is limited by a 140 basis-point cap applied to earnings on the equity portion of total rate base. To the extent that AER-related energy expenses exceed the allowable range of fluctuation, such expenses outside the allowable range become subject to ECAC balancing account treatment. The AER mechanism is on the same time schedule as the ECAC mechanism.
Electric Revenue Adjustment Mechanism (ERAM). The ERAM allows rate adjustments to offset the effect on base revenues of changes in electric sales from the level 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 subsequent ERAM rate adjustments. ERAM rate adjustments are made as part of the ECAC process with a January 1 revision date.
GAS REVENUE MECHANISMS
Biennial Cost Allocation Proceeding (BCAP). The BCAP forecasts the cost of gas, allocates costs of providing gas service to various customer classes, including the base revenue amount approved in the GRC or ARA, and sets associated rates. Issues considered in the BCAP include: (i) the gas transportation forecast (throughput), purchased gas costs and transportation revenue requirement forecast for costs other than the base amount; (ii) the allocation of costs between core and noncore customer classes; and (iii) the rates for procurement services for core customers and for transportation and related services for each customer class. Core customers include all residential customers and commercial customers that do not exceed certain volume limitations. Noncore customers are industrial and larger commercial customers that exceed certain volume limitations. A filing is made on August 15 of every other year for rates to be effective on April 1 of the following year. The Company's next BCAP application is currently scheduled to be filed in August 1994. 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 over-or under-collections 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.
Purchased Gas Account (PGA). The PGA is a balancing account which accumulates differences between actual cost of gas procured for the core portfolio and revenues intended to cover those costs. Those differences accumulate with interest, and are recovered from or returned to procurement customers through subsequent BCAP rate adjustments.
Gas Fixed Cost Accounts (GFCAs). The GFCAs include separate core and noncore accounts. The core GFCA is a balancing account that accumulates the differences between most of actual transportation revenues from core customers and the sum of the authorized core base revenue amount and core gas service costs. The difference accumulates with interest, and is recovered from or returned to customers through subsequent BCAP rate adjustments. The noncore GFCA tracks 75% of the difference between most of actual transportation revenues from noncore customers and the sum of the authorized noncore base revenues and noncore gas service costs. This amount accumulates with interest, and is recovered from or returned to customers through subsequent BCAP rate adjustments.
Interstate Transition Cost Surcharge (ITCS) Account. The ITCS is a balancing account that accumulates unrecovered demand charges for interstate capacity acquired by a utility prior to the adoption of the CPUC's capacity brokering rules in November 1991. Demand charges that are not fully recovered because of the operation of the capacity brokering rules accumulate in the ITCS account and are recovered through subsequent BCAP rate adjustments 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.
OTHER RATE ADJUSTMENT MECHANISMS
Low Income Rate Assistance (LIRA). The LIRA program was established by the CPUC in 1989 to provide discount residential electric and gas rates for customers who qualify under low-income criteria. LIRA
program administrative costs are recovered through base rate revenues and the direct cost of LIRA rate discounts are funded through LIRA rate adjustments made in the ECAC and BCAP proceedings.
Customer Energy Efficiency (CEE). Under the 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 programs. Beginning in 1994, CEE rate adjustments resulting from shareholder incentives earned on CEE programs will be determined as part of the Annual Earnings Assessment Proceeding (AEAP), a new 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 CEE program accomplishments. See "CEE/DSM Programs" below. Prior to 1994, these adjustments had been made in the ECAC proceeding.
CATASTROPHIC EVENTS MEMORANDUM ACCOUNT (CEMA)
The 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.
REGULATORY REFORM INITIATIVE
The Company has been engaged in discussions with the CPUC, customers and other interested parties concerning various reforms to the current regulatory approach to setting rates. On March 1, 1994, the Company filed an application with the CPUC requesting it adopt the Company's proposed RRI and approve 1995 electric and gas base revenue requirements.
The RRI is, in part, a response to the report issued in February 1993 by the CPUC's Division of Strategic Planning on electric industry restructuring. That report concluded that the current regulatory approach is incompatible with the emerging industry structure resulting from technological change, competitive pressure and new market forces. The report indicated that the existing cost-of-service ratemaking does not provide sufficient incentives for efficient utility operations and disproportionately favors additions to rate base as opposed to energy efficiency or purchased power alternatives, and that the number and complexity of proceedings result in significant administrative costs and burdens which threaten the quality of public participation in CPUC proceedings. Although the report indicated the necessity for reform of the regulatory framework, it did not ultimately recommend a specific strategy.
The Company's RRI has three components: (i) performance based ratemaking (PBR) for determining base revenues; (ii) establishment of the LEMC, consisting of large electric manufacturing customers; and (iii) use of market benchmarks to evaluate gas procurement costs. A specific proposal regarding the third component is not included in the Company's March 1, 1994 filing but is expected to be filed at a later date.
In its filing, the Company proposes a schedule calling for technical workshops in April, public hearings beginning in June and a final CPUC decision by the end of 1994. The Company has requested that the RRI become effective on January 1, 1995.
PBR
Under the Company's PBR proposal, electric and natural gas base revenues would be determined annually by formula rather than through GRCs, ARAs and Cost of Capital proceedings. Base revenues are the revenues intended to recover the Company's operation and maintenance expenses (excluding costs for fuel or fuel-related items), depreciation expense, income and other taxes, and to provide a return on invested capital. Revenues to offset fuel and fuel-related costs would still be determined in the ECAC proceeding for electric operations and the BCAP for gas operations. The PBR mechanism will not apply to the base revenue associated with Diablo Canyon, including Diablo Canyon decommissioning costs, which will continue to be determined pursuant to the Diablo Canyon rate case settlement. See "Diablo Canyon -- Diablo Canyon Settlement" below.
The Company's proposed PBR mechanism would determine the base revenues for a given calendar year by multiplying the base revenues authorized for the prior calendar year by an index consisting of inflation plus customer growth less a prescribed productivity factor. Those revenues would also be adjusted up or down depending on the Company's achievement relative to four performance standards: CEE programs, Energy Bills (i.e., a comparison of the Company's overall residential electric and gas bills relative to national averages), Customer Satisfaction and Electric Service Reliability. The positive or negative adjustments related to the Company's performance in these four areas would be one-time modifications to that year's base revenues as calculated under the PBR index formula. The adjustments for CEE incentives would be determined as they currently are under existing ratemaking procedures. The maximum adjustments that the Company could earn related to Energy Bills and Customer Satisfaction is $25 million per year for each, and the maximum for Electric Service Reliability is $19 million per year. Under PBR, the Company could also apply for an adjustment to base revenues due to the occurrence of certain extraordinary events outside the Company's control, including events that would currently qualify for ratemaking treatment through the existing CEMA (see "California Ratemaking Mechanisms -- Catastrophic Events Memorandum Account" above).
The PBR proposal provides for the sharing between ratepayers and shareholders of earnings above or below a target utility return on equity (ROE) that would be computed annually. To the extent actual ROE exceeds more than 200 basis points above or below the target ROE, the difference would be shared equally with ratepayers through a reduction or increase in the next year's base revenue. If actual ROE was more than 500 basis points above or below the target ROE, then the Company and the CPUC would each have the option to initiate a proceeding to reexamine the PBR formula.
The Company is proposing that base revenue indexing begin in 1995. However, the Company proposes to forgo any increase in the electric base revenue for 1995 determined under the PBR mechanism. Instead, 1995 electric base revenue would be held at the 1994 level.
In its filing, the Company proposes that the RRI remain in place indefinitely. The Company recommends that after five years the CPUC review the PBR mechanism and make any necessary adjustments, but not return to the use of traditional rate cases to set rates.
LEMC
As proposed by the Company, the LEMC would consist of the Company's largest electric accounts (having an average hourly electricity usage over a 12-month period of at least 2,000 kilowatts) engaged in manufacturing. Currently, approximately 120 accounts would qualify for inclusion in the LEMC.
LEMC customers would be removed from cost-of-service ratemaking. Standard LEMC tariff rates would be determined every calendar year by an index formula, similar to that used in the PBR mechanism, which is intended to reflect inflation less a productivity factor. In addition, several long-term tariff options designed to respond to these customers' competitive alternatives would be offered to the LEMC. The Company also seeks authorization to negotiate and enter into customized contracts with LEMC customers. In some cases, the customized contracts would become effective without prior approval or subsequent review by the CPUC of the contract terms.
Generally, the Company proposes to separate the costs allocated to the LEMC and bear the risk of their recovery if sales to these customers decline over time. The Company's shareholders would bear the risk of LEMC costs that increase faster than the LEMC price index.
ACCOUNTING IMPLICATIONS
Based on the regulatory framework in which it operates, 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, the Company defers recognition of costs which would otherwise be expensed when incurred because regulators have provided mechanisms that make it probable that the costs will be included in future rates. If the RRI is
adopted, the mechanics of the rate setting process would change. However, the Company anticipates that rates derived from the RRI would remain based on cost-of-service, with the exception of rates for the LEMC customers and rates established under certain other regulatory mechanisms proposed to be discontinued upon adoption of the RRI.
If the RRI is adopted as proposed, the Company anticipates that it will write-off certain regulatory assets, including an estimated $65 million related to the LEMC customers and potentially additional amounts which may be affected by the adoption of the RRI, the aggregate amount of which could have a significant adverse impact on the Company's financial position or results of operations. The estimated amount related to the LEMC is based on the base revenue allocation currently used in establishing rates; the actual amount could vary depending on the allocation method adopted by the CPUC. The final determination of the accounting impact will be dependent upon the form of the regulatory reform ultimately adopted.
In the event that recovery of specific costs through rates becomes unlikely or uncertain for a portion or all of the Company's utility operations, whether resulting from the expanding effects of competition or specific regulatory actions which force the Company away from cost-of-service ratemaking, SFAS No. 71 would no longer apply. Discontinuation of SFAS No. 71 would cause the write-off of the applicable portion of regulatory assets, including regulatory balancing accounts receivable and those regulatory assets included in deferred charges, which could have a significant adverse impact on the Company's financial position or results of operations.
LONG-TERM GAS TRANSPORTATION RATES
On March 18, 1994, the Company filed an advice letter with the CPUC, requesting authorization to implement an optional long-term noncore gas transportation tariff. This tariff would be offered to the Company's largest industrial and cogeneration gas transport customers (having an annual usage greater than three million therms) under a standard ten-year service agreement.
The proposed rates are intended to enable the Company to more effectively meet intensified competition by allowing it to offer a long-term competitive rate without having to obtain CPUC approval on a contract-by-contract basis as is currently required under the EAD procedure. The proposed rates are within the range of rates negotiated under existing EAD contracts and will exceed the marginal cost of serving the customers eligible for the new rates. The Company's shareholders will bear the risk of any revenue shortfalls attributable to any differences between the long-term rate option and the customer's otherwise applicable rate.
The Company has requested that the requested tariff changes become effective no later than June 1, 1994. If approved, the rates would be offered to existing qualifying customers in a two-month open season commencing on that date.
If its advice letter is approved, the Company anticipates that it will discontinue application of SFAS No. 71 for the customers accepting the long-term service agreement. This would cause a write-off of as much as approximately $25 million of regulatory assets related to those specific customers which elect to use the new tariff. This estimated amount is based on the base revenue allocation currently used in establishing rates; the actual amount could vary depending on the allocation method adopted by the CPUC.
CURRENT RATE PROCEEDINGS
ELECTRIC RATE INITIATIVE
In April 1993, the Company proposed a comprehensive electric rate initiative to freeze current retail electric rates through the end of 1994 and to reduce electric rates by $100 million for major businesses as an economic stimulus for those customers. In June 1993, the CPUC approved the economic stimulus rate, effective for the period July 1993 through December 1994.
In December 1993, the CPUC approved the electric rate freeze and issued its decisions in the Company's ARA and ECAC proceedings. As part of the ECAC decision, the CPUC approved the Company's request to defer beyond 1994 recovery of a portion of the undercollections in the ECAC balancing account. The total undercollection at December 31, 1993 was $427 million.
Pursuant to the electric rate initiative, 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 1994 (see "1994 Revenue Changes" below).
1994 REVENUE CHANGES
The following table summarizes the various rate case decisions that became effective on January 1, 1994.
SUMMARY OF RATE CASE DECISIONS EFFECTIVE JANUARY 1, 1994 (IN MILLIONS)
ARA Proceeding. In December 1993, the CPUC issued a resolution authorizing the Company to implement an adjustment to base rates pursuant to the ARA mechanism, effective January 1, 1994, which results in a net attrition increase of $41 million for electric base rates and $54 million for gas base rates. These adjustments incorporate the final decision in the Company's 1994 Cost of Capital proceeding described below. As part of the Company's electric rate initiative, the $41 million increase excludes approximately $20 million of increased taxes attributable to the higher corporate tax rate recently adopted for which the Company would otherwise have sought recovery through the ARA mechanism but instead will forgo.
The CPUC's resolution also authorized the Company to reduce its 1994 electric and gas base revenues by approximately $143 million and $60 million, respectively, primarily as a result of the net savings from the Company's workforce reduction program and a plan change that will limit the amount the Company will contribute toward post-retirement medical benefits. These reductions in revenue requirements for electric operations were used to offset the $41 million attrition increase and to reduce undercollections in the ERAM balancing account by $102 million. Pursuant to the electric rate initiative, electric base revenues were held constant, resulting in a consolidated net change in electric rates of zero effective as of January 1, 1994.
1994 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 1994 designed to provide a utility return on common equity of 11.00%. The decision authorizes a utility capital structure of 47.50% common equity, 5.50% preferred stock and 47.00% long-term debt, which represents an increase from 46.75% in the equity component of the Company's capital structure. The decision states that the increase will bring the Company in line with other comparable utilities and will better reflect the increasingly competitive environment facing electric utilities. When combined with the authorized costs of debt and preferred stock, the 11.00% return on equity results in a 9.21% overall authorized utility rate of return for 1994 compared with the 10.13% authorized for 1993. The decision would decrease revenue requirements by approximately $116 million for electric rates and $36 million for gas rates effective January 1, 1994. As proposed by the Company, the reduction in the cost of capital was consolidated with other electric revenue changes such that there was no net increase in electric revenue requirements effective January 1, 1994.
ECAC/AER/ERAM/LIRA/CEE. In December 1993, the CPUC issued a decision authorizing a net zero change in the Company's electric revenue requirement for the twelve-month forecast period beginning January 1, 1994. The decision also authorizes a gas revenue requirement increase of approximately $4 million relating to the Company's CEE programs for the same forecast period. The new rates are effective as of January 1, 1994.
The net zero change in the Company's overall annual electric revenue requirement for 1994 is composed of a $112 million increase under the ECAC balancing account, a $7 million increase under the AER mechanism, a $129 million decrease under the ERAM, a $1 million decrease under the LIRA account and a $11 million increase for recovery of incentives earned on CEE programs.
Consistent with its electric rate initiative, the Company had requested deferral beyond 1994 of a portion of undercollections in the ECAC balancing accounts. The total undercollection at December 31, 1993 was $427 million. In its decision, the CPUC approved the Company's request, but cautioned that the CPUC does not view its action as simply a deferral with payment due in 1995. Rather, the CPUC indicated that it expects the Company to take the necessary measures over the year to reduce its rates. With the stated objective of providing additional incentives for cost containment, the CPUC refused to allow the Company to collect interest on the revenue requirement deferral and ordered the reinstatement of the AER mechanism, which places the Company at risk for nine percent of the variations between actual and forecasted energy expenses.
With respect to CEE, the decision authorizes the Company to recover in rates over three years an aggregate electric and gas revenue increase of approximately $41 million for shareholder incentives relating to CEE measures installed in 1992, a reduction from the $59 million initially requested by the Company. Those revenues will be recovered in equal annual amounts beginning in 1994. The electric and gas revenue increases of $11 million and $4 million, respectively, authorized in rates for 1994 relating to CEE include one third of the 1992 incentives as well as amounts earned in previous years. However, the decision also provides that the $41 million allowed as shareholder incentives shall be subject to refund pending completion of a CPUC audit of all the Company's 1990-1992 CEE expenses. The audit is required to be completed by the end of 1994.
GAS COST ALLOCATION PROCEEDINGS
In October 1992, the CPUC issued a decision in the Company's 1992 BCAP which resulted in a $434 million decrease in the core gas revenue requirement and a $3 million decrease in the noncore gas revenue requirement over a two-year period from then current rates. The decision allocated approximately $250 million in annual revenues to be collected from the noncore transportation customers other than the Company's electric department, with 75% balancing account treatment for transportation revenues from all noncore customers.
In September 1993, the Company submitted an interim, or trigger, filing as permitted under the BCAP mechanism to set new rates. The Company's filing requests an increase of $136.7 million in the Company's core gas revenue requirement, which would result in a 7.7% increase in core rates over rates currently in effect. The Company requested that the proposed increase not be implemented until May 1, 1994. The CPUC has not acted yet on the Company's request.
WORKFORCE REDUCTION RATE MECHANISM
In February 1993, the Company announced a corporate reorganization and workforce reduction program. In conjunction with implementing the workforce reduction program, the Company filed an application with the CPUC to establish a balancing account through which the labor savings, net of the related costs, would be flowed back to the Company's customers in the form of reduced gas and electric rates. In March 1993, the CPUC authorized the establishment of a memorandum account to record all costs and savings incurred in connection with the 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. In its filing with the CPUC, the Company proposed that the revenue requirement savings achieved during the balance of the 1993 GRC cycle through the workforce reduction program be passed on to ratepayers over a two-year period beginning January 1, 1994.
As of December 31, 1993, the Company had recorded net workforce reduction program costs of $264 million. In April 1993, the Company announced a freeze on electric rates through 1994. As a result, the
Company has expensed $190 million of such costs relating to electric operations. The remaining $74 million of such costs relating to gas operations has been deferred for future rate recovery. The amount deferred is currently being amortized as savings are realized. The Company is currently seeking rate recovery of all costs incurred in connection with the workforce reduction program relating to electric and gas operations. However, in its RRI filing (see "Regulatory Reform Initiative" above), the Company requests that if the CPUC's review of the costs and savings associated with the workforce reduction program is not completed and reflected in rates before PBR begins, such review not be conducted. Under the RRI, the memorandum account established for such costs and savings would be terminated as of January 1, 1995.
During 1994 and 1995, the Company expects to benefit from the expense reduction attributable to the electric operations' workforce reduction. The Company currently estimates that the workforce reduction program will result in a net revenue requirement savings of approximately $170 million during the three-year 1993 GRC cycle, which ends December 31, 1995. Beginning in 1996, the workforce reduction program is expected to result in annual revenue requirement savings of at least $200 million.
CEE/DSM PROGRAMS
The Company has long been active in the implementation of CEE and other demand-side management (DSM) programs which provide incentives to customers to implement energy-efficient measures. These measures allow the Company to defer capital expenditures in connection with generating, 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 billion on DSM programs, allowing the Company to avoid the need for approximately 1,600 megawatts (MW) of new generating capacity.
In 1990, the CPUC issued a decision which implemented expanded CEE programs developed through collaborative efforts by the Company, other California utilities, regulatory agencies and environmental and consumer groups. The decision approved an incentive mechanism intended to encourage and sustain the Company's commitment to CEE. The mechanism adopted in 1990 provided that the Company can recover in rates the authorized costs of DSM programs plus shareholders incentives equal to 15% of the estimated net present value of energy savings from specified resource, or shared savings, programs that produce substantial net avoided capacity, transmission, distribution and energy costs savings, and 5% of the cost of certain service programs, including the Company's direct weatherization and energy efficiency education programs. Incentives earned on the implementation of CEE measures were originally authorized to be recovered in rates over the three-year period following the year in which the recovery of those incentives was authorized in the Company's annual ECAC proceeding.
The CPUC subsequently initiated a rulemaking proceeding on CPUC policies related to DSM programs (DSM Proceeding), and in a February 1992 decision, concluded that, as an interim policy beginning in 1993, shareholders' return on DSM measures should be no greater than shareholders' return on equivalent investments in utility constructed plants. Accordingly, in the Company's 1993 GRC, the percentage of energy savings to be earned as shareholder incentives for 1993 resource program accomplishments was reduced to 5.1% from the 15% earned in 1990, 1991 and 1992. Pending determination of a permanent shareholder incentive mechanism in the DSM Proceeding, the percentage return applied in calculating the shared savings incentive will be recalculated each year based on the rate of return on utility constructed plants and the forecasted costs and benefits of DSM programs.
In another 1993 decision, the CPUC determined that shareholder incentives earned on shared savings 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. In addition, the decision provided that, beginning in 1994, the amount of shareholder incentives authorized for the Company and other California energy utilities will be determined annually in the AEAP. See "California Ratemaking Mechanisms -- Other Rate Adjustment Mechanisms" above.
The CPUC held hearings in 1993 to determine whether shareholder incentives should be continued for DSM programs beyond 1994. In September 1993, the CPUC concluded that DSM shareholder incentives should be continued under the current regulatory framework. Hearings will be held in 1994 to determine the appropriate incentive mechanism and incentive level for DSM programs in 1995 and beyond.
The Company estimates that it will earn approximately $7 million (after-tax) in shareholder incentives from the 1993 CEE programs. The Company plans to spend approximately $260 million on CEE programs in 1994, an increase over the $186 million spent in 1993. If the Company meets its 1994 energy savings goals, it could earn over a ten-year period approximately $11 million (after-tax) under the shareholder incentive mechanism. The Company is permitted to recover, through a balancing account, up to a maximum of 130% of the amount authorized for shared savings programs. As in the past, the Company is subject to a penalty if actual accomplishments under a shared savings program fall below the minimum performance standard established for the program.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
The Company continues to require capital for additions to its facilities and to maintain and enhance the efficiency and reliability of existing generation, transmission and distribution facilities. Expenditures for these purposes, including the allowance for funds used during construction (AFUDC) were $1,883 million for 1993. New investments in nonregulated businesses totaled $234 million in 1993.
The following table sets forth the forecasted total capital requirements, consisting of capital expenditures for the utility functions, the expansion of the gas pipeline from Canada to California, Diablo Canyon and the nonregulated investments of Enterprises and amounts for maturing debt and sinking funds for the years 1994 through 1998. CAPITAL REQUIREMENTS (IN MILLIONS)
- ------------ (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 any amounts relating to the expansion of Pacific Gas Transmission Company's (PGT) pipeline system in 1994 through 1996 to provide additional deliveries in the Pacific Northwest. Capital expenditures relating to such further expansion total approximately $84 million.
(2) Utility expenditures include AFUDC. Diablo Canyon expenditures include capitalized interest.
(3) Enterprises' actual capital expenditures may vary significantly depending on the availability of attractive investment opportunities.
(4) In January 1994, the Company approved a final plan for the disposition of PG&E Resources Company (Resources) in 1994, if market conditions remain favorable. In light of the planned disposition, the forecasted capital expenditures for Resources in 1994 was recently increased to the level indicated in the table above. If Resources is not divested in 1994, the Company's capital expenditures would be approximately $100 million per year in each of the years 1994 through 1998.
(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 $95 million, $151 million and $27 million in 1994, 1995 and 1996, respectively. There are no current commitments to make contributions in 1997, 1998 or thereafter.
Most of the utility capital expenditures for 1994 through 1998 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 improve 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 1994 through 1998 will include approximately $2,278 million for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt. In an effort to reduce financing costs, the Company redeemed or repurchased $3,536 million of high-cost first and refunding mortgage bonds and $267 million of redeemable preferred stock in 1993. In addition, in December 1993, the Board of Directors authorized the Company to redeem or repurchase up to $1.2 billion of first and refunding mortgage bonds, $125 million of medium-term notes and $175 million of redeemable preferred stock. Of those amounts, $80 million of bonds, $40 million of medium-term notes and $75 million of preferred stock were redeemed in February and March 1994. Redemptions and repurchases were financed in part by the issuance in 1993 of $2,950 million of first and refunding mortgage bonds (Series 93A through 93H), $750 million of medium-term notes and $200 million of redeemable preferred stock. In 1993, the Company also entered into loan agreements with the California Pollution Control Financing Authority to borrow proceeds of $260 million of tax-exempt pollution control bonds issued to finance sewage and solid waste disposal facilities.
The funds necessary for the Company's 1994-1998 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. These programs and the projections 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 Electric Supply.
- ------------ (1) Area net capability at time of annual peak, based on 1977 water conditions which are the most adverse of record to date. (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, 1993, the Company owned and operated the following generating plants, all located in California, listed by energy source:
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(1) The following fossil fuel steam units (412 MW) were on long-term standby reserve during 1993. The units require a 12-18 month reactivation time, and are included as unavailable capacity in the Control Area Net Capacity table below. Contra Costa Unit 3 (116 MW) Kern Unit 1 (74 MW) Kern Unit 2 (106 MW) Moss Landing Unit 1 (116 MW)
(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, 1993, 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 33,130,000 kilovolt-amperes (kVa). Energy is distributed to customers through approximately 104,133 circuit miles of distribution system and distribution substations having a capacity of approximately 24,805,000 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 1977 water conditions, which are the most adverse on record to date) 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, 1993.
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(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 1993 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 9.9% and total reserve (spinning reserve and capability available within a short period of time) was 18.5%. (3) Represents actual year net generation from sources shown.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
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 twelve-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 Company forecasts area electric peak demand (on a CEC area basis) to increase from approximately 16,100 MW in 1994 to approximately 23,000 MW in 2013, reflecting a compound annual growth rate of 1.9%. The Company forecasts area electric energy load to increase from approximately 87,500 gigawatthours (GWh) in 1994 to 120,900 GWh in 2013, reflecting a compound annual growth rate of 1.7%. The Company's energy and peak demand forecasts closely approximate the CEC staff's forecasts through 2005, and are somewhat higher than the CEC staff's forecasts for periods thereafter, 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 243.5 MW of new purchases or company-owned
resources resulting from the BRPU solicitation, (ii) approximately 290 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 also anticipates completing the 2,500 MW of CEE and load management improvements initiated in 1990. The Company currently plans no new major construction projects for electric supply before the year 2000, other than projects already under development.
Future additions to satisfy electric supply needs in the Company's service territory 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 CPUC is exploring the use of an integrated bidding system in which both resource generation and DSM bidders would participate in the competitive procurement process. In October 1993, the CPUC issued a decision in the DSM Proceeding described above (see "General -- CEE/DSM Programs" above) which selected the Company to conduct an integrated bidding pilot program. The CPUC ordered the Company to conduct a pilot bid program for between 49 and 200 MW to test the feasibility of integrated bidding. The Company is granted significant flexibility in designing and implementing the bid program, in exchange for its agreement not to submit a bid in the pilot program. The Company expects to issue requests for bids in late 1994.
The CEC committee conducting proceedings relating to the CEC's 1994 Electricity Report issued orders expanding 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. The orders direct comprehensive studies in a wide variety of areas, including wholesale wheeling and regional integration of transmission systems, performance based ratemaking and "maximum feasible" competitive choices for customers. Workshops and hearings related to these orders will take place during 1994, with the committee expected to report the results of its analysis to the CEC in early 1995.
ELECTRIC 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. The CPUC explicitly stated that the investigation will not consider proposals for retail transmission service and should not be construed as a challenge to the franchise retail service territories of public utilities. The CPUC indicated that it believed the transmission investigation was necessary at this time in order to assure development of a competitive electricity generation sector in California.
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 second phase of the investigation could consider certain broader long-term transmission access and cost issues. In 1993, the assigned commissioner ruled that the scope of any future rulemaking in the second phase of the investigation would be limited to wholesale transmission issues which are not likely to be fully addressed by the Federal Energy Regulatory Commission (FERC). These issues include (i) coordinated regional transmission planning, (ii) unbundling of transmission service costs, (iii) determination of the best access form or vehicle, (iv) use of alternative dispute resolution mechanisms, (v) relative priority of transmission requests, and (vi) incentives for transmitting utilities. The assigned administrative law judge
(ALJ) has been ordered to commence discussions regarding procedure and schedule in the second phase of the investigation.
On the federal level, in 1993 the FERC began implementation of the National Energy Policy Act of 1992 (Energy Act). The Energy Act expanded the FERC's authority to order an electric utility to provide wholesale transmission service. The FERC may order any owner of transmission lines to provide transmission service, subject to a public interest finding, on application of any wholesale purchaser or seller of power. The FERC must allow the transmitting utility to recover its costs and may not order transmission service which will unreasonably impair system reliability. The Energy Act prohibits the FERC from ordering retail transmission service, or wheeling, directly to an ultimate consumer.
In 1993, the FERC issued a final rule on the transmission access information utilities must file annually and policy statements concerning regional transmission groups and the necessary components of a good faith request and response for transmission access under the Energy Act. The FERC also opened an investigation on transmission pricing.
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.
Payments to QFs are expected to vary in future years. The amount of energy received from QFs and the total energy and capacity payments made under these agreements were:
As of December 31, 1993, the Company had approximately 6,000 MW of QF capacity under CPUC-mandated power purchase agreements. Of the 6,000 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 6,000 MW of QF capacity consists of 3,400 MW from cogeneration projects, 1,500 MW from wind projects and 1,100 MW from other projects, including biomass, geothermal, solar and hydroelectric.
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. The DRA indicated that it would recommend disallowances over the 15-year term of the contracts of approximately $80 million. In its report on ECAC expenses for the 1992 record period, the DRA recommended a disallowance of approximately $3.5 million for two of these agreements.
The Company contested the DRA's assertions in its rebuttal testimony which was filed in November 1993. A decision is not expected from the CPUC until mid-1994. The Company is unable to predict the outcome of this matter, but believes the ultimate outcome will not have a significant adverse impact on its financial position or results of operation.
HELMS PUMPED STORAGE PLANT (HELMS)
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 while 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 $106 million at December 31, 1993.
In August 1991, the Company filed an application with the CPUC to increase electric base rates to allow recovery of a portion of the remaining unrecovered costs associated with Helms. In addition to placing these costs in rate base, the Company seeks to recover the associated revenue requirement on such costs since 1984 and lost revenues during the time the generators were being repaired.
In June 1993, the DRA issued its report on the Company's 1991 Helms application and recommended a disallowance of all requested costs and revenues. As a matter of policy, the DRA recommends that ratepayers should not be held responsible for plant costs or losses incurred by a utility due to contractor error whether or not the utility was prudent, and cites past CPUC action for this policy. In addition, the DRA contends that the Company acted imprudently in the management of the project and failed to adequately oversee the engineering and design of the generators. The DRA argues that the Company should not recover any revenue requirements associated with the generator costs for the period since 1984 since those revenues were not authorized previously by the CPUC and would constitute retroactive ratemaking. With respect to the lost revenues and related recorded interest during the time that Helms was out of service for the modification and repair of the generators, the DRA asserts that the Company has failed to establish that the outage was not caused by a problem first identified during the precommercial testing program.
The Company filed its rebuttal testimony in January 1994 asserting it is unreasonable to hold a utility responsible for all costs arising out of contractor error in all instances without regard to the specific facts of the case. This testimony also asserts that the Company was prudent in managing and overseeing the project, and that various issues raised by the DRA were not based on facts or were irrelevant to the application.
The Company has commenced discussions with the DRA in an attempt to expeditiously resolve the treatment of Helms costs through a settlement. The Company is uncertain whether, and to what extent, any of the remaining $106 million of costs and revenues will be recovered through the ratemaking process.
GEOTHERMAL GENERATION
Because of declining geothermal steam supplies, the Company's geothermal units at The Geysers Power Plant (The Geysers) are forecast to operate at reduced capacities. The consolidated Geysers capacity factor is forecast to be approximately 55.9% in 1994, which includes forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 61.8% in 1993. 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 (WSPP)
In 1991, the FERC approved an agreement among 40 utilities operating in 22 states and British Columbia for a permanent 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.
GAS UTILITY OPERATIONS
GAS OPERATIONS
As of December 31, 1993, the Company owned and operated approximately 5,700 miles of gas transmission lines and approximately 35,000 miles of gas distribution lines. The Company has three underground storage facilities. The Company's peak day send-out of gas during the year ended December 31, 1993, was 4,002 million cubic feet (MMcf). The total volume of gas throughput during that period was approximately 701,706 MMcf, of which 430,718 MMcf was sold to direct end-use or resale customers, 161,895 MMcf was used by the Company principally as fuel for fossil-fueled electric generating plants, and 109,093 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 1993 report forecasts the Company's gas demand from 1993 through 2010.
The forecast growth rate for the Company's service territory of 1.8% per year from 1993 through 2010 is higher than the 1.3% annual forecasted growth rate shown in last year's report for the same period for two reasons. First, a more optimistic forecast of growth in the number of households leads to a higher forecasted growth rate of gas sales. Second, the expected success of the Company's natural gas vehicle program and the implementation of federal and state clean air regulations leads to a much higher forecast of natural gas vehicle use.
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 108 billion cubic feet for 1993. The forecast assumes that bypass which began in 1991 will change little from the 1993 level and does not include any potential bypass from the proposed Mojave Pipeline Company expansion project. See "Other Competitive Interstate 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.
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(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 Customer Identified Gas (CIG) Program. Sales include 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) 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, 1993, approximately 55% of the Company's total purchases of natural gas consisted of Canadian gas purchased from PGT, a wholly owned subsidiary of the Company, and, following implementation of the of the Decontracting Plan described below, from various Canadian producers and transported by PGT, approximately 5% was purchased from various California producers, and approximately 40% 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.
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(1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or fixed 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
Effective in May 1988, a new regulatory framework for natural gas service was established in California. This framework (i) segmented customers into core (all residential customers and commercial customers that do not exceed certain volume limitations) and noncore (industrial and commercial customers that exceed certain volume limitations) classes; (ii) unbundled utilities' gas transportation and procurement services; (iii) allows noncore 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.
In November 1991, the CPUC issued a decision adopting a statewide capacity brokering program, whereby noncore customers and other shippers can obtain rights to firm interstate pipeline transportation capacity held by the local gas distribution utilities. Under the capacity brokering program implemented August 1, 1993 for the Company's El Paso and Transwestern capacity, and November 1, 1993 for the Company's PGT capacity, 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 choosing bundled procurement and transportation service). Noncore customers, brokers 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 are 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 has allowed many of the Company's noncore customers to arrange for the purchase and transportation of their own gas supplies. These changes have 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
FORMER CANADIAN GAS SUPPLY AND TRANSPORTATION ARRANGEMENTS
Prior to implementation of the Decontracting Plan described below, the Company purchased Canadian natural gas under various long-term contracts. The gas was shipped to the U.S. border by Alberta and Southern Gas Co., Ltd. (A&S), a wholly owned subsidiary of the Company, over the NOVA Corporation of Alberta (NOVA) and Alberta Natural Gas Company Ltd (ANG) pipelines under an export license from the National Energy Board of Canada (NEB), a removal permit from the Alberta Energy Resources Conservation Board and an energy removal certificate from the province of British Columbia. PGT purchased this Canadian natural gas from A&S and transported it from Canada to the California border, under authorization from the Department of Energy (DOE) to import the gas. The gas was purchased at the California-Oregon border by the Company. A&S had been authorized to export up to 1,126 MMcf per day (MMcf/d) and 373,500 MMcf per year through October 31, 2005.
DECONTRACTING PLAN
The CPUC's gas procurement and capacity brokering programs and the FERC's new regulatory structure resulted in a decrease in the amount of gas required to be purchased by the Company. As a result, A&S was required to terminate its gas supply arrangements with Canadian producers. A&S had commitments to purchase minimum quantities of gas from Canadian producers under various contracts, most of which extended through 2005. A number of Canadian gas producers had filed lawsuits against the Company during 1991 and 1992 claiming damages of at least Cdn. $466 million resulting from the alleged failure of A&S to meet its minimum contractual gas purchase obligations for the 1989-1992 contract years and for the anticipated failure of A&S to meet those obligations through 2005.
As a result of the regulatory changes 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. Gas producers representing more than 99.9% of the total volume of the gas supply of A&S participated in the Decontracting Plan. As a result, the Alberta provincial government and the NEB have ended restrictions imposed in 1992 on the shipment of gas to northern California and permitted the Decontracting Plan to be implemented. A&S also restructured its gas transportation and processing agreements.
Under the Decontracting Plan, the Canadian producers' contracts with A&S, the sales agreement between A&S and PGT, and the Company's service agreement with PGT each were terminated, effective on November 1, 1993. The termination of the agreements relieved the parties of their obligations under those agreements and permitted producers to decontract their reserves from the A&S supply pool. As a result, the Company may contract on an individual basis for its requirements directly with any producer, aggregator or marketer, whether or not they were formerly in the A&S supply pool.
Under the Decontracting Plan, participating producers released A&S, PGT and the Company from any claims they may have had that resulted from the termination of the former arrangements as well as any claims
for losses which arose from alleged historical shortfalls in gas taken by A&S. The total amount of settlement payments paid to the producers is approximately $210 million.
As part of the overall A&S decontracting process, A&S' operations have been significantly reduced, with Pan-Alberta Gas Ltd., a major aggregator of Canadian natural gas, acquiring A&S' restructured gas purchase contracts and its remaining Canadian sales contracts. A&S continues to hold gas transportation capacity on Canadian pipelines and is in the process of permanently assigning or brokering such capacity.
As part of the Decontracting Plan, A&S permanently assigned substantial portions of its commitments for transportation capacity with NOVA through October 2001 and ANG through October 2005 to third parties. A&S also assigned approximately 600 MMcf/d of capacity on each of these pipelines to the Company for use in the servicing of the Company's core and core subscription customers. A&S currently holds remaining capacity of approximately 450 MMcf/d with annual demand charges of approximately $25 million for which it is continuing its efforts to assign or broker. There is uncertainty about the ability of A&S to assign or broker this remaining capacity. To the extent others do not take this capacity, A&S will remain obligated to pay for the related demand charges.
In July 1993, FERC 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. The TCRM precludes most objections to the eligibility and prudence of such costs; prudence challenges may be made only on the grounds that the payment is unreasonably high in light of the damages claimed. Disposition of approved transition costs will be as follows: (1) 25% of such costs will be absorbed by PGT; (2) 25% will be recovered by PGT through direct bills (substantially all to the Company as PGT's principal customer); and (3) 50% will be 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 October 1993, PGT filed an application at the FERC for recovery of payments made under settlement agreements with 140 producers, representing approximately 97% of the volumes dedicated to A&S. The application seeks recovery of $154 million under the TCRM, which is 75% of the $206 million paid to such producers as of the time of the filing. PGT intends to submit further applications with the FERC for recovery of transition costs incurred under settlement agreements entered into after October 15. In November 1993, the FERC issued an order accepting the filing, with rates effective on November 15, but subject to refund to the extent not ultimately approved by the FERC. In December 1993, the CPUC filed a limited challenge to the costs. In its filing the CPUC decided not to challenge the prudence of the transition costs filed by PGT, but did challenge the eligibility for recovery under the TCRM of PGT's settlement payment to BC Gas Utility of $2.4 million. The CPUC also requested a technical conference or hearing to determine if other payments made by PGT are consistent with the TCRM.
In September 1993, the Company requested that the CPUC approve a memorandum account to track the direct bills charged to the Company by PGT for transition costs. In response, the DRA indicated that while it does not protest the Company's request to record the direct bills to a memorandum account, it does believe that these costs are unreasonable and that they should not be passed on to ratepayers. The DRA also urged that the CPUC investigate any gas supply restructuring costs that PGT attempts to pass on to the Company and to take into account these costs in its final decisions in the 1988-1990, 1991, 1992 and 1993 gas reasonableness proceedings. See "Gas Reasonableness Proceedings" below. In November 1993, the Company paid PGT approximately $51 million in payment of the direct bill charged by PGT for transition costs under the TCRM. The Company expects to seek recovery in its next BCAP application of this amount and volumetric surcharges to be billed to the Company.
FINANCIAL IMPACT OF DECONTRACTING PLAN AND LITIGATION
The Company incurred transition costs of $228 million, 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 due to the uncertainty of A&S's ability to assign or broker its remaining commitments for Canadian transportation capacity. Accordingly, the Company expensed $93 million in 1993 and a total of $23 million in prior years.
PGT and the Company are seeking recovery of all transition costs eligible for recovery under the TCRM other than the 25% of such costs to be absorbed by PGT. While such transition costs are still subject to challenges at the FERC level and the recovery of such costs paid by the Company as a shipper of gas on PGT will depend on the recovery mechanism adopted by the CPUC, the Company believes that it will ultimately recover the deferred transition costs.
RESTRUCTURING OF INTERSTATE GAS SUPPLY ARRANGEMENTS
NEW INTERSTATE GAS TRANSPORTATION AND PROCUREMENT ARRANGEMENTS
The Company's contract for firm sales service from PGT had entitled the Company to purchase up to 1,066 MMcf/d from PGT at Malin, Oregon. Effective November 1, 1993, the Company converted its firm sales service contract to firm transportation service of up to 1,066 MMcf/d. The firm transportation agreement runs through October 31, 2005. The firm transportation demand charge associated with the Company's firm capacity on PGT is approximately $50 million per year. To procure Canadian gas, the Company may contract on an individual basis for gas supply directly with any Canadian producer, aggregator or marketer. The Company currently purchases substantially all of its Canadian gas under flexible, short-term arrangements.
Following FERC approval of PGT's Order 636 compliance filing and pursuant to FERC rules on capacity relinquishment and release, the Company commenced capacity release on PGT's pipeline effective November 1, 1993. The Company retained approximately 610 MMcf/d on the PGT pipeline to support its service to core and core subscription customers. The Company made amounts not needed for core or core subscription service available for capacity release. The Company's release of its PGT capacity is also subject to the CPUC's capacity brokering program.
The Company's contract for firm sales service from El Paso had entitled the Company to purchase up to 1,140 MMcf/d from El Paso at Topock, Arizona. On September 1, 1991, the Company converted its firm sales service contract to firm transportation service of up to 1,140 MMcf/d. The firm transportation agreement runs through 1997. The firm transportation reservation charge associated with the Company's firm capacity on El Paso is approximately $130 million per year. The Company may contract on an individual basis for gas supply directly with any producer, aggregator or marketer of Southwest gas and currently purchases substantially all of its Southwest gas under flexible, short-term arrangements.
Pursuant to FERC rules on capacity relinquishment and release, the Company began brokering its capacity on the El Paso system effective August 1, 1993. The Company retained approximately 610 MMcf/d on the El Paso system to support its core and core subscription customers. The Company made amounts not needed for core or core subscription service available for capacity release. The Company's brokering of its El Paso capacity is also subject to the CPUC's capacity brokering program. During the period from August 1, 1993 to November 1, 1993, partial capacity brokering under the CPUC rules occurred. During this period, noncore customers who took assignment of the Company's brokered El Paso capacity received unbundled rates for intrastate service on the Company's system. The unbundled rates excluded the costs for the Company's El Paso and PGT capacity.
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 150 MMcf/d is to be used to meet the Company's gas demands and 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, effective November 1, 1993.
RECOVERY OF INTERSTATE TRANSPORTATION DEMAND CHARGES
Beginning November 1, 1993, when capacity release on both the PGT and El Paso systems was under way, full capacity brokering under the CPUC program went into effect. Under the full capacity brokering program, the Company's costs for interstate capacity on El Paso and PGT were unbundled from all the Company's rates for all noncore transportation service on its system. Noncore customers, or their gas suppliers, became responsible for the interstate transportation arrangements necessary to deliver gas at the Company's interconnections with the interstate pipelines. Under full capacity brokering, the Company continues to make its firm capacity on El Paso and PGT above the core and core subscription reservations, as well as capacity reserved for core and core subscription customers that is not being used to serve such customers' requirements at any given time, available for brokering to other potential shippers.
Interstate transportation service which cannot be marketed at the full rates 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. The Company has not succeeded in marketing its firm PGT or El Paso capacity above the core and core subscription reservations at the full cost of the capacity (the as-billed rate). The Company also has not been able to market all the El Paso and PGT capacity it has made available for brokering. Pursuant to the CPUC's ITCS mechanism, the Company has accumulated unrecovered demand charges for El Paso and PGT capacity in the ITCS.
Ultimate recovery of unrecovered interstate pipeline demand charges accumulated in the ITCS will be subject to CPUC ratemaking mechanisms. 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. Also, as described above (see "General -- Long-Term Gas Transportation Rates"), the Company has requested authorization to implement an optional long-term noncore gas transportation tariff. Under the Company's proposal, shareholders will bear the risk of any revenue shortfalls attributable to any differences between the long-term rate option and the customer's otherwise applicable rate. Accordingly, shareholders may bear the costs of any shortfall in recovery of ITCS costs contained in the otherwise applicable rate.
In July 1992, the CPUC issued a decision in its capacity brokering proceeding which denied the Company the authority to recover in gas rates at that time costs associated with 150 MMcf/d of Transwestern capacity prior to a prudence determination by the CPUC. Instead, those costs may be entered into a balancing account, subject to reasonableness review proceedings. The July 1992 decision did not address the Company's use of 50 MMcf/d on behalf of the electric department. The issue of the inclusion of the costs associated with the electric department's subscription to Transwestern capacity was raised in the Company's 1992 ECAC proceeding, but as a result of a settlement with the DRA, final resolution of the issue was deferred to a later reasonableness review proceeding. In the interim, the CPUC's decision in the ECAC case authorized the Company to record the demand charges incurred by the electric department in its ECAC balancing account, but such costs will not be recovered in electric rates until the CPUC makes a determination in a future reasonableness proceeding that the commitment to subscribe to the Transwestern capacity was prudent. Currently, the Company is not permitted to include any Transwestern firm capacity demand charges in the ITCS account.
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 electric department. The DRA asserted that the incremental
interstate 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 on account of noncore customers.
The Company is continuing its efforts to broker or assign its remaining interstate transportation capacity that is not used. Since the latter half of 1993 when implementation of capacity brokering began on interstate pipelines, including El Paso, PGT and Transwestern, the Company has been able to broker a significant portion of the unused capacity, including limited amounts of the capacity held for its core and core subscription customers when such capacity was not being used to serve those customers. Amounts brokered have been on a short-term basis, most of which were at a discounted price. The average monthly demand charges associated with the Company's unused interstate capacity have been approximately $10 million, of which the Company has been able to recover approximately 40% through capacity brokering during the past few months. Because the success of the Company's brokering efforts will depend on market demand, the Company cannot predict the volume or the price of the capacity that will be brokered in the future.
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 RECORD PERIOD
The CPUC has consolidated its review of the reasonableness of gas system costs for 1988 through 1990.
In September 1991, the DRA issued its report on the Company's Canadian gas procurement activities during 1988 through 1990. The DRA recommended that the Company refund approximately $392 million for the approximately three-year period from February 1988 to December 1990, based on its contention that the Company should have purchased 50% of its Canadian supplies on the spot market instead of almost totally relying on long-term contracts.
In addition to the recommendation on Canadian gas procurement, the DRA proposed a $37 million disallowance related to gas operations. The DRA contended that the Company should have withdrawn gas from storage in the winter of 1989-1990 and December 1990 instead of burning fuel oil, which was more expensive.
On March 16, 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 about 70% of its daily customer demand for gas from its then-existing Canadian gas suppliers, but that the Company could have met the remainder of its daily demand 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. The decision finds that the Company should have withdrawn more gas from storage during December 1990 for the electric department's generation and orders a disallowance of $8 million. The Company intends to file requests for rehearing of this decision and the decision on the Canadian gas procurement activities described above.
The decisions described above do not address an additional $18 million disallowance recommended by the DRA in connection with the Company's purchased power expenses for Pacific Northwest purchases during 1989 and 1990. In its September 1991 report on the Company's Canadian gas procurement activities during 1988 through 1990, the DRA noted that the Company purchased electric energy when it was cheaper than its incremental fossil fuel generation costs. However, the DRA argues that if cheaper Canadian gas supplies had been used then the Company's incremental fossil fuel generation costs would have been lower than the purchased power costs. The DRA has also sought permission to file additional testimony on the
effects of any imprudently incurred Canadian gas costs on certain of the Company's electric operations costs during the 1988 through 1990 record periods. On March 7, 1994, the ALJ granted the DRA's motion requesting the right to file testimony concerning prices for energy purchased from QFs and geothermal steam prices. The ALJ's ruling combines these issues with the outstanding Pacific Northwest purchased power issues into a separate phase of the reasonableness proceeding. Hearings on these issues have not yet been scheduled.
1991 RECORD PERIOD
In September 1992, the Company filed testimony to establish the reasonableness of its gas procurement and operating activities for 1991. In March 1993, the DRA issued its report on the reasonableness of those activities and recommended that the Company refund approximately $116 million in costs for that period.
The major recommended disallowance relates to the DRA's contention that the Company failed to pursue least-cost purchasing alternatives in acquiring Canadian gas supplies during the 1991 record period. The DRA calculated that the Company would have saved $105 million in gas costs if it had purchased 50% of its Canadian gas supply at spot market prices, and accordingly recommended that amount be disallowed. The DRA also asserted that the Company's electric department's procurement policies and decisions were strongly influenced by the Company's Canadian gas affiliate arrangements. The DRA indicated that although the electric department's excess costs are subsumed in the $105 million recommended disallowance for Canadian gas procurement activities, it recommended a disallowance of $15.8 million in electric department gas costs even if the Canadian gas costs are not deemed unreasonable, given the electric department's alleged failure to pursue least-cost procurement alternatives.
The DRA recommended an additional disallowance of approximately $2.4 million in connection with the Company's Southwest gas procurement activities during the 1991 record period. The DRA asserted that the Company imprudently incurred these additional costs by purchasing amounts in excess of minimum contract requirements at contract prices which were higher than spot market prices.
In addition, the DRA recommended an $8.5 million disallowance related to the Company's gas inventory operations. The DRA contended that the Company's operating assumptions regarding the quantity of gas to be reserved in storage for potential needs of residential customers under extreme weather conditions resulted in the electric department incurring excess costs as it had to burn higher priced fuel oil to generate electricity during the record period.
Hearings on the 1991 record period are scheduled for May 1994.
1992 RECORD PERIOD
In January 1994, the DRA issued its report on the reasonableness of the Company's gas procurement and operating activities for 1992 and recommended a disallowance of approximately $92 million in costs for that period.
The major recommended disallowance relates to the DRA's contention that the Company failed to pursue least-cost purchasing alternatives in acquiring Canadian gas supplies during the 1992 record period. The DRA calculated that the Company would have saved $60.5 million in gas costs if it had purchased 50% of its Canadian gas supply at spot market prices, and accordingly recommended that amount be disallowed. In addition, the DRA recommended a disallowance of approximately $5.1 million in connection with the Company's Southwest gas procurement activities during a three-month period in 1992 and a disallowance of $8.2 million related to the Company's gas inventory operations.
In its report, the DRA also 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 electric department. The DRA asserted that the incremental interstate 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 on account of noncore customers.
AFFILIATE AUDIT
In addition to challenging the prudence of the gas costs incurred by the Company under its Canadian gas supply arrangements, in 1992 the DRA also initiated an audit of the non-gas costs incurred by the Company's present and former Canadian affiliates.
In September 1993, the DRA distributed a report on its audit of A&S for the 1988 through 1991 period. The DRA report recommends that the CPUC impose a $50 million penalty on the Company and disallow approximately $6.2 million of primarily non-gas and administrative costs in 1991. The DRA has filed a motion asking that recommendations for the 1992 record period be made in a subsequent report. No action has been taken on this motion. In addition, the DRA has indicated that it will be filing in June 1994 a supplemental report addressing matters relating to the profitability of the Cochrane liquids extraction plant operated by the Company's former affiliate, ANG. The DRA has stated that the report will address the implications, if any, of ANG's status as an affiliate of the Company. In a previous report, the DRA had noted that a substantial portion of ANG's profits were derived from the operation of the Cochrane plant and that in part as a result of that profitability the Company had a pre-tax profit of $49 million from the sale of its ANG shares in 1992.
The DRA's proposed $50 million penalty relates primarily to its contention that the Company has committed serious lapses in the oversight of A&S. In particular, the DRA alleges that the Company failed to prevent A&S from passing through allegedly excessive and improper transportation and non-gas and administrative costs in A&S' cost of service. Based on its calculations, the DRA alleges that A&S contracted for excessive Canadian pipeline capacity on the pipeline systems of NOVA and ANG relative to the capacity necessary to service the Company's ratepayers. The DRA further argues that A&S misallocated its cost of service between the Company and its other customers resulting in cross-subsidies of Canadian customers by the Company's ratepayers. The Company filed its rebuttal testimony in March 1994. Hearings are scheduled in May 1994.
In December 1993, the ALJ denied a motion filed by the Company which had asked the CPUC to dismiss the penalty and disallowance because prior federal rulings approved such costs and thus preempt the issue.
In January 1994, the DRA filed with the CPUC a report on alleged conflicts of interest which discusses the stock holdings of certain officers and directors of A&S in companies from which A&S contracted for gas supplies that eventually flowed to California. In its report, the DRA indicates that it did not discover specific transactions resulting from the stock ownership which caused identifiable harm to California ratepayers. However, the DRA concluded that the stock ownership created the appearance of impropriety and that the interests may have created a disincentive for those officers to aggressively seek opportunities to drive down the price for gas paid to producers. The DRA's report also criticizes the Company for not taking sufficient action to ensure that A&S's conflicts threshold was as stringent as that which the Company employed in evaluating possible conflicts of interest of its employees.
The DRA's report does not request any specific disallowance associated with the conflicts of interest discussed in the report. Rather, the DRA argues that the Company's lack of oversight in this respect provides further evidence to support the $50 million penalty recommended in its September 1993 report on Canadian non-gas costs.
FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS
The Company recorded reserves of $61 million in 1993 and will accrue approximately an additional $90 million in the first quarter of 1994 as a result of the CPUC's disallowance in the 1988-1990 gas reasonableness proceedings and the Company's assessment of gas procurement activities in the periods 1991 through 1993.
The Company currently is unable to estimate the ultimate outcome of the gas reasonableness proceedings, including the affiliate audit, discussed above or predict whether such outcome will have a significant adverse 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. The 840-mile combined pipeline will provide an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 755 MMcf/d of firm capacity to Northern and Southern California. At December 31, 1993, the Company's total investment in the project was approximately $1,587 million. The $1,587 million consisted of $767 million for the facilities within California (i.e., intrastate portion) and $820 million for the facilities outside California (i.e., interstate portion).
The construction of facilities within the state of California has been certificated by the CPUC. The conditions of the certificate place the Company at risk for its decision to construct based on its assessment of market demand and for any potential underutilization of the facility. The certificate requires the application of a "cross-over" ban under which volumes delivered from the incremental interstate (PGT) expansion must be transported at an incremental intrastate 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 interstate portion 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 intrastate capacity, and the Company continues negotiations for the remaining capacity. The CPUC has authorized the Company to provide as-available service on the expansion project, which can provide additional revenues to recover the incremental costs of the expansion.
The CPUC certificate issued in December 1990 established a cost cap of $736 million for the California portion, which 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. In October 1993, the CPUC issued a decision granting the Company's motion to put in place temporary interim rates based on the existing cost cap of $736 million. The decision authorized the temporary interim rates to become effective on the date of commercial operation, November 1, 1993, and remain in effect for five months or until interim rates are established by the CPUC.
In February 1994, the CPUC announced a decision on the Company's request for an increase in the California portion of the expansion project's cost cap and its interim rate filing. 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 expansion project. In its decision, the CPUC also approved a one percentage point increase in the return on equity over the authorized return on utility operations in order to reflect the risk associated with the additional leverage of a capital structure of 70% debt and 30% equity for the California portion of the expansion project. The decision rejects assignment of unused capacity costs on other pipelines (or the Company's intrastate facilities) to the expansion project as previously proposed by an ALJ's proposed decision.
The FERC issued an order in October 1991 approving the interstate portion of the expansion project. However, concluding that PGT had not sufficiently demonstrated that shippers would not be subject to discriminatory restraints on access into California or on the interstate portion of the project as a result of the "cross-over" ban imposed by the CPUC, the FERC reduced PGT's approved rate of return on equity to 10.13% (from the 12.5% return previously approved) 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 1993, the FERC authorized an increase in the nominal return on equity to 12.75% from 12.5%, but reaffirmed the lower 10.13% return on equity it implemented as an incentive for PGT to seek removal of unduly discriminating restraints.
Based upon the current status of the cost cap and interim rate case at the CPUC and market demand, the Company believes it will recover its investment in the expansion project.
OTHER COMPETITIVE INTERSTATE PIPELINE PROJECTS
In 1992, several new gas pipeline projects were completed to serve the enhanced oil recovery market in Southern California and other customers. In March 1992, projects sponsored by Kern and the Mojave Pipeline Company (Mojave) commenced commercial operations. The projects involved construction of Kern's 700 MMcf/d pipeline from Wyoming to California, Mojave's 400 MMcf/d pipeline from Arizona border interconnection points with the El Paso and Transwestern systems to a point of interconnection with the Kern project in California, and a pipeline, jointly owned by Kern and Mojave, from the point of interconnection to the Bakersfield area. Also in 1992, 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 PGT/PG&E expansion project. Some of the gas available from the U.S. Southwest over these projects is priced equal to or lower than the current price of Canadian gas available over the PGT/PG&E expansion project, due in part to federal tax credits available for certain San Juan gas production.
Altamont Gas Transmission Company (Altamont) has proposed to build a pipeline that would transport gas from Alberta, Canada, to Wyoming, where it would interconnect with the Kern project. However, in July 1992, Altamont announced a one-year delay (to late 1994) in the scheduled completion of its proposed pipeline project.
In March 1993, Mojave 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 at Bakersfield, California, through California's Central Valley to Sacramento and the San Francisco Bay Area. Mojave's filing indicates that 433 MMcf/d of the firm service capacity provided by the proposed expansion will 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 April 1993, the CPUC issued a resolution asserting jurisdiction over the rates and services of Mojave and the facilities used by Mojave to transport gas received by Mojave in California and ultimately consumed in California. The CPUC also filed with the FERC a protest and motion to dismiss Mojave's application. The Company also filed a protest and motion to dismiss Mojave's application, arguing that the FERC should dismiss Mojave's application because the CPUC, and not the FERC, has jurisdiction to review Mojave's proposed expansion. The Company indicated in its filing that Mojave's proposed expansion would bypass the Company's existing gas network, taking business from the Company and requiring the Company to spread costs over a smaller customer base. The Company contended that Mojave's project would cost over $330 million (net present value) more than if the Company served the targeted customers, while reducing the economic welfare of the Company's remaining customers by over $325 million in present value terms.
In December 1993, the FERC held hearings in response to the Company's and the CPUC's requests to dismiss Mojave's pending pipeline expansion application. In February 1994, the FERC issued a decision asserting jurisdiction over Mojave's pending application. In March 1994, both the Company and the CPUC filed requests for a rehearing in this matter, arguing that the FERC erred in asserting jurisdiction. In addition, the Company requested that, if the FERC denies rehearing on the jurisdictional issues, the FERC hold a hearing to review the merits of Mojave's proposal and to establish a mechanism to reimburse the Company for costs arising from bypass associated with Mojave's proposed expansion.
STORAGE SERVICE
The Company has generally provided natural gas storage service only in conjunction with its procurement and transportation services. In an open season ending in January 1993, noncore customers indicated an interest
in obtaining unbundled storage service. In February 1993, the CPUC adopted policies and rules for permanent unbundled gas storage programs for noncore customers, and ordered the Company to submit a storage proposal in compliance with those policies. The Company's proposal regarding an unbundled storage program was submitted to the CPUC in July 1993 and hearings on the proposal were held in October and November 1993. CPUC authorization of an unbundled storage program for the Company is expected in the second quarter of 1994. Following authorization, the Company will hold an open season offering noncore customers short-term storage services from existing facilities and long-term storage services from expanded facilities.
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, 1993, 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 nine 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.
On July 9, 1992, the Company filed a license amendment request with the Nuclear Regulatory Commission (NRC) to change the operating license expiration dates for both units at Diablo Canyon. Diablo Canyon Units 1 and 2 are currently licensed to operate for 40 years commencing on the date the construction permit for the respective unit was issued, which occurred in 1968 and 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. The Company's request seeks to utilize that policy change, and if granted, would extend the operating license expiration date for Unit 1's license from April 2008 to September 2021 and the expiration date for Unit 2's license from December 2010 to April 2025.
In August 1992, a group intervened in opposition to the license amendment and requested hearings at the NRC. In October 1992, the intervenor group supplemented its petition with a request that eleven contentions be admitted for hearing. The Company and the NRC staff responded to the intervention petition and its supplement, asserting that the intervenors lack standing and none of the contentions are admissible. In January 1993, an NRC licensing board issued its order granting the intervenors standing and admitting for hearings two of the eleven contentions filed by the intervenors. The two admitted contentions relate to the Company's maintenance program for Diablo Canyon and the adequacy of the Company's implementation of certain compensatory measures approved by the NRC to address issues relating to a fire-barrier material known as Thermo-Lag pending NRC/industry resolution of those issues. Hearings were completed in August 1993. In February 1994, the intervenor group filed a motion to reopen the record in the proceeding in order to take evidence on an NRC inspection issue which the intervenor group alleges represents significant new information regarding deficiencies in the Company's maintenance of the plant's auxiliary saltwater system. Both the Company and the NRC staff have replied to the motion, urging it be rejected. A decision by the NRC licensing board on the motion to reopen is expected in the next few months, and a decision on the Company's license amendment request is expected in 1994.
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL I and II). 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
assessments of $21 million (property damage) or $7 million (business interruption), in each case per policy period, if losses exceed premiums, reserves and other resources of NML, NEIL I or NEIL II.
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 $9.4 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.
DIABLO CANYON SETTLEMENT
The Diablo Canyon rate case settlement adopts 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 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. Total prices for the years 1993 through 1994, effective January 1 of each year, are 11.16 cents and 11.89 cents per kWh, respectively. For 1995 through 2016, 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 settlement provides that certain Diablo Canyon costs, including decommissioning costs, be recovered over the term of the settlement, including a full return on such costs through base rates.
In March 1993, the CPUC denied a petition filed in September 1992 by a consumer advocacy group seeking to modify the CPUC's 1988 decision that adopted the Diablo Canyon rate case settlement. The petition contended that the Company has made unreasonably high profits because of the better-than-expected operating performance of Diablo Canyon. The petition did not propose any specific change to the Diablo Canyon rate provisions, but requested that the CPUC reopen the Diablo Canyon settlement to consider mechanisms for sharing with ratepayers additional benefits of Diablo Canyon's performance.
The CPUC found that there had been no failure in the underlying assumptions of the settlement and that reopening the settlement would be contrary to the public policy in favor of settlements. Although all four CPUC Commissioners voted to deny the petition, CPUC President Fessler indicated in his concurring opinion that he was concerned about the high electricity rates paid by all classes of ratepayers and would consider reopening the settlement if the Company does not reduce its rates within a year.
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 1994, 1996 and 1998, respectively. The Company is currently negotiating contracts for 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 (the Act), the DOE is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level waste. The 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 Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The 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 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.
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, 1993, the amount recovered in rates for
decommissioning costs was $54 million. The estimated total obligation for decommissioning costs is approximately $1 billion in 1993 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, 1993, the Company had accrued $537 million in accumulated depreciation and decommissioning and had accumulated that amount in external trust funds, to be used for the decommissioning of the Company's nuclear facilities. 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 principal non-utility unregulated 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 the Bechtel Group, Inc. is the other general partner of USGen. USGen develops and manages non-utility electric generation facilities which 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 seven operational plants and eight projects under construction or in advanced stages of development (with power sales agreements). Enterprises' share of capacity from those projects is approximately 1,515 MW. The projects are typically financed with a combination of equity commitments from the project sponsors and non-recourse debt. USGen also manages Enterprises' 39.9% limited partnership interest in Sycom Enterprises, which offers energy conservation services.
GAS AND OIL EXPLORATION AND PRODUCTION
Resources, 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 January 1994, the Company approved a final plan for the disposition of Resources in 1994 if market conditions remain favorable. The Company has retained Goldman, Sachs & Co. to advise it with respect to possible alternatives for the divestiture of Resources. In February 1994, Resources filed with the Securities and Exchange Commission a proposed S-1 registration statement with respect to one of these options. This option involves an initial public offering of all of the stock of Resources' parent holding company, PG&E Resources Holdings Company, which would be renamed Dalen Resources Corp. prior to the offering. Such an offering would be preceded by the transfer of Resources' non-strategic properties to a newly-formed subsidiary of Enterprises for disposition by sale. As of December 31, 1993, Resources had assets of approximately $680 million.
POWER PLANT OPERATING SERVICES
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.
REAL ESTATE DEVELOPMENT
PG&E Properties, Inc. (Properties) develops real estate in the Company's service territory, focusing on residential lot creation. It also develops offices, industrial buildings, retail outlets and apartments. Properties is wholly owned by Enterprises.
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 projected expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. Capital expenditures for environmental protection are currently estimated to be approximately $50 million, $50 million, $75 million, $95 million and $75 million for 1994, 1995, 1996, 1997 and 1998, respectively, and are included in the Company's five-year projection 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.
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 have adopted final rules to reduce NOx emissions from these plants.
The three agencies that have adopted utility boiler NOx rules are the Monterey Bay Unified Air Pollution Control District (Rule 431 adopted September 15, 1993), the San Luis Obispo County Air Pollution Control District (Rule 429 adopted November 16, 1993) and the Bay Area Air Quality Management District (Regulation 9, Rule 11 adopted February 16, 1994). These rules prescribe emission limitations for the Company's Contra Costa, Hunters Point, Moss Landing, Morro Bay, Pittsburg and Potrero power plants. In each district, other NOx rules have been or will be adopted to regulate other NOx sources.
Because the Company's power plants operate as a system, the three agencies coordinated their NOx rulemakings. Together, the rules require a reduction in NOx emissions of approximately 90% from the power plants by 2004 (with numerous interim compliance deadlines). The first major retrofit is scheduled to begin in 1996. Certain retrofits will not be required if the smaller generating units are operated for emergency purposes only after 2000. Rule 431 also requires the Company to provide a total of $7 million to the Monterey Bay Unified Air Pollution Control District in 1994 and 1995 for emission reduction projects not related to Company sources. Rule 429 may 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 to $500 million over 10 years, depending on assumptions about fuel use and unit retirement. Ongoing business and engineering studies could change this estimate. In the Company's 1993 GRC, the CPUC authorized NOx related plant additions of approximately $70 million for 1993, and established an Air Quality Adjustment (AQA) mechanism under which the Company may seek cost recovery in rates for NOx reduction projects beyond January 1, 1994. However, in its RRI filing (see "General -- Regulatory Reform Initiative" above) the Company has proposed that the AQA mechanism be terminated as of January 1, 1995.
In the San Luis Obispo County Air Pollution Control District, the Company obtained permits to install the first phase of NOx emission reductions at the Morro Bay Power Plant, thereby commencing implementation of NOx reductions in that district. The Company spent $48 million for the first phase of this NOx reduction project, which has been completed.
The Company operates both reciprocating engine and gas turbine drivers at its natural gas compressor stations. They are located in local air districts whose attainment plans call for reductions in emissions of exhaust pollutants over the next few years. On December 20, 1993, the Mojave Desert Air Quality Management District adopted a rule that will require a reduction in NOx emissions of approximately 90% from the Hinkley Compressor Station by January 1, 1998. The Topock Compressor Station is currently exempt from this rule. The San Joaquin Valley Unified Air Pollution Control District expects to adopt a similar rule during 1994 that would require a reduction in NOx emissions of approximately 90% from the Kettleman Compressor Station by January 1, 1999. The Company currently estimates that compliance with these NOx rules could require capital expenditures of approximately $55 million over five years.
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, which must be met by January 1, 1995, are being incorporated in local air quality rules. The air monitoring rules will require the installation of monitoring equipment to measure emissions from the fossil fuel fired generating plants. The Company currently estimates that the cost of complying with the monitoring requirements will total approximately $29 million in 1994 and 1995.
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 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 two offshore moorings, three docks, approximately 103 large aboveground fuel tanks with a capacity of approximately 16,000,000 barrels and approximately 45 miles of fuel pipelines. These facilities are used for the transport, handling and storage of residual fuel oil and diesel, both of which are used at the Company's power plants and facilities.
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 1994 and 1995 are estimated to be approximately $4 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 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 co-ops 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 1994 and 1995 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 1994 and 1995.
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 either is upgrading the existing ponds or closing the old ponds and building new evaporation ponds that meet new standards for leak monitoring, detection and containment. Capital expenditures for this work in the years 1994 and 1995 are estimated to be approximately $9.9 million. Closure and post-closure expenditures for these ponds, including remediation and cost contingencies, may approximate $20 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 1994 and 1995 are estimated to be approximately $4.8 million.
A third program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by 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 30 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 $15.5 million over the period 1994 through 1995. The full long-term costs cannot be determined accurately until a closer study of each site or facility 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.
The Company may be required to take remedial action at certain disposal sites and retired manufactured gas plant sites if they are determined to present a significant threat to human health or the environment because of an actual or potential release of hazardous substances. The Company has been designated as a potentially responsible party (PRP) under CERCLA, the federal Superfund law, with respect to the Purity Oil Sales site in Malaga, California; the 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 Company has been named as a PRP under the California Hazardous Substance Account Act (California Superfund law) with respect to the Martin Service Center former gas plant site and the Midway/Bayshore sites in Daly City, California; the Berman Steel site in Salinas, California; the Emeryville Service Center site in Emeryville, California; the GBF Land Fill at Pittsburg, California; the former Sacramento gas plant site in Sacramento, California; the former San Rafael gas plant site in San Rafael, California; and the former Monterey gas plant site in Monterey, California. Although the Company has not been formally designated a PRP with respect to the Geothermal, Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed the Company and other parties to initiate measures with respect to the study and remediation of that site. In addition, 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 Company will perform a groundwater remedial action at its former Sacramento manufactured gas plant site during 1994, at a cost of up to $4 million. The DTSC must approve the groundwater remedial action design plan proposed for this site before it is implemented.
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, 1993, of $60 million for hazardous waste remediation costs. The ultimate amount of such costs may be significantly higher 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
Generally, the Company seeks recovery of hazardous waste compliance costs in the GRC. However, as part of the Company's 1987 GRC, the CPUC established a separate procedure through which the Company may receive ratepayer recovery of reasonable hazardous waste remediation costs incurred at certain historic hazardous waste sites. The CPUC indicated that it was establishing this procedure because the amount and timing of certain hazardous waste remediation expenditures was difficult to forecast in the context of the GRC. This procedure entails obtaining CPUC approval by advice letter prior to incurring any costs, as well as filing an application periodically with the CPUC for recovery of the amounts expended, subject to a review of the reasonableness of the expenditures.
The Company currently has received approval of advice letters totaling approximately $22.5 million, has filed two additional advice letters for approval, and expects to file additional requests for specific projects in 1994 and 1995. Amounts authorized by advice letters and subsequently spent by the Company may be collected from ratepayers only after a reasonableness review of the associated projects.
In November 1992, the CPUC issued a decision in Southern California Gas Company's (SoCal Gas) environmental reasonableness proceeding deferring a decision on rate recovery of remediation costs incurred by SoCal Gas and instead requesting comments on incentive and/or cost sharing mechanisms for the ratemaking treatment of hazardous waste remediation costs as an alternative to the current reasonableness review of such expenses.
In response to the CPUC's request and as a result of a collaborative effort, in November 1993, the Company and various interested parties, including the DRA and other California utilities, filed a report with the CPUC in connection with the SoCal proceeding, which proposes a cost sharing mechanism for the ratemaking treatment of hazardous waste remediation costs. The proposed mechanism would assign 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 would have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. The parties supporting the proposed mechanism, including the Company, also filed a settlement, requesting that the mechanism be adopted only in its entirety. A special interest group opposes the proposed mechanism. The CPUC has authority to adopt the proposed mechanism, reject it, suggest certain changes to the proposed mechanism, schedule hearings on the issues it considers relevant, or send the parties back for further negotiations until they reach a consensus. On March 10, 1994, the assigned ALJ issued a proposed decision adopting the settlement and proposed mechanism. A final CPUC decision is expected in 1994.
The CPUC has put all parties on notice that the mechanism adopted for SoCal Gas may be applied to other utilities. Accordingly, a final decision in this proceeding is expected to establish the method by which the CPUC addresses similar issues in the Company's pending environmental reasonableness proceeding, which has been postponed indefinitely pending a decision in the SoCal Gas case. In the Company's environmental reasonableness proceeding, the Company seeks to recover approximately $10.2 million in costs for two environmental projects -- the Antioch Service Center site and the Sacramento Gas Plant site. However, in its RRI filing (see "General -- Regulatory Reform Initiative" above), the Company requests to withdraw its participation in the collaborative report and recommendation, the pending settlement and the Company's pending environmental reasonableness application if the CPUC approves the Company's RRI application.
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. However, under the Company's proposed RRI, the specific rate mechanism for recovery of these costs would be discontinued at the end of 1994. As of December 31, 1993, the Company has a deferred charge of $61 million for most 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, the CPUC created a 17-member EMF Consensus Group, with representatives from government, utilities (including a representative from the Company), organized labor and the public. The Consensus Group submitted to the CPUC its recommendations for a CPUC interim policy on EMF, which were considered during evidentiary hearings held in December 1992. 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 commerical buildings.
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.
LOW EMISSION VEHICLE (LEV) PROGRAMS
In October 1991, the CPUC issued an Order Instituting Investigation/Order Instituting Rulemaking on 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 the LEV proceeding were conducted in August 1991, 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 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 November 1993, the Company filed an application for approximately $200 million in funding for the Company's fleet and market development activities for NGVs and EVs over the six-year period. However, in its RRI filing (see "General -- Regulatory Reform Initiative" above), the Company requests permission to withdraw the funding request portion of its LEV application if the CPUC approves the Company's RRI proposal.
In July 1991, the CPUC approved the implementation of the Company's NGV market development program as proposed by the Company, and authorized initial funding for the program. 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 2,000 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.
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.
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 2026 and involving a total normal operating capability of 2,684 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 three of the Company's projects. Federal legislation enacted in 1986 has eliminated any preference for governmentally-run utilities in the relicensing of hydroelectric projects.
The 1986 law requires the Company to pay these challengers 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 projects. In return, the challengers are required to withdraw their competing license applications. The FERC has approved the settlement agreement for one project. The
challengers for the other two projects have filed with the FERC to assert claims amounting to approximately $100 million, including 100% of the Company's net investment in the projects of approximately $89 million. In October 1991, the FERC approved a partial settlement agreement between the Company and one of the challengers which, among other things, required the Company to provide additional load following services under a power sale agreement and pay approximately $2 million to settle the challenger's claims related to both projects of approximately $40 million. In October 1992, the FERC issued an order requiring the Company to pay compensation of $1.9 million to the remaining challengers for the two projects, representing the costs incurred preparing their applications. The FERC declined to award the remaining challengers any additional compensation. In December 1992, the challengers filed with FERC a request for rehearing of the compensation order. In February 1993, the FERC reaffirmed the award and rejected the challengers' request for additional compensation. The challengers have appealed FERC's order to the U.S. Court of Appeals. The Company expects to recover the costs of FERC-awarded compensation and the partial settlement 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.
NATURAL GAS PURCHASE CONTRACTS LITIGATION
In connection with the implementation of the Decontracting Plan described above (see "Gas Utility Operations -- Restructuring of Canadian Supply Arrangements -- Decontracting Plan") in November 1993, the Canadian gas producers party to the Decontracting Plan released A&S, PGT and the Company from any claims they may have had that resulted from the termination of A&S' former Canadian gas purchase arrangements as well as any claims for losses which arose from alleged historical shortfalls in gas taken by A&S. Accordingly, the lawsuits filed by Amoco Canada Petroleum Company Ltd. and Amoco Canada Resources Ltd. (Amoco), Shell Canada Limited (Shell), Chevron Canada Resources (Chevron), Gulf Canada Resources Limited and Gulf Canada Frontier Exploration Limited (Gulf), and Scurry-Rainbow Oil Limited, Opinac Exploration Limited, Norco Resources Limited and Hershey Oil Corporation (North Coleman Producers) were each discontinued under Canadian Law.
QF TRANSMISSION CONSTRAINED AREA LITIGATION
The Company was a defendant in three lawsuits concerning the existence, nature and extent of transmission constraints in the northern portion of the Company's service area, and whether the Company improperly used those transmission constraints and adopted policies and practices to defeat QF development. The plaintiffs all signed power purchase agreements with the Company for the sale of power from proposed projects that were to have been located in the northern portion of the Company's system. All of the power purchase agreements contained a provision stating that they would terminate if energy deliveries from the proposed projects did not begin within five years of the execution date of the agreement. None of the plaintiffs delivered power within those deadlines.
The first case was filed in Fresno County Superior Court by Griswold Creek Joint Power Authority, Tranquility Irrigation District, Thermalito Irrigation District, Table Mountain Irrigation District and Concow Power Authority (collectively, Griswold Creek). The second and third cases were filed in San Francisco County Superior Court by Pacific Oroville Power, Inc. (POPI) and Robert F. Tamaro, doing business as Power Project Ventures (Tamaro), respectively. The three cases had been coordinated in the San Francisco County Superior Court by order of the California Judicial Council, at the Company's request, with trial set for September 1993.
The September trial date was suspended while the parties pursued settlement discussion. The Griswold Creek and Tamaro cases were settled in October and November 1993, respectively. Trial of the POPI case, which commenced November 1, 1993, is expected to continue for at least six months.
Plaintiff in the POPI case contends that: the Company misrepresented to the CPUC and to QFs its transmission capacity; the existence of transmission constraints extends the five-year deadline in the agreements; the Company was obligated to build transmission upgrades at utility (non-QF) expense which it failed to build; and the Company had a general goal of trying to stifle QF development. The POPI suit alleges breach of contract, negligent misrepresentation, misrepresentation, breach of the implied covenant of good faith and fair dealing, unfair business practices and negligent interference with prospective economic advantage, and seeks declaratory relief, damages, injunctive relief and relief from forfeiture. The POPI complaint seeks compensatory damages "according to proof," together with interest, attorneys' fees and costs of suit. While the complaint makes no mention of any dollar amount of compensatory damages, the plaintiff's damage expert has given a preliminary estimate of damages sought of $67 million. POPI also seeks an unspecified amount of punitive damages.
If the trial of the POPI case results in an outcome adverse to the Company, there are other similarly-situated QFs which might choose to file similar complaints. How many such additional complaints might be filed will likely depend on the basis for any adverse decision in the POPI case. The Company believes that the matter has no merit and that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations.
AIR DISTRICT RULEMAKING PROCEEDINGS
See "Environmental Matters and Other Regulations -- Environmental Matters -- Environmental Protection Measures" above for a description of proceedings pending before local air districts in California relating to NOx emission reduction requirements.
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.
The Company believes the case is without merit and has filed a motion to dismiss the complaint. 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 add additional individuals for a total of 178 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.
In November 1993, the parties engaged in private mediation sessions. On December 20, 1993, the plaintiffs filed an offer to compromise and settle their claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter, but such outcome could have a significant adverse impact on the Company's results of operations. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
EXECUTIVE OFFICERS OF THE 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 47 under the heading "Quarterly Consolidated Financial Data" in the Company's 1993 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 1993 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 24 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the Company's 1993 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 1993 Annual Report to Shareholders on page 48 and pages 25 through 47 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 1994 Proxy Statement relating to the 1994 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 17 under the heading "Executive Compensation" in the 1994 Proxy Statement relating to the 1994 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 18 under the headings "Security Ownership of Management" and "Principal Shareholders" in the 1994 Proxy Statement relating to the 1994 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 1994 Proxy Statement relating to the 1994 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 1993 Annual Report to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31, 1993, 1992 and 1991.
Consolidated Balance Sheet as of December 31, 1993 and 1992.
Statement of Consolidated Cash Flows for the Years Ended December 31, 1993, 1992 and 1991.
Statement of Consolidated Common Stock Equity and Preferred Stock for the Years Ended December 31, 1993, 1992 and 1991.
Statement of Consolidated Capitalization as of December 31, 1993 and 1992.
Schedule of Consolidated Segment Information for the Years Ended December 31, 1993, 1992 and 1991.
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:
V -- Consolidated Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991.
VI -- Accumulated Depreciation of Consolidated Plant in Service for the Years Ended December 31, 1993, 1992 and 1991.
VIII -- Consolidated Valuation and Qualifying Accounts for the Years Ended December 31, 1993, 1992 and 1991.
IX -- Consolidated Short-term Borrowings for the Years Ended December 31, 1993, 1992 and 1991.
X -- Consolidated Supplementary Income Statement Information for the Years Ended December 31, 1993, 1992 and 1991.
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 November 18, 1992 (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit 4.1).
3.2 Certificate of Determination of Preferences of 7.04% Redeemable First Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit 4.2).
3.3 Certificate of Determination of Preferences of 6 7/8% Redeemable First Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit 4.3).
3.4 Certificate of Decrease in Number of Shares of Certain Series of First Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit 4.4).
3.5 Certificate of Determination of Preferences of 6.30% Redeemable First Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit 4.5).
3.6 By-Laws dated October 1, 1993.
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 Master Agreement for the Assignment of Service between the Company and NOVA Corporation of Alberta dated September 1, 1993 and schedule A.
10.2 Service Agreement Rate Schedule FS between the Company and NOVA Corporation of Alberta dated October 1, 1993, rate schedule FS, and general terms and conditions.
10.3 Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FS-1 between the Company and Alberta Natural Gas Company LTD dated September 22, 1993, statement of effective rates and charges effective November 1, 1993, service schedule FS-1, and general terms and conditions.
10.4 Firm Transportation Service Agreement between the Company and Pacific Gas Transmission Company dated October 26, 1993, rate schedule FTS-1, and general terms and conditions.
10.5 Transportation Service Agreement as Amended and Restated Between the Company and El Paso Natural Gas Company dated November 1, 1993, rate schedule T-3, and general terms and conditions.
10.6 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).
*10.7 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5).
*10.8 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6).
*10.9 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to management employees, effective January 1, 1994.
- --------------- * 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.
*10.10 Performance Incentive Plan of Pacific Gas and Electric Company.
*10.11 The Pacific Gas and Electric Company Retirement Plan applicable to management employees, effective January 1, 1994.
*10.12 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).
*10.13 Pacific Gas and Electric Company Stock Option Plan, as amended effective as of September 16, 1992.
*10.14 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13).
*10.15 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.16 Pacific Gas and Electric Company Executive Flexible Perquisites Program.
*10.17 Management Contract with Jerry R. McLeod (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.18).
*10.18 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.19 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).
*10.20 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).
*10.21 Contract For Performance of Work Between George A. Maneatis and Pacific Gas and Electric Company (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.20).
*10.22 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, 1994 (File No. 1-2348), Exhibit 11).
12.1 Computation of Ratios of Earnings to Fixed Charges (Form 8-K dated March 2, 1994 (File No. 1-2348), Exhibit 12.1).
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends (Form 8-K dated March 2, 1994 (File No. 1-2348), Exhibit 12.2).
13. 1993 Annual Report to Shareholders (portions of the 1993 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Information," "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 1993 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 & Co.
24.1 Resolution of the Board of Directors authorizing the execution of the Form 10-K.
24.2 Powers of Attorney.
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, 1993 and through the date hereof:
1. October 14, 1993
Item 5. Other Events.
-- Restructuring of Canadian Gas Purchase Obligations
-- California Public Utilities Commission (CPUC) Proceedings
Canadian Affiliates Audit
Workforce Reduction Memorandum Account
1994 Attrition Rate Adjustment
Electric Reasonableness Proceeding
-- PGT/PG&E Pipeline Expansion Project
2. October 25, 1993
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- Regulatory Reform Initiative
-- Medium-Term Note Program
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits.
3. November 4, 1993
Item 5. Other Events.
-- Restructuring of Canadian Gas Purchase Obligations
-- California Public Utilities Commission Proceedings
1994 Cost of Capital Proceeding
CPUC Denial of Petition to Modify General Rate Case
-- PGT/PG&E Pipeline Expansion Project
4. November 17, 1993
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- California Public Utilities Commission Proceeding -- 1988-1990 Reasonableness Proceeding
-- QF Constrained Area Litigation
5. December 7, 1993
Item 5. Other Events.
-- Antitrust Litigation
-- California Public Utilities Commission Proceeding
1994 Cost of Capital Proceeding
Hazardous Materials and Hazardous Waste Compliance and Remediation
6. December 23, 1993
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
7. January 10, 1994
Item 5. Other Events.
-- Performance Incentive Plan -- 1994 Target
-- California Public Utilities Commission Proceedings
Electric Fuel and Sales Balancing Accounts
1994 Attrition Rate Adjustment
8. January 24, 1994
Item 5. Other Events.
-- Performance Incentive Plan -- 1993 Financial Results
-- 1993 Consolidated Earnings (unaudited)
-- Common Stock Dividend
-- Potential Sale of PG&E Resources Company
-- Hinkley Compressor Station Litigation
9. March 2, 1994
Item 5. Other Events.
-- California Public Utilities Commission Proceedings
PGT-PG&E Expansion Project
1992 Reasonableness Proceeding-DRA Recommendation
1988-1990 Reasonableness Proceeding -- Non-Canadian Gas Phase
Item 7. Financial Statements, Pro Forma Information and Exhibits.
-- 1993 Financial Statements
-- Ratios of Earnings to Fixed Charges
-- Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
-- Exhibits
10. March 11, 1994
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- California Public Utilities Commission Proceedings
Regulatory Reform Initiative
1988-1990 Reasonableness Proceeding -- Canadian Issues
1988-1990 Reasonableness Proceeding -- Non-Canadian Issues
11. March 25, 1994
Item 5. Other Events.
-- California Public Utilities Commission Proceedings -- Gas Reasonableness Proceedings
-- Preferred Stock Offering
Item 7. Financial Statements, Pro Forma Financial Information and 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 28TH DAY OF MARCH, 1994.
PACIFIC GAS AND ELECTRIC COMPANY (Registrant)
By BRUCE R. WORTHINGTON (Bruce R. Worthington, 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 BRUCE R. WORTHINGTON (Bruce R. Worthington, 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 16, 1994. Our report on the 1993 consolidated financial statements includes explanatory paragraphs that describe the uncertainties regarding the ultimate outcome of the gas reasonableness proceedings, the recovery of certain Helms costs and revenues and the Hinkley litigation, as discussed in notes 2 and 11 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 and income taxes as discussed in notes 1 and 7 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 schedules listed in Part IV, Item 14. (a)(3) of this Annual Report on Form 10-K are the responsibility of the Company's management and are presented for the purpose of complying with the Securities and Exchange Commission's rules and are not part of the consolidated financial statements. These supplemental schedules have 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 state 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 & CO.
ARTHUR ANDERSEN & CO.
San Francisco, California February 16, 1994
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
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SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
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SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
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(1) Electric tangible cost at December 31, 1991 includes approximately $5.9 billion related to the Diablo Canyon Nuclear Power Plant, substantially all in electric production.
(2) Additions are net of transfers of property to plant in service.
(4) Other changes consist of:
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1993
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See Note 1 of Notes to Consolidated Financial Statements in the 1993 Annual Report to Shareholders for the accounting policy with respect to plant in service and depreciation.
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1992
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See Note 1 of Notes to Consolidated Financial Statements in the 1993 Annual Report to Shareholders for the accounting policy with respect to plant in service and depreciation.
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1991
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(1) Electric accumulated depreciation at December 31, 1991 includes approximately $1.2 billion related to the Diablo Canyon Nuclear Power Plant, substantially all in electric production.
See Note 1 of the Notes to Consolidated Financial Statements in the 1993 Annual Report to Shareholders for the accounting policy with respect to plant in service and depreciation.
SCHEDULE VIII
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VIII -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
- --------------- (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.
SCHEDULE IX
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE IX -- CONSOLIDATED SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
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(1) The general terms of aggregate short-term borrowings are described in Note 6 of Notes to Consolidated Financial Statements in the 1993 Annual Report to Shareholders.
(2) Calculated using a monthly average.
SCHEDULE X
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE X--CONSOLIDATED SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
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Amounts charged to expense for royalties, advertising costs, and miscellaneous taxes are not set forth inasmuch as such items do not exceed one percent of total revenues as shown in the related Statement of Consolidated Income.
Amounts charged to expense for maintenance and repairs and depreciation and amortization of intangible assets, preoperating costs, and similar deferrals are not set forth inasmuch as the information is included in the Consolidated Financial Statements or Notes thereto.
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
EXHIBITS
TO
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1993
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PACIFIC GAS AND ELECTRIC COMPANY
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INDEX TO EXHIBITS
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* 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.
INDEX TO EXHIBITS--(CONTINUED)
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*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.