-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, qE0ojhSvh4xKs6xGq0PPh5vuIAaXotWnR1afviufnSnIaN9HoRnW4QAtjYAyGJC1 lVmrGeK+Tsp63Xu3Zdmrdg== 0000950149-95-000092.txt : 19950608 0000950149-95-000092.hdr.sgml : 19950608 ACCESSION NUMBER: 0000950149-95-000092 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19950302 ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 19950302 SROS: AMEX SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFIC GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000075488 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 940742640 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02348 FILM NUMBER: 95517963 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 MAIL CODE B7C CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4159737000 8-K 1 FORM 8-K DATED MARCH 2, 1995 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report: March 2, 1995 PACIFIC GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) California 1-2348 94-0742640 - ------------------------------------------------------------------------- (State or other juris- (Commission (IRS Employer diction of incorporation) File Number) Identification Number)
77 Beale Street, P.O.Box 770000, San Francisco, California 94177 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (415) 973-7000 2 Item 7. Financial Statements, Pro Forma Financial Information And Exhibits A. 1994 Financial Statements Copies of the following documents are attached hereto as Appendix I and incorporated herein: (i) the selected financial data; (ii) management's discussion and analysis of consolidated results of operations and financial condition; (iii) audited consolidated balance sheet and statement of consolidated capitalization of Pacific Gas and Electric Company and subsidiaries as of December 31, 1994 and 1993, and the related statements of consolidated income, cash flows, common stock equity and preferred stock, and the schedule of consolidated segment information for each of the three years in the period ended December 31, 1994, and related notes to consolidated financial statements, and supplementary financial information, and (iv) the report dated February 6, 1994, of Arthur Andersen LLP, independent public accountants, with respect to the consolidated financial statements and schedule of consolidated segment information. B. Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends The Company's earnings to fixed charges ratio for the year ended December 31, 1994 was 3.43. The Company's earnings to combined fixed charges and preferred stock dividends ratio for the year ended December 31, 1994 was 3.03. Exhibits: 11 Computation of Earnings per Common Share 12.1 Computation of Ratios of Earnings to Fixed Charges 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 23 Consent of Arthur Andersen LLP 27 Financial Data Schedule
3 SIGNATURE Pursuant to the requirements 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. PACIFIC GAS AND ELECTRIC COMPANY By THOMAS C. LONG ------------------------------ THOMAS C. LONG Controller Dated: March 2, 1995 4 Appendix I Pacific Gas and Electric Company SELECTED FINANCIAL DATA (in thousands, except per share amounts)
1994 1993 1992 1991 1990 FOR THE YEAR Operating revenues $10,447,351 $10,582,408 $10,296,088 $ 9,778,119 $ 9,470,092 Operating income 1,633,359 1,762,930 1,833,441 1,713,079 1,706,136 Net income 1,007,450 1,065,495 1,170,581 1,026,392 987,170 Earnings per common share 2.21 2.33 2.58 2.24 2.10 Dividends declared per common share 1.96 1.88 1.76 1.64 1.52 AT YEAR END Book value per common share $20.07 $19.77 $19.41 $18.40 $17.86 Common stock price per share 24.38 35.13 33.13 32.63 25.00 Total assets 27,809,133 27,162,526 24,188,159 22,900,670 21,958,397 Long-term debt and preferred stock with mandatory redemption provision (excluding current portions) 8,812,591 9,367,100 8,525,948 8,341,310 7,902,409
Matters relating to certain data above are discussed in Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition and in Notes to Consolidated Financial Statements. 12 5 Pacific Gas and Electric Company MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION Pacific Gas and Electric Company (PG&E) and its wholly owned and majority-owned subsidiaries (collectively, the Company) have three types of operations: utility, Diablo Canyon Nuclear Power Plant (Diablo Canyon) and nonregulated through PG&E Enterprises (Enterprises). The Company is engaged principally in the business of supplying electric and natural gas service throughout most of Northern and Central California. The Company's operations are regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC), among others. Competition and Changing Regulatory Environment: Recent changes in both the gas and electric industries have allowed competition to develop in the gas supply and electric generation segments of the Company's business. A number of reforms at both the federal and state level have been proposed. These reforms are designed to restructure regulation in the energy supply industry and promote competition by providing electric and gas customers with purchasing options. As a result of the restructuring of the natural gas industry, the Company no longer provides combined purchase and transportation services to many of its industrial and large commercial gas customers. Instead, most of these customers now procure their gas supplies from a source other than the Company while purchasing transportation service from the Company. These customers can also use alternative transportation services available within the Company's service territory. In November 1994, the FERC approved the expansion of a competing company's natural gas pipeline into the Company's service territory. This pipeline could compete directly for transportation service to several of the Company's large customers as soon as January 1, 1996, and may result in the loss of sales on the Company's gas transportation system. While the restructuring of the electric industry is still evolving, proposals being considered are expected to bring increased competition into the electric generation business. At the federal level, the National Energy Policy Act of 1992 (Energy Act) reduces various restrictions on the operation and ownership of independent power producers and provides them and other wholesale suppliers and purchasers with increased access to electric transmission lines throughout the United States. At the state level, in April 1994, the CPUC issued a proposal on electric industry restructuring which seeks to lower energy prices and provide customers with a choice of electric generation suppliers (known as direct access). This proposal involves two key strategies: One, phase in direct access to electric generation for all customers over a six-year period beginning in 1996; two, where competition does not exist, replace traditional cost-of-service regulation with performance-based regulation (PBR). To ensure a transition that maintains the financial integrity of the utilities, the CPUC proposed that uneconomic costs of utility generating assets resulting from its proposal be recovered through a "competition transition charge." However, the CPUC proposal did not specify which costs might be recovered through such a transition charge or how such a charge would be allocated to and collected from customers. The Company has filed a response to the CPUC proposal embracing the objective of lower prices and supporting increased competition, but recommending a longer phase-in period to direct access to permit an orderly transition. Based on market prices of $.048 and $.032 per kilowatthour (kWh), the Company estimated that its uneconomic generating assets and obligations are approximately $3 billion and $11 billion, respectively, resulting from the restructuring as proposed by the CPUC. The Company identified three categories of uneconomic assets: utility-owned generation assets and power purchase commitments, power purchase obligations relating to qualifying facilities (QFs) and generation-related regulatory assets. The estimates of uneconomic assets were determined by comparing the future revenue requirements of generation assets and power purchase obligations over a twenty-year and thirty-year period, respectively, with revenues computed at the assumed market price. Diablo Canyon was included in the revenue requirement calculation using the proposed pricing modifications to the Diablo Canyon settlement. (See Operating Revenues.) The revenue requirement for Diablo Canyon and all Company-owned generation assets included a return on investment. The actual amount of uneconomic assets and obligations will depend upon the final regulation and the actual market price of electricity. The Company intends to seek recovery of its uneconomic assets and obligations through the competition transition charge. (See Note 2 of Notes to Consolidated Financial Statements.) In addition to working with the CPUC on this proposal, the Company has made several proposals to modify existing regulatory processes and to provide additional pricing flexibility to those customers with the most competitive options. The Company has proposed instituting PBR for determining nonfuel revenues, under which electric and natural gas 13 6 revenues would be determined annually by formula rather than through general rate cases (GRCs), attrition rate adjustments and cost of capital proceedings. The Company has also proposed a gas procurement incentive mechanism that would replace after-the-fact reasonableness reviews of certain costs. This proposed mechanism would measure the Company's gas procurement costs against market benchmarks and would provide for the sharing, between ratepayers and shareholders, of variances from a preset range around the market benchmark. The shifting of utility regulation from traditional cost-of-service based concepts to concepts based upon market competition and benchmarks will place greater emphasis on the Company's ability to provide valued products and services at competitive prices. The Company has announced a five-year goal of reducing its system-wide average electric rates. In addition, the Company has taken several significant actions to position itself to effectively compete in the restructured electric and gas industries. Specifically, the Company has: - Extended through 1995 its electric rate freeze which began in 1993. - Proposed a modification of the Diablo Canyon settlement to reduce the price paid for electricity generated at Diablo Canyon over the next five years. - Reduced electric rates for certain of its largest industrial customers through an economic stimulus rate that will extend through the end of 1995. - Planned reductions in annual spending in 1995 of approximately $600 million from 1993 spending levels. - Refinanced debt and preferred stock over the last three years resulting in annual savings of approximately $97 million in financing costs. The Company cannot predict the ultimate outcome of the ongoing changes that are taking place in the utility industry. However, management believes the end result will involve a fundamental change in the way the Company conducts its business. These changes may impact financial operating trends and add volatility to the Company's earnings. Management is actively seeking regulatory and operational changes that will allow the Company to provide energy services in a safe, reliable and competitive manner while achieving strong financial performance. Accounting for the Effects of Regulation: The transition to a competitive market environment may affect the Company's future revenues and cash flows. In the event that recovery of the Company's costs and investments becomes unlikely or uncertain due to competitive pressures or regulatory changes, it could cause the Company to write off applicable portions of its regulatory assets. The final CPUC determination of uneconomic costs and the method of recovery could adversely affect the Company's returns on its investments in electric generation assets. If future electric generation revenues are insufficient to recover the Company's investments and QF obligations, the Company would recognize a loss. The Company currently accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $3.7 billion of regulatory assets, including balancing accounts, at December 31, 1994. As discussed further in Note 2 of Notes to Consolidated Financial Statements, if the CPUC's electric industry restructuring proposal is adopted as proposed or the Company determines that future electric generation rates will no longer be based on cost-of-service, the Company will discontinue application of SFAS No. 71 for the electric generation portion of its operations. If such discontinuance should occur, the Company would write off all applicable electric generation-related regulatory assets to the extent that transition cost recovery is not assured. The regulatory assets attributable to electric generation, excluding balancing accounts of approximately $700 million which are expected to be recovered in the near term, are estimated to be $1.6 billion at December 31, 1994. The final determination of the financial impact will depend on the form of regulation, including transition mechanisms, if any, adopted by the CPUC and the groups of customers affected. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. Proposed Accounting Standard: The Financial Accounting Standards Board (FASB) has proposed a new accounting standard, "Accounting for the Impairment of Long-Lived Assets," which is expected to be issued in early 1995. The Company would be required to adopt the new standard beginning January 1, 1996, but may elect to adopt it earlier. If issued by the FASB as proposed, the new standard would require, among other things, that regulatory assets recorded as a result of SFAS No. 71 continue to be probable of recovery in 14 7 rates at all times, rather than only at the time the regulatory asset is recorded. As such, regulatory assets currently recorded may require adjustment in the future if recovery is no longer probable. Under the current ratemaking, the Company does not believe there would be any immediate significant impact of adopting the standard, as proposed. Results of Operations The Company's results of operations for the three years ended December 31, 1994, are reflected in the following table and discussed below.
Diablo (in millions, except per share amounts) Utility Canyon (1) Enterprises Total 1994 Operating revenues $ 8,329 $1,870 $ 248 $10,447 Operating expenses 7,281 1,252 281 8,814 ------- ------ ------ ------- Operating income (loss) $ 1,048 $ 618 $ (33) $ 1,633 ======= ====== ====== ======= Net income $ 541 $ 461 $ 5 $ 1,007 ======= ====== ====== ======= Earnings per common share $ 1.16 $ 1.04 $ .01 $ 2.21 ======= ====== ====== ======= Total assets at year end $20,303 $5,978 $1,528 $27,809 ======= ====== ====== ======= 1993 Operating revenues $ 8,398 $1,933 $ 251 $10,582 Operating expenses 7,335 1,225 259 8,819 ------- ------ ------ ------- Operating income (loss) $ 1,063 $ 708 $ (8) $ 1,763 ======= ====== ====== ======= Net income $ 552 $ 496 $ 17 $ 1,065 ======= ====== ====== ======= Earnings per common share $ 1.18 $ 1.11 $ .04 $ 2.33 ======= ====== ====== ======= Total assets at year end $19,870 $6,250 $1,043 $27,163 ======= ====== ====== ======= 1992 Operating revenues $ 8,306 $1,781 $ 209 $10,296 Operating expenses 7,125 1,118 220 8,463 ------- ------ ------ ------- Operating income (loss) $ 1,181 $ 663 $ (11) $ 1,833 ======= ====== ====== ======= Net income (loss) $ 738 $ 443 $ (10) $ 1,171 ======= ====== ====== ======= Earnings (loss) per common share $ 1.61 $ .99 $ (.02) $ 2.58 ======= ====== ====== ======= Total assets at year end $17,759 $5,494 $ 935 $24,188 ======= ====== ====== =======
(1) See Note 4 of Notes to Consolidated Financial Statements for discussion of allocations. Earnings Per Common Share: Earnings per common share were $2.21, $2.33 and $2.58 for 1994, 1993 and 1992, respectively. Earnings per common share for 1994 were lower than for 1993 primarily due to the refueling of both units of Diablo Canyon in 1994 compared to only one unit in 1993. In 1994, the Company recorded special charges for workforce reductions, gas reasonableness matters, contingencies related to gas transportation commitments and an increase in litigation reserves which in the aggregate totaled approximately $434 million. Special charges in 1993 totaled approximately $410 million and included charges for workforce reductions, gas decontracting, gas reasonableness matters, contingencies related to gas transportation commitments and the impact of increasing the federal income tax rate to 35 percent. Earnings per common share for 1993 were lower than for 1992 due to charges against earnings discussed above. These charges were partially offset by higher Diablo Canyon revenues due to the annual increase in the price per kWh as provided in the Diablo Canyon settlement. Since the Diablo Canyon settlement in 1988, Diablo Canyon has made an increasing contribution to the Company's total earnings per share. For the year ended December 31, 1994, Diablo Canyon contributed $1.04 (47 percent) to the total earnings per share of $2.21. The proposed modification of the price for power produced by Diablo Canyon, discussed below, will likely cause a decrease in the Diablo Canyon earnings per share contribution. On a consolidated basis, the Company earned an 11.1 percent, 11.9 percent and 13.7 percent return on average common stock equity for the years ended December 31, 1994, 1993 and 1992, respectively. For 1995, the CPUC has authorized a return on average common stock equity of 12.1 percent for the Company's utility operations. Common Stock Dividend: In January 1995, the Board of Directors (Board) declared a quarterly dividend of $.49 per share which corresponds to an annualized dividend of $1.96 per share. The Company's common stock dividend is based on a number of financial considerations, including sustainability, financial flexibility and competitiveness with investment opportunities of similar risk. The Company has a long-term objective of reducing its dividend payout ratio (dividends declared divided by earnings available for common stock) to reflect the increased business risk in the utility industry. At this time, the Company is unable to determine the impact, if any, the restructuring of the electric industry will have on the Company's ability to increase its dividends in the future. 15 8 Operating Revenues: Electric revenues increased $162 million, $119 million and $378 million in 1994, 1993 and 1992, respectively, compared to the preceding year. Despite the rate freeze, electric revenues increased due to higher energy costs in 1994 reflected in the electric energy cost balancing account. The higher revenues from the energy cost balancing account were offset by the decrease in revenues from Diablo Canyon resulting from the refueling of both units of the nuclear power plant in 1994 as compared with only one unit in 1993. The Company will continue through the end of 1995 its freeze on electric rates which began in 1993. The increase in 1993 electric revenues was due to rate increases associated with general increases in operating expenses and a higher electric rate base on which PG&E is allowed to earn a return. This increase was offset by a decrease in revenues resulting from a decrease in the cost of electric energy. In addition, Diablo Canyon revenues, which are included in the electric revenues discussed above, increased due to the annual increase in the price per kWh as provided in the Diablo Canyon settlement. The 1992 increase in electric revenues was primarily due to one scheduled refueling outage at Diablo Canyon as compared with two scheduled refueling outages in 1991, and the annual increase in the price per kWh as provided in the Diablo Canyon settlement. The Diablo Canyon settlement, which became effective July 1988, bases revenues for the plant primarily on the amount of electricity generated, 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. As discussed further in Note 4 of Notes to Consolidated Financial Statements, in December 1994, the Company, a consumer advocacy branch of the CPUC staff (the Division of Ratepayer Advocates (DRA)), the California Attorney General and several other parties representing energy consumers have agreed to modify the pricing provisions of the Diablo Canyon settlement, subject to CPUC approval. Under the proposed modification, the price for power produced by Diablo Canyon would be reduced from what it would have been under the original terms of the Diablo Canyon settlement. The Diablo Canyon capacity factors for 1994, 1993 and 1992 were 81 percent, 89 percent and 88 percent, respectively, reflecting the scheduled refueling outages for Units 1 and 2 in 1994, Unit 2 in 1993 and Unit 1 in 1992. The 1994 capacity factors were also impacted by 24 days of extended unscheduled outages. There were no extended unscheduled outages in 1993 or 1992. Through December 31, 1994, the lifetime capacity factor for Diablo Canyon was 79 percent. The Company will report significantly lower revenues for Diablo Canyon during any extended outages, including refueling outages. Refueling outages, the length of which depend on the scope of the work, typically occur for each unit every eighteen months. The next refueling outages for Unit 1 and Unit 2 are scheduled to begin in September 1995 and March 1996, respectively, and each is planned to last about six weeks. Under the proposed modification to the prices prescribed in the Diablo Canyon settlement, each Diablo Canyon unit will contribute approximately $2.9 million in revenues per day at full operating power in 1995. The daily revenues could decline each year for the next five years. Gas revenues decreased $297 million in 1994 compared to the preceding year primarily due to a decrease in revenues received from our industrial and large commercial customers, who are now arranging for the purchase of their own gas supplies, with the Company providing only transportation service partially offset by revenues generated from the natural gas transmission expansion project. (See Regulatory Matters.) Gas revenues increased $168 million and $140 million in 1993 and 1992, respectively, compared to the preceding year. The 1993 increase was primarily due to rate increases associated with general increases in operating expenses and a higher gas rate base on which PG&E is allowed to earn a return, as well as increased revenues from Enterprises reflecting increases in the price and production of gas. The 1992 increase in gas revenues was primarily due to revenues resulting from the December 1991 acquisition of Tex/Con Oil & Gas Company by DALEN Resources Corp. (DALEN), a wholly owned subsidiary of Enterprises. 16 9 Operating Expenses: Operating expenses in 1994 remained constant as compared to 1993. The 1994 operating expenses include a charge against earnings of $249 million related to the workforce reductions that commenced in 1994. In comparison, the Company expensed $190 million related to the 1993 workforce reductions. As a result of the 1993 workforce reductions, administrative and general expense was less in 1994 as compared to 1993. The cost of electric energy was $312 million greater in 1994 as compared to 1993 primarily due to less favorable hydro conditions and an increase in the cost per kWh of purchased power. These unfavorable variances were offset by a favorable variance of $365 million in the cost of gas as a result of the Company no longer procuring gas for certain customers. Income tax expense has declined due to lower operating income in 1994. In 1993 and 1992, the Company's operating expenses increased $357 million and $398 million, respectively, over the preceding year. The 1993 increase was due to the charge related to the Company's 1993 workforce reductions and increases in administrative and general expense, income tax expense, and depreciation and decommissioning expense, partially offset by a decrease in the cost of electric energy. Most of the $114 million increase in administrative and general expense was due to an increase in litigation costs and an increase in employee benefit costs upon adoption of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." The $100 million increase in income tax expense was primarily due to the increase in the federal income tax rate to 35 percent. The $166 million decrease in the cost of electric energy was a result of improved hydro conditions and reflects a decline in the cost per kWh for purchased power. The 1992 increase in operating expenses was primarily due to increases in the cost of gas, the cost of electric energy, and depreciation and decommissioning expense. Other Income and (Income Deductions): Other--net includes charges in 1994 and 1993 related to gas issues. The 1994 charges consist of accruals for gas reasonableness matters, including proposed settlement agreements and contingencies related to transportation capacity commitments. (See Note 3 of Notes to Consolidated Financial Statements.) The 1993 charges include accruals for gas reasonableness matters and contingencies related to transportation capacity commitments as well as charges associated with restructuring the Company's Canadian gas supply arrangements. Regulatory Matters: In addition to the CPUC electric industry restructuring proposal, discussed further in Note 2 of Notes to Consolidated Financial Statements, during 1994 the Company received CPUC decisions in proceedings on revenues and energy costs and filed applications which will impact rates in 1995 and beyond. The most significant of these are discussed below. The CPUC has approved the Company's request to freeze retail electric rates through the end of 1995. In order to accomplish the rate freeze, rate increases attributable to energy costs and the increase in the authorized rate of return were offset by base revenue reductions. The Company is implementing base cost reductions which are reflected in the decreased base revenues. Gas rates for commodity, transportation and base costs have increased as a result of two decisions during 1994. In July, the CPUC approved a $162 million increase for recovery of previously deferred gas and transportation costs. In December, a $100 million increase in revenue was approved reflecting an increase in the cost of capital, balancing accounts adjustments and inflationary increases in costs. In addition, the Company filed an application with the CPUC requesting a gas rate increase of approximately $173 million annually for the two-year period beginning in October 1, 1995. The Company's request reflects an increase in gas and transportation costs and the collection of amounts previously deferred in balancing accounts. If the Company's request is adopted, rates would be effective September 15, 1995. In January 1995, the Company updated its 1996 GRC application to reflect CPUC decisions that went into effect on January 1, 1995. In the GRC, the Company is seeking a $162 million decrease for electric revenues and a $92 million decrease for gas revenues, compared to rates in effect in 1994. (Compared to rates in effect in 1995, there would be no change for electric revenues and a $162 million decrease for gas revenues.) Revenues to be collected from customers in 1996 may also be affected by future requests related to energy costs and cost of capital. In November 1993, the Company placed in service an expansion of its natural gas transmission system from the Canadian border into California. The pipeline provides 17 10 additional firm capacity to the Pacific Northwest and to Northern and Southern California. The total cost of construction is approximately $1.7 billion. The Company has filed applications with the FERC (for the interstate portion) and the CPUC (for the portion within California) requesting that capital and operating costs be found reasonable. Revenues are currently being collected under rates approved by the FERC and the CPUC, subject to refund. The Company believes the final decisions on these applications will not have a significant impact on its financial position or results of operations. In accordance with mechanisms established by the CPUC, the Company accumulates the difference between actual costs of generating electricity and the revenues designed to recover such costs. To the extent costs exceed revenues, the undercollection accumulates in the electric energy cost balancing account. Over the past few years, the Company has experienced a significant increase in the level of balancing account undercollection related to its electric energy costs. The increase primarily results from Diablo Canyon's generation exceeding that forecasted in the annual electric energy cost proceeding, increased fuel costs, the use of higher-cost energy sources to compensate for less than normal hydro conditions and the deferred recovery of undercollected balances. At December 31, 1994, the electric energy cost balancing account undercollection was approximately $716 million. In order to accomplish its freeze on retail electric rates, the Company will be deferring the recovery of $444 million of the electric energy cost undercollection beyond 1995 and will also forgo collection of interest on these deferred costs. Recovery of these deferred costs will depend on a number of factors. However, the Company currently believes that the amount deferred will be collected through rates over the near term. The modification of the price for Diablo Canyon power will assist in reducing the undercollected energy cost balance. Nonregulated Operations: The Company, through its wholly owned subsidiary, Enterprises, has taken steps to position itself to compete in the nonregulated energy business. Enterprises contributed $.01, $.04 and $(.02) per share to the Company's total earnings per share for the years ended December 31, 1994, 1993 and 1992, respectively. Enterprises makes the majority of its investments in nonregulated energy projects through a joint venture, U.S. Generating. Enterprises in partnership with Bechtel Enterprises, Inc. is in the process of forming a company to develop, build, own and operate international nonutility generation projects. In August 1994, Enterprises and Bechtel Enterprises, Inc. completed their acquisition of J. Makowski Co., Inc. (JMC), a Boston-based company engaged in the development of natural gas-fueled power generation projects and natural gas distribution, supply and underground storage projects. The final purchase price was approximately $250 million. Enterprises' effective ownership share of JMC is approximately 80 percent. In July 1994, the Company's Board approved a plan for the disposition of DALEN, formerly PG&E Resources Company, through an initial public offering of DALEN's common stock, as DALEN no longer fits Enterprises' business strategy. The disposition, if completed, is not anticipated to have a significant impact on the Company's financial position or results of operations. Liquidity and Capital Resources Sources of Capital: The Company's capital requirements are funded from cash provided by operations and, to the extent necessary, external financing. The Company's capital structure provides financial flexibility and access to capital markets at reasonable rates, ensuring the Company's ability to meet all of its capital requirements. Proceeds from the issuance of securities are used for capital expenditures, refundings and other general corporate purposes. Debt: In 1994, the Company issued $30 million of medium-term notes and redeemed or repurchased $135 million of mortgage bonds, medium-term notes and Eurobonds. In 1993, the Company issued $4.0 billion of mortgage bonds, pollution control revenue bonds and medium-term notes. Substantially all these proceeds were used to redeem or repurchase higher-cost mortgage bonds to accomplish a reduction in financing costs. In January 1995, the Board authorized the Company to redeem or repurchase up to $153 million of mortgage bonds. In addition, $85 million remains from a previous authorization to repurchase medium-term notes. The Company issues short-term debt (principally commercial paper) to fund fuel oil, nuclear fuel and gas inventories, unrecovered balances in balancing accounts and cyclical fluctuations in daily cash flows. At December 31, 1994 and 1993, the Company had $525 million and $764 18 11 million, respectively, of commercial paper outstanding. In addition, the Company has a $1 billion short-term credit facility to support the sale of commercial paper and other corporate purposes. There were no borrowings under this facility in 1994, 1993 or 1992. Equity: In 1994 and 1993, the Company received $274 million and $264 million, respectively, in proceeds from the sale of common stock under the employee Savings Fund Plan, the Dividend Reinvestment Plan and the employee Long-term Incentive Program. Proceeds were used for capital expenditures and other general corporate purposes. In July 1993, the Board authorized the Company to reinstate its common stock repurchase program and repurchase up to $1 billion of common stock on the open market or in negotiated transactions. This program is funded by internally generated funds. Shares will be repurchased to manage the overall balance of common stock in the Company's capital structure. Through December 31, 1994, the Company had repurchased approximately $435 million of its common stock under this program. In 1994, the Company issued $63 million of preferred stock with a mandatory redemption provision and redeemed $75 million of the Company's higher-cost preferred stock. In 1993, the Company issued $200 million of redeemable preferred stock. Proceeds were used to finance a portion of the redemption of $267 million of the Company's higher-cost preferred stock. Capital Requirements: The Company's estimated capital requirements for the next three years are shown below:
Year ended December 31, ------------------------- (in millions) 1995 1996 1997 Utility $1,212 $1,276 $1,237 Diablo Canyon 47 50 52 Enterprises 285 142 284 ------ ------ ------ Total capital expenditures 1,544 1,468 1,573 Maturing debt and sinking funds 477 373 369 ------ ------ ------ Total capital requirements $2,021 $1,841 $1,942 ====== ====== ======
Utility and Diablo Canyon expenditures will be primarily for improvements to the Company's facilities to maintain their efficiency and reliability, to extend their useful lives and to comply with environmental laws and regulations. Enterprises' estimated expenditures include oil and gas exploration and development activities by DALEN of approximately $120 million for 1995, project development expenditures for power and real-estate projects and equity commitments associated with generating facility projects. In addition to these capital requirements, the Company has other commitments as discussed in Notes 3 and 12 of Notes to Consolidated Financial Statements. Risk Management: The Company uses a number of techniques to mitigate its financial risk including the purchase of commercial insurance, the maintenance of systems of internal control and the selected use of financial instruments. The extent to which these techniques are used depends on the risk of loss and the cost to employ such techniques. These techniques do not eliminate financial risk to the Company. The majority of the Company's financing is done on a fixed-term basis thereby eliminating the financial risk associated with fluctuating interest rates. The Company has used financial instruments to eliminate the effects of fluctuations in interest rates and foreign currency exchange rates on certain of its debt. At December 31, 1994, the Company, through a series of interest rate swap transactions, had converted $639 million of a subsidiary's debt from a floating rate to a fixed rate through July 31, 1999. The Company, through foreign exchange contracts, has agreed to pay fixed interest and principal payments in U.S. dollars on $67 million of Swiss Franc debentures. In addition, DALEN periodically enters into crude oil and natural gas hedging transactions to minimize the risk of price fluctuations. The net gains and losses associated with these transactions have not been material. Environmental Matters: 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 $39 million, $93 million and $85 million for 1995, 1996 and 1997, respectively, and are included in the 19 12 Company's three-year table in the Capital Requirements section above. Expenditures during these years will be primarily for nitrogen oxide (NOx) emission reduction projects for the Company's fossil fuel fired generating plants and natural gas compressor stations. Pursuant to federal and state legislation, local air districts have adopted rules that require reductions in NOx emissions from company facilities. Final rules have yet to be adopted in all local air districts in which the Company operates and these rules continue to be modified. The Company currently estimates that compliance with NOx rules likely to be in place could require capital expenditures of up to $355 million over the next ten years. 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. Although the ultimate amount of costs that will be incurred by the Company in connection with its compliance and remediation activities is difficult to estimate, the Company has an accrued liability at December 31, 1994, of $95 million for hazardous waste remediation costs. The costs could be as much as $235 million, due to uncertainty concerning the Company's responsibility and the extent of contamination, the complexity of environmental laws and regulations and the selection of compliance alternatives. (See Note 13 of Notes to Consolidated Financial Statements.) Legal Matters: In the normal course of business, the Company is named as a party in a number of claims and lawsuits. Substantially all of these are litigated or settled with no significant impact on either the Company's results of operations or financial position. There are several significant litigation cases which are discussed in Note 13 of Notes to Consolidated Financial Statements. These cases include claims for personal injury and property damage, as well as punitive damages, allegedly suffered as a result of exposure to chromium near the Company's Hinkley Compressor Station, antitrust claims for damages as a result of Canadian natural gas purchases by one of the Company's wholly owned subsidiaries and two claims that the Company underpaid franchise fees. Accounting for Decommissioning Expense: The staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations. In response to these questions, the FASB has agreed to review the accounting for removal costs, including decommissioning. If current electric utility industry accounting practices for such decommissioning are changed: (1) Annual expense for decommissioning could increase and (2) The estimated total cost for decommissioning could be recorded as a liability rather than accrued over time as accumulated depreciation. The Company does not believe that such changes, if required, would have an adverse effect on its results of operations due to its current ability to recover decommissioning costs through rates. 20 13 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31, - ---------------------------------------- (in thousands, except per share amounts) 1994 1993 1992 OPERATING REVENUES Electric $ 8,027,976 $ 7,866,043 $ 7,747,492 Gas 2,419,375 2,716,365 2,548,596 ----------- ----------- ----------- Total operating revenues 10,447,351 10,582,408 10,296,088 ----------- ----------- ----------- OPERATING EXPENSES Cost of electric energy 2,561,778 2,250,209 2,416,554 Cost of gas 574,894 939,572 907,945 Distribution 229,640 226,975 219,082 Transmission 293,995 319,022 339,099 Customer accounts and services 433,603 403,560 421,990 Maintenance 456,889 442,939 484,751 Depreciation and decommissioning 1,397,470 1,315,524 1,221,490 Administrative and general 973,302 1,041,453 927,316 Workforce reduction costs 249,097 190,200 - Income taxes 924,620 1,006,774 906,845 Property and other taxes 296,911 297,495 295,164 Other 421,793 385,755 322,411 ----------- ----------- ----------- Total operating expenses 8,813,992 8,819,478 8,462,647 ----------- ----------- ----------- OPERATING INCOME 1,633,359 1,762,930 1,833,441 ----------- ----------- ----------- OTHER INCOME AND (INCOME DEDUCTIONS) Interest income 108,092 85,642 87,244 Allowance for equity funds used during construction 19,046 41,531 39,368 Other--net (8,344) (53,524) (3,006) ----------- ----------- ----------- Total other income and (income deductions) 118,794 73,649 123,606 ----------- ----------- ----------- INCOME BEFORE INTEREST EXPENSE 1,752,153 1,836,579 1,957,047 ----------- ----------- ----------- INTEREST EXPENSE Interest on long-term debt 651,912 731,610 739,279 Other interest charges 105,744 118,100 91,404 Allowance for borrowed funds used during construction (12,953) (78,626) (44,217) ----------- ----------- ----------- Total interest expense 744,703 771,084 786,466 ----------- ----------- ----------- NET INCOME 1,007,450 1,065,495 1,170,581 Preferred dividend requirement 57,603 63,812 78,887 ----------- ----------- ----------- EARNINGS AVAILABLE FOR COMMON STOCK $ 949,847 $ 1,001,683 $ 1,091,694 =========== =========== =========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 429,846 430,625 422,714 EARNINGS PER COMMON SHARE $2.21 $2.33 $2.58 DIVIDENDS DECLARED PER COMMON SHARE $1.96 $1.88 $1.76
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 21 14 Pacific Gas and Electric Company CONSOLIDATED BALANCE SHEET
December 31, ---------------------------- (in thousands) 1994 1993 ASSETS PLANT IN SERVICE Electric Nonnuclear $ 17,045,247 $ 16,633,772 Diablo Canyon 6,647,162 6,518,413 Gas 7,447,879 7,146,741 ------------ ------------ Total plant in service (at original cost) 31,140,288 30,298,926 Accumulated depreciation and decommissioning (12,269,377) (11,235,519) ------------ ------------ Net plant in service 18,870,911 19,063,407 ------------ ------------ CONSTRUCTION WORK IN PROGRESS 527,867 620,187 OTHER NONCURRENT ASSETS Oil and gas properties 437,352 573,523 Nuclear decommissioning funds 616,637 536,544 Investment in nonregulated projects 761,355 304,223 Other assets 137,325 193,466 ------------ ------------ Total other noncurrent assets 1,952,669 1,607,756 ------------ ------------ CURRENT ASSETS Cash and cash equivalents 136,900 61,066 Accounts receivable Customers 1,413,185 1,264,907 Other 98,035 123,255 Allowance for uncollectible accounts (29,769) (23,647) Regulatory balancing accounts receivable 1,345,669 992,477 Inventories Materials and supplies 197,394 239,856 Gas stored underground 136,326 170,345 Fuel oil 67,707 109,615 Nuclear fuel 140,357 134,411 Prepayments 33,251 56,062 ------------ ------------ Total current assets 3,539,055 3,128,347 ------------ ------------ DEFERRED CHARGES Income tax-related deferred charges 1,155,421 1,276,532 Diablo Canyon costs 401,110 419,775 Unamortized loss net of gain on reacquired debt 382,862 395,659 Workers' compensation and disability claims recoverable 247,209 192,203 Other 732,029 458,660 ------------ ------------ Total deferred charges 2,918,631 2,742,829 ------------ ------------ TOTAL ASSETS $ 27,809,133 $ 27,162,526 ============ ============
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 22 15 Pacific Gas and Electric Company CONSOLIDATED BALANCE SHEET
December 31, ---------------------------- (in thousands) 1994 1993 CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock $ 2,151,213 $ 2,136,095 Additional paid-in capital 3,806,508 3,666,455 Reinvested earnings 2,677,304 2,643,487 ----------- ----------- Total common stock equity 8,635,025 8,446,037 Preferred stock without mandatory redemption provisions 732,995 807,995 Preferred stock with mandatory redemption provisions 137,500 75,000 Long-term debt 8,675,091 9,292,100 ----------- ----------- Total capitalization 18,180,611 18,621,132 ----------- ----------- OTHER NONCURRENT LIABILITIES Customer advances for construction 152,384 152,872 Workers' compensation and disability claims 221,200 157,000 Other 644,233 246,950 ----------- ----------- Total other noncurrent liabilities 1,017,817 556,822 ----------- ----------- CURRENT LIABILITIES Short-term borrowings 524,685 764,163 Long-term debt 477,047 221,416 Accounts payable Trade creditors 414,291 472,985 Other 337,726 389,065 Accrued taxes 436,467 303,575 Deferred income taxes 432,026 315,584 Interest payable 84,805 82,105 Dividends payable 210,903 203,923 Other 643,779 487,809 ----------- ----------- Total current liabilities 3,561,729 3,240,625 ----------- ----------- DEFERRED CREDITS Deferred income taxes 3,902,645 3,978,950 Deferred investment tax credits 391,455 410,969 Noncurrent balancing account liabilities 226,844 112,533 Other 528,032 241,495 ----------- ----------- Total deferred credits 5,048,976 4,743,947 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Notes 2, 3, 12 and 13) ----------- ----------- TOTAL CAPITALIZATION AND LIABILITIES $27,809,133 $27,162,526 =========== ===========
23 16 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED CASH FLOWS
Year ended December 31, ---------------------------------------- (in thousands) 1994 1993 1992 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 1,007,450 $ 1,065,495 $ 1,170,581 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and decommissioning 1,397,470 1,315,524 1,221,490 Amortization 49,671 135,808 121,795 Gain on sale of investment in Alberta Natural Gas Company Ltd - - (48,722) Deferred income taxes and investment tax credits--net 15,312 319,198 164,457 Allowance for equity funds used during construction (19,046) (41,531) (39,368) Other deferred charges 32,740 (158,725) 8,147 Other noncurrent liabilities 301,842 50,279 31,374 Other deferred credits 105,262 110,145 73,259 Net effect of changes in operating assets and liabilities Accounts receivable (116,936) 64,790 39,922 Regulatory balancing accounts receivable (353,192) (218,553) (215,195) Inventories 112,443 23,097 (7,161) Accounts payable (110,033) (39,422) (102,559) Accrued taxes 132,892 44,638 128,243 Other working capital 181,481 108,873 (36,117) Other--net 210,331 13,184 49,891 ----------- ----------- ----------- Net cash provided by operating activities 2,947,687 2,792,800 2,560,037 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Construction expenditures (1,094,495) (1,763,024) (2,307,318) Allowance for borrowed funds used during construction (12,953) (78,626) (44,217) Nonregulated expenditures (328,266) (234,221) (148,226) Proceeds from sale of investment in Alberta Natural Gas Company Ltd - - 97,251 Other--net (29,914) 9,992 82,352 ---------- ----------- ----------- Net cash used by investing activities (1,465,628) (2,065,879) (2,320,158) ---------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock issued 274,269 264,489 296,653 Common stock repurchased (181,558) (257,780) (5,410) Preferred stock issued 62,312 200,001 195,451 Preferred stock redeemed (83,275) (302,640) (276,806) Long-term debt issued 60,907 4,584,548 1,676,513 Long-term debt matured or reacquired (436,673) (4,002,704) (1,409,337) Short-term debt issued (redeemed)--net (239,478) (366,961) 121,213 Dividends paid (891,850) (857,515) (809,108) Other--net 29,121 (24,885) (28,736) ---------- ----------- ----------- Net cash used by financing activities (1,406,225) (763,447) (239,567) ---------- ----------- ----------- NET CHANGE IN CASH AND CASH EQUIVALENTS 75,834 (36,526) 312 CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592 97,280 ---------- ----------- ----------- CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 136,900 $ 61,066 $ 97,592 ========== =========== =========== Supplemental disclosures of cash flow information Cash paid for Interest (net of amounts capitalized) $ 674,758 $ 642,712 $ 694,512 Income taxes 712,777 542,827 682,809
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 24 17 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
Preferred Preferred Stock Stock Total Without With Additional Common Mandatory Mandatory (dollars in thousands) Common Paid-in Reinvested Stock Redemption Redemption Stock Capital Earnings Equity Provisions Provisions(1) BALANCE DECEMBER 31, 1991 $2,087,859 $3,287,313 $2,306,152 $7,681,324 $ 894,897 $104,632 ---------- ---------- ---------- ---------- --------- -------- Net income--1992 1,170,581 1,170,581 Common stock issued (9,453,353 shares) 47,267 249,386 296,653 Common stock repurchased (179,610 shares) (898) (2,450) (2,062) (5,410) Preferred stock issued (8,000,000 shares) (4,549) (4,549) 125,000 75,000 Preferred stock redeemed (9,365,449 shares) (12,638) (14,940) (27,578) (229,106) (20,122) Cash dividends declared Preferred stock (81,393) (81,393) Common stock (744,277) (744,277) Other (2,214) (2,214) ---------- ---------- ---------- ---------- --------- -------- Net change 46,369 229,749 325,695 601,813 (104,106) 54,878 ---------- ---------- ---------- ---------- --------- -------- BALANCE DECEMBER 31, 1992 2,134,228 3,517,062 2,631,847 8,283,137 790,791 159,510 ---------- ---------- ---------- ---------- --------- -------- Net income--1993 1,065,495 1,065,495 Common stock issued (7,708,512 shares) 38,541 225,948 264,489 Common stock repurchased (7,334,876 shares) (36,674) (63,180) (157,926) (257,780) Preferred stock issued (8,000,000 shares) 200,001 Preferred stock redeemed (8,156,968 shares) (13,375) (21,958) (35,333) (182,797) (84,510) Cash dividends declared Preferred stock (62,521) (62,521) Common stock (811,196) (811,196) Other (254) (254) ---------- ---------- ---------- ---------- --------- -------- Net change 1,867 149,393 11,640 162,900 17,204 (84,510) ---------- ---------- ---------- ---------- --------- -------- BALANCE DECEMBER 31, 1993 2,136,095 3,666,455 2,643,487 8,446,037 807,995 75,000 ---------- ---------- ---------- ---------- --------- -------- Net income--1994 1,007,450 1,007,450 Common stock issued (10,508,483 shares) 52,543 221,726 274,269 Common stock repurchased (7,485,001 shares) (37,425) (66,334) (77,799) (181,558) Preferred stock issued (2,500,000 shares) (188) (188) 62,500 Preferred stock redeemed (3,000,000 shares) (5,331) (2,544) (7,875) (75,000) Cash dividends declared Preferred stock (58,203) (58,203) Common stock (840,627) (840,627) Other (9,820) 5,540 (4,280) ---------- ---------- ---------- ---------- --------- -------- Net change 15,118 140,053 33,817 188,988 (75,000) 62,500 ---------- ---------- ---------- ---------- --------- -------- BALANCE DECEMBER 31, 1994 $2,151,213 $3,806,508 $2,677,304 $8,635,025 $ 732,995 $137,500 ========== ========== ========== ========== ========= ========
(1) Includes current portion. The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 25 18 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED CAPITALIZATION
December 31, ---------------------------- (dollars in thousands, except per share amounts) 1994 1993 COMMON STOCK EQUITY Common stock, par value $5 per share (authorized 800,000,000 shares, issued and outstanding 430,242,687 and 427,219,205 $ 2,151,213 $ 2,136,095 Additional paid-in capital 3,806,508 3,666,455 Reinvested earnings 2,677,304 2,643,487 ----------- ----------- Common stock equity 8,635,025 8,446,037 ----------- ----------- PREFERRED STOCK Preferred stock without mandatory redemption provision Par value $25 per share (1) Nonredeemable 5% to 6%--5,784,825 shares outstanding 144,621 144,621 Redeemable 4.36% to 8.2%--23,534,958 and 26,534,958 shares outstanding 588,374 663,374 ----------- ----------- Total preferred stock without mandatory redemption provision 732,995 807,995 ----------- ----------- Preferred stock with mandatory redemption provision Par value $25 per share (1) 6.30%--2,500,000 and none outstanding 62,500 - 6.57%--3,000,000 shares outstanding 75,000 75,000 Par value $100 per share (authorized 10,000,000 shares) - - ----------- ----------- Total preferred stock with mandatory redemption provision 137,500 75,000 ----------- ----------- Preferred stock 870,495 882,995 ----------- ----------- LONG-TERM DEBT PG&E long-term debt First and refunding mortgage bonds Maturity Interest rates 1994-1999 4.25% to 6.875% 714,074 724,610 2000-2005 5.875% to 8.75% 1,658,749 1,739,649 2006-2012 6.25% to 8.875% 477,870 477,870 2013-2019 7.5% to 12.75% 136,030 140,900 2020-2026 5.85% to 9.30% 2,902,945 2,947,428 ----------- ----------- Principal amounts outstanding 5,889,668 6,030,457 Unamortized discount net of premium (66,198) (71,817) ----------- ----------- Total mortgage bonds 5,823,470 5,958,640 Unsecured debentures, 10.81% to 12%, due 1994-2000 124,939 221,523 Pollution control loan agreements, variable rates, due 2008-2016 925,000 925,000 Unsecured medium-term notes, 4.13% to 10.10% due 1994-2014 1,443,800 1,542,625 Unamortized discount related to unsecured medium-term notes (2,428) (3,459) Other long-term debt 22,209 24,127 ----------- ----------- Total PG&E long-term debt 8,336,990 8,668,456 Long-term debt of subsidiaries 815,148 845,060 ----------- ----------- Total long-term debt of PG&E and subsidiaries 9,152,138 9,513,516 Less long-term debt--current portion 477,047 221,416 ----------- ----------- Long-term debt 8,675,091 9,292,100 ----------- ----------- TOTAL CAPITALIZATION $18,180,611 $18,621,132 =========== ===========
(1) Authorized 75,000,000 shares in total (both with and without mandatory redemption provisions). The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 26 19 Pacific Gas and Electric Company SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
Diversified Operations Intersegment (in thousands) Electric Gas (4) Eliminations Total 1994 Operating revenues $ 8,006,157 $2,194,870 $ 246,324 $ - $10,447,351 Intersegment revenues (1) 12,852 85,341 1,695 (99,888) - ----------- ---------- ---------- --------- ----------- Total operating revenues $ 8,019,009 $2,280,211 $ 248,019 $ (99,888) $10,447,351 =========== ========== ========== ========= =========== Depreciation and decommissioning $ 982,859 $ 295,979 $ 118,632 $ - $ 1,397,470 Operating income before income taxes (2) 2,213,518 381,078 (33,390) (3,227) 2,557,979 Construction expenditures (3) 834,494 292,000 - - 1,126,494 Identifiable assets (3) $19,471,121 $6,433,984 $1,436,128 $ - $27,341,233 Corporate assets 467,900 ----------- Total assets at end of year $27,809,133 =========== 1993 Operating revenues $ 7,866,043 $2,466,788 $ 249,577 $ - $10,582,408 Intersegment revenues (1) 15,369 223,443 5,079 (243,891) - ----------- ---------- ---------- --------- ----------- Total operating revenues $ 7,881,412 $2,690,231 $ 254,656 $(243,891) $10,582,408 =========== ========== ========== ========= =========== Depreciation and decommissioning $ 925,673 $ 251,490 $ 138,361 $ - $ 1,315,524 Operating income before income taxes (2) 2,344,796 440,323 (7,375) (8,040) 2,769,704 Construction expenditures (3) 929,065 954,116 - - 1,883,181 Identifiable assets (3) $19,125,555 $6,467,424 $1,053,027 $ - $26,646,006 Corporate assets 516,520 ----------- Total assets at end of year $27,162,526 =========== 1992 Operating revenues $ 7,747,492 $2,342,202 $ 206,394 $ - $10,296,088 Intersegment revenues (1) 15,150 410,014 28,191 (453,355) - ----------- ---------- ---------- --------- ----------- Total operating revenues $ 7,762,642 $2,752,216 $ 234,585 $(453,355) $10,296,088 =========== ========== ========== ========= =========== Depreciation and decommissioning $ 856,124 $ 231,443 $ 133,923 $ - $ 1,221,490 Operating income before income taxes (2) 2,308,828 441,612 (9,808) (346) 2,740,286 Construction expenditures (3) 1,124,368 1,266,535 - - 2,390,903 Identifiable assets (3) $17,658,656 $5,068,213 $ 996,860 $ - $23,723,729 Corporate assets 464,430 ----------- Total assets at end of year $24,188,159 ===========
(1) Intersegment electric and gas revenues are accounted for at tariff rates prescribed by the CPUC. (2) Income taxes and general corporate expenses are allocated in accordance with the FERC Uniform System of Accounts and requirements of the CPUC. Operating income in the Statement of Consolidated Income is net of utility income taxes. (3) Includes an allocation of common plant in service and allowance for funds used during construction. (4) Includes the nonregulated operations of wholly owned subsidiaries, including PG&E Enterprises, Mission Trail Insurance Ltd. (liability insurance), Pacific Gas Properties Company (real estate development) and Pacific Conservation Services Company (conservation loans). The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 27 20 Pacific Gas and Electric Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1: Summary of Significant Accounting Policies Regulation: Pacific Gas and Electric Company (PG&E) is regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). PG&E's consolidated financial statements reflect the ratemaking policies of these commissions in conformity with generally accepted accounting principles for rate-regulated enterprises. In the Notes to Consolidated Financial Statements, regulated operations other than the Diablo Canyon Nuclear Power Plant (Diablo Canyon) are referred to as the utility. Principles of Consolidation: The consolidated financial statements include PG&E and its wholly owned and majority-owned subsidiaries (collectively, the Company). All significant intercompany transactions have been eliminated. Major subsidiaries, all of which are wholly owned, are: Pacific Gas Transmission Company (PGT)--transports natural gas from the U.S./Canadian border to the California border; Alberta and Southern Gas Co. Ltd. (A&S)-- prior to November 1, 1993, bought gas in Canada and arranged its transport to the U.S. border (see Note 3 for discussion of the restructuring of A&S's operations); Pacific Energy Fuels Company--finances the purchase of nuclear fuel through issuance of its commercial paper; PG&E Enterprises (Enterprises)-- the parent company for nonregulated subsidiaries, including DALEN Resources Corp. (DALEN), formerly PG&E Resources Company, which engages in exploration, development and production of oil and natural gas, and PG&E Generating Company which through a joint venture (U.S. Generating) develops, builds, owns and operates independent power projects. Alberta Natural Gas Company Ltd (ANG), a 49.98% owned affiliate of PGT which transports natural gas, was sold in June 1992. Prior to the sale of ANG, the Company's investment in ANG was accounted for by the equity method of accounting. Revenues: Revenues are recorded primarily for delivery of gas and electric energy to customers. These revenues give rise to receivables from a diversified base of customers including residential, commercial and industrial customers primarily in Northern and Central California. The CPUC has established mechanisms known as balancing accounts which help stabilize the Company's earnings. Specifically, sales balancing accounts accumulate differences between authorized and actual base revenues. Energy cost balancing accounts accumulate differences between the actual cost of gas and electric energy and the revenues designated for recovery of such costs. Recovery of gas and electric energy costs through these balancing accounts is subject to a reasonableness review by the CPUC. (See Note 3 for further discussion of gas costs.) Plant in Service: The cost of plant additions and replacements is capitalized. Cost includes labor, materials, construction overhead and an allowance for funds used during construction (AFUDC). AFUDC is the cost of debt and equity funds used to finance the construction of new facilities. Financing costs of capital additions for Diablo Canyon, the California portion of the PGT-PG&E Pipeline Expansion Project (Pipeline Expansion), and other nonregulated projects are calculated under Statement of Financial Accounting Standards (SFAS) No. 34, "Capitalization of Interest Cost." The original cost of retired plant plus removal costs less salvage value are charged to accumulated depreciation. Maintenance, repairs and minor replacements and additions are charged to maintenance expense. Depreciation and Nuclear Decommissioning Costs: Depreciation of plant in service is computed using a straight-line remaining-life method. The estimated cost of decommissioning the Company's nuclear power facilities is recovered in base rates through an annual allowance. For the years ended December 31, 1994, 1993 and 1992, the amount recovered in rates for decommissioning costs was $54 million each year. The estimated total obligation for nuclear decommissioning costs is approximately $1.1 billion in 1994 dollars (or $4.5 billion in future dollars); this obligation is being recognized ratably over the facilities' lives. This estimate considers the total cost (including labor, materials and other 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. The decommissioning method selected for Diablo Canyon anticipates that the equipment, structures, and portions of the facility and site containing radioactive contaminants will be removed or decontaminated to a level that permits the property to be released for unrestricted use. Humboldt Bay Power Plant is being decommissioned under a method that consists of placing and maintaining the facility in protective storage until some future time when dismantling can be initiated. The average annualized escalation rate and the assumed return on qualified trust assets used to calculate the decommissioning obligation and annual expense are approximately 5.5 percent and 5.25 percent (6.25 percent on 28 21 nonqualified trust assets), respectively. (See Note 8 for further discussion of nuclear decommissioning funds.) As required by federal law, the U.S. Department of Energy (DOE) is responsible for the future storage and disposal of spent nuclear fuel. No permanent storage site has been identified and the DOE has indicated that the storage site will not be available until after 2010. The Company pays a one-tenth of one cent fee on each nuclear kilowatthour (kWh) sold to fund DOE storage and disposal activities. Income Taxes: The Company files a consolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80 percent or more. Income tax expense includes current and deferred income taxes resulting from operations during the year. Investment tax credits are deferred and amortized to income over the life of the related property. Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes," which established new financial accounting standards for income taxes. SFAS No. 109 prohibits net-of-tax accounting, requires that deferred tax liabilities and assets be adjusted for enacted changes in the income tax rates and requires the use of the liability method of accounting for income taxes. Under the liability method, the deferred tax liability represents the tax effect of temporary differences between the financial statement and income tax bases of assets and liabilities at current income tax rates. The effect of the adoption of SFAS No. 109, as of January 1, 1993, was an increase of $1.8 billion in consolidated liabilities as a result of recording additional deferred taxes; consolidated assets also increased $1.8 billion, consisting of a $1.5 billion increase in deferred charges (income tax-related deferred charges and Diablo Canyon costs) and a $300 million increase in net plant in service. These adjustments relate to temporary differences, which prior to adoption of SFAS No. 109 were not recorded as deferred taxes, consistent with the ratemaking process. Due to regulatory treatment, the adoption of SFAS No. 109 did not have a significant impact on the Company's results of operations. Debt Premium, Discount and Related Expenses: Long-term debt premium, discount and related expenses are amortized over the life of each issue. Gains and losses on reacquired debt allocated to the utility are amortized over the remaining original lives of the debt reacquired, consistent with ratemaking; gains and losses on debt allocated to Diablo Canyon and the California portion of the Pipeline Expansion are recognized in income, and if material as an extraordinary item, at the time such debt is reacquired. Occasionally, the Company uses interest rate swap agreements and foreign currency contracts to hedge fluctuations in interest rates and foreign currency exchange rates. The Company defers any gains or losses on these transactions and records interest expense adjusted for the effects of the agreements. Oil and Gas Properties: DALEN uses the successful-efforts method of accounting for oil and gas properties. Inventories: Nuclear fuel inventory is stated at the lower of average cost or market. Amortization of fuel in the reactor is based on the amount of energy output. Other inventories are valued at average cost except for fuel oil, which is valued by the last-in-first-out method. Statement of Consolidated Cash Flows: Cash and cash equivalents (valued at cost which approximates market) include special deposits, working funds and short-term investments with original maturities of three months or less. Reclassifications: Certain amounts in the prior years' consolidated financial statements have been reclassified to conform to the 1994 presentation. Note 2: COMPETITION AND REGULATION In April 1994, the CPUC issued an order instituting a rulemaking and an investigation (OIR/OII) on electric industry restructuring. The proposal, which is subject to comment and modification, involves two major changes in electric industry regulation in California. The first would move electric utilities from traditional ratemaking to performance-based ratemaking. The second would unbundle electric services and provide electric utility retail customers with the option to choose from a range of electric generation providers, including utilities (direct access). Direct access would be phased in over a six-year period beginning in 1996. Utilities would still be obligated to provide transmission and distribution services to all customers. To ensure an orderly transition that maintains the financial integrity of the utilities, the CPUC proposed that uneconomic costs of utility generating assets be recovered through a "competition transition charge" (CTC). However, the OIR/OII did not specify which costs might be recovered through such a transition charge or how such a charge would be allocated to and collected from customers. In June 1994, the Company filed its initial comments on the CPUC's proposal. The Company's response proposed an implementation schedule for direct access beginning in 29 22 1996, with direct access service available to all customers by 2008. For direct access customers, the Company proposed that it be given the pricing flexibility to compete and sell unbundled electric power while assuming the market risk of competitive pricing. In November 1994, the Company filed testimony with the CPUC on its plan for recovering uneconomic assets and obligations which would result from the restructuring of the electric industry as proposed by the CPUC. The Company's testimony, among other things, identifies and defines the costs proposed to be included in the CTC, provides preliminary estimates of the transition costs and discusses options for allocating and recovering those costs. Based on market prices of $.048 and $.032 per kWh, the Company estimated that its uneconomic generating assets and obligations are approximately $3 billion and $11 billion, respectively, resulting from the restructuring as proposed by the CPUC. The Company identified three categories of uneconomic assets: utility-owned generation assets and power purchase commitments, power purchase obligations relating to Qualifying Facilities (QFs), and generation-related regulatory assets. The estimates of uneconomic assets were determined by comparing future revenue requirements of generation assets and power purchase obligations, over a twenty-year and thirty-year period, respectively, with revenues computed at assumed market prices. Diablo Canyon was included in the revenue requirement calculation using the proposed pricing modification to the Diablo Canyon settlement. (See Note 4.) The revenue requirement for Diablo Canyon and all Company-owned generation assets included a return on investment. The actual amount of uneconomic assets and obligations will depend on the final regulation and the actual market price of electricity. Under the Company's proposal for a longer phase-in period to direct access, the Company would not seek recovery of the transition costs associated with its own generation assets and power purchase commitments, except for commitments to purchase power from QFs. Based on this assumption and the market price assumptions referred to above, the uneconomic assets and obligations are approximately $3 billion and $5 billion, respectively. If the CPUC adopts a shorter phase-in period, the Company indicated that it would seek recovery of all uneconomic assets and obligations resulting from the restructuring through the CTC. In December 1994, the CPUC issued an interim decision in the OIR/OII. The decision sets a schedule under which the CPUC will propose a policy decision in March 1995, with a final policy decision to be effective no earlier than September 1995. The CPUC's proposed policy statement will be subject to hearings and state legislative review before it can be implemented. The CPUC also established a public working group to comment on unbundling and transition cost recovery, social programs and resource procurement, under several different models for restructuring which include direct access and a supply pool for use by wholesale and/or retail purchasers of electricity. Financial Impact of the Electric Industry Restructuring Proposal: 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 SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $3.7 billion of regulatory assets, including balancing accounts, at December 31, 1994. In the event that recovery of specific costs through rates becomes unlikely or uncertain for all or a portion of the Company's utility operations, whether resulting from the expanding effects of competition or specific regulatory actions, it could cause the Company to write off applicable portions of its regulatory assets. If the OIR/OII is adopted as proposed, or the Company determines that future electric generation rates will no longer be based on cost-of-service, the Company will discontinue application of SFAS No. 71 for the electric generation portion of its operations. The Company continues to evaluate the current regulatory and competitive environment to determine whether and when such a discontinuance would be appropriate. If such discontinuance should occur, the Company would write off all applicable generation-related regulatory assets to the extent that transition cost recovery is not assured. The regulatory assets attributable to electric generation, excluding balancing accounts of approximately $700 million which are expected to be recovered in the near term, were approximately $1.6 billion at December 31, 1994. This amount could vary depending on the allocation methods used. The final CPUC determination of uneconomic costs and the method of recovery could adversely affect the Company's returns on its investments in electric generation assets. If future electric generation revenues are insufficient to recover the Company's investments and QF obligations, the Company would recognize a loss. The final determination of the financial impact will depend on the form of regulation, including transition mechanisms, if any, adopted by the CPUC and the groups of customers affected. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. 30 23 Note 3: Natural Gas Matters Regulatory Restructuring: Beginning August 1, 1993, PG&E implemented the CPUC's capacity brokering program which requires PG&E to make available for brokering all interstate gas pipeline capacity which is not held for its residential and smaller commercial (core) customers, and industrial and large commercial customers who choose bundled gas services (core subscription customers). PG&E's industrial and large commercial (noncore) customers, producers, aggregators, marketers and the Company's electric department can bid for such capacity. In addition, beginning November 1, 1993, PGT implemented the FERC's Order No. 636, which requires interstate pipelines to restructure their services. This order unbundled sales, transportation and storage services, instituted capacity release programs and provided for recovery of transition costs related to the restructuring of services. The Company's compliance with these regulatory changes allowed more of the Company's noncore customers to arrange for the purchase and transportation of their own gas supplies. As a result, the Company's gas purchase requirements and related need for firm transportation capacity for its gas purchases decreased, contributing to the Company's need to restructure its gas supply arrangements. Decontracting Plan: Until November 1993, PG&E purchased Canadian natural gas from PGT which in turn purchased such gas from A&S. A&S had commitments to purchase natural gas from approximately 190 Canadian gas producers under various long-term contracts, most of which extended through 2005. As a result of the regulatory restructuring discussed above, A&S, PGT, PG&E and approximately 190 Canadian gas producers entered into agreements (collectively, the Decontracting Plan) which terminated A&S's contracts with these Canadian gas producers effective November 1, 1993. Under the Decontracting Plan, producers released A&S, PGT and PG&E from any claims they may have had that resulted from the termination of the former arrangements as well as any prior claims related to these contracts. The total amount of settlement payments paid to producers was approximately $210 million. As part of the overall decontracting process, A&S's operations have been significantly reduced. A&S permanently assigned significant portions of its commitments for transportation capacity with NOVA Corporation of Alberta (NOVA) through October 2001 and ANG through October 2005 to third parties. In addition, A&S assigned approximately 600 million cubic feet per day (MMcf/d) of capacity on each of these pipelines to PG&E for use in the servicing of PG&E's core and core subscription customers. With the permanent assignments of its capacity made through the end of 1994, A&S holds remaining capacity of approximately 300 MMcf/d on each of the pipelines with total annual demand charges of approximately $15 million for which it is continuing its efforts to assign or broker. A&S believes it will be able to permanently assign substantially all of its remaining capacity by the end of 1995. To the extent others do not take this capacity, A&S will remain obligated to pay for the related demand charges. The FERC approved a transition cost recovery mechanism for PGT under which most costs incurred to restructure, reform or terminate the sales arrangements between A&S and PGT and the 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 arising out of the former contracts, are treated as transition costs. Twenty-five percent of the transition costs was absorbed by PGT. Twenty-five percent of the transition costs was recovered by PGT through direct bills (substantially all to PG&E as PGT's principal customer). The final fifty percent of the transition costs is being 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. Financial Impact of Decontracting Plan: The Company incurred transition costs of $228 million in 1993, consisting of settlement payments made to producers in connection with the implementation of the Decontracting Plan and amounts incurred by A&S in reducing certain administrative and general functions resulting from the restructuring. Of these costs, the Company deferred $143 million for future rate recovery. In addition, the Company recorded a charge of $31 million in 1993 related to A&S's remaining commitments for Canadian transportation capacity. Accordingly, the Company expensed $93 million in 1993 and a total of $23 million in prior years. Transportation Commitments: The Company has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that the Company will pay each year may change due to changes in tariff rates and may be offset to the extent the Company can broker or permanently assign any unused capacity. In addition to demand charges, the Company is required to pay transportation charges for actual quantities shipped. The Company's total demand and transportation charges paid under these agreements (excluding agreements with PGT) were approximately $225 million in 1994, $280 million in 1993 and $300 million in 1992. 31 24 The following table summarizes the approximate capacity held by the Company on various pipelines and the related annual demand charges as of December 31, 1994:
Total Firm Capacity Annual Demand Pipeline Held Charges Contract Company (MMcf/d) (in millions) Expiration - ------------------------- ------------- ------------- ---------- El Paso 1,140 $130 December 1997 Transwestern 200 $ 30 March 2007 NOVA 870 $ 25 October 2001 ANG 890 $ 15 October 2005
Regulatory changes have resulted in a decrease in the Company's need for firm transportation capacity for its own gas purchases. PG&E holds approximately 600 MMcf/d of firm capacity on each of the pipelines owned by El Paso Natural Gas Company (El Paso), NOVA and ANG, and 150 MMcf/d on the pipeline owned by Transwestern Pipeline Company (Transwestern) to service its core and core subscription customers. In addition, PG&E holds for its electric department approximately 50 MMcf/d on Transwestern. The Company is continuing its efforts to broker or assign any remaining unused capacity including certain amounts of that held for its core and core subscription customers when such capacity is not being used. Based on the current demand for Canadian pipeline capacity, the Company believes it will be able to broker or assign substantially all of its unused capacity on NOVA and ANG; however, due to lower demand for Southwest pipeline capacity, the Company cannot predict the volume or price of the capacity on El Paso and Transwestern that will be brokered or assigned. Substantially all demand charges incurred by the Company for pipeline capacity, including charges for capacity that is not brokered or brokered at a discount, are eligible for rate recovery subject to a reasonableness review. The Division of Ratepayer Advocates (DRA), a consumer advocacy branch of the CPUC staff, and others have challenged recovery of all demand charges for the Company's Transwestern capacity and of certain other demand charges for capacity not brokered or brokered at a discount. In November 1994, the CPUC approved an interim increase in gas rates, subject to refund, designed to collect approximately one-half of the demand charges for unbrokered or discounted El Paso and PGT capacity. The decision set hearings on the issue, and acknowledged that significant reasonable costs continue to accrue. The Company believes that the ultimate resolution of these matters will not have a significant adverse impact on its financial position or results of operations. Gas Reasonableness Proceedings: Recovery of energy 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. In March 1994, the CPUC issued decisions covering the years 1988 through 1990, ordering disallowances of $90 million of gas costs, plus accrued interest of approximately $25 million through 1993 for the Company's Canadian gas procurement activities, and $8 million for gas inventory operations. The Company has filed a lawsuit in a federal district court challenging the CPUC decision on Canadian gas costs. The CPUC decision on the Company's Canadian gas procurement activities found that the Company could have saved its customers money if it had bargained more aggressively with its then-existing Canadian suppliers or bought lower-priced gas from other Canadian sources. The CPUC concluded that it was appropriate for the Company to take a substantial portion of its Canadian gas (up to 700 MMcf/d) at the actual price charged under its then-existing Canadian gas supply contracts, but that the Company could have met the remainder of its Canadian gas requirement with lower-priced gas, either under those same contracts or with purchases from other Canadian natural gas sources. A number of other reasonableness issues related to the Company's gas procurement practices, transportation capacity commitments and supply operations for periods dating from 1988 to 1994 are still under review by the CPUC. The DRA recommended disallowances of $142 million and a penalty of $50 million and indicated that it was considering additional recommendations for pending issues. The Company and the DRA have signed settlement agreements to resolve most of these issues for a $68 million disallowance. Significant issues covered by the settlement agreements include (1) the Company's purchases of Canadian, Southwest and California gas for its electric department in 1991 and 1992 and its core customers from 1991 through May 1994; (2) the investigation by the DRA of A&S and proposed investigation of ANG for the period 1988 through May 1994; (3) the effects of Canadian gas prices on amounts paid by the Company for Northwest power purchases for 1988 through 1992 and power from QFs and geothermal producers for 1991 and 1992; (4) the Company's gas storage operations for 1991 and 1992; (5) the Company's Southwest gas procurement activities for 1988 through 1990; and (6) Canadian gas restructuring transition costs billed to PG&E by PGT. Agreements with the DRA do not constitute a CPUC decision and are subject to modification by the CPUC in its final decisions. 32 25 Financial Impact of Reasonableness Proceedings: The Company accrued approximately $135 million and $61 million in 1994 and 1993, respectively, for gas reasonableness matters including the CPUC decisions for the years 1988 through 1990 and issues covered by the settlement agreements. The Company believes the ultimate outcome of these matters will not have a significant impact on its financial position or results of operations. Note 4: Diablo Canyon Rate Case Settlement: The 1988 Diablo Canyon rate case settlement (Diablo Canyon settlement) bases revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. In approving the settlement, the CPUC explicitly affirmed that Diablo Canyon costs and operations should no longer be subject to CPUC reasonableness reviews. The Diablo Canyon settlement provides that only certain Diablo Canyon costs be recovered through base rates over the term of the Diablo Canyon settlement, including a full return on such costs. The related revenues to recover these costs are included in Diablo Canyon operating revenues for reporting purposes. Other than these and decommissioning costs, Diablo Canyon no longer meets the criteria for application of SFAS No. 71. Consequently, application of this statement was discontinued for Diablo Canyon effective July 1988. Pricing: In December 1994, the Company, the DRA, the California Attorney General and several other parties representing energy consumers agreed to modify the pricing provisions of the Diablo Canyon settlement. The modification, which is subject to CPUC approval, calls for a reduction in the price paid for electricity generated by Diablo Canyon over the next five years. Under the Diablo Canyon settlement, the price per kWh of electricity generated by Diablo Canyon consists of a fixed and an escalating component. The total prices for 1994, 1993 and 1992 were 11.89 cents, 11.16 cents and 10.34 cents per kWh, respectively. Under the proposed modification, the price for power produced by Diablo Canyon would be reduced from the current level as shown in the following table. Under the proposed pricing, at full operating power each Diablo Canyon unit would contribute approximately $2.9 million in revenues per day in 1995.
Diablo Canyon Price (cents) per kWh ----------------------------------- 1995 1996 1997 1998 1999 Original Settlement Price* 12.15 12.42 12.70 12.98 13.28 Proposed Price 11.00 10.50 10.00 9.50 9.00
- ---------------- * assumes 3.5% inflation After December 31, 1999, the escalating portion of the Diablo Canyon price would increase using the same formula specified in the original Diablo Canyon settlement. The proposed modification provides the Company with the right to reduce the price below the amount specified. The parties to the proposed modification have agreed that the difference between the Company's revenue requirement under the original Diablo Canyon settlement prices and the proposed prices would be applied to the energy cost balancing account until the undercollection in that account is fully amortized. Financial Information: Selected financial information for Diablo Canyon is shown below:
Year ended December 31, --------------------------- (in millions) 1994 1993 1992 Operating revenues $1,870 $1,933 $1,781 Operating income 618 708 663 Net income 461 496 443
In determining operating results of Diablo Canyon, operating revenues were specifically identified pursuant to the Diablo Canyon settlement. The majority of operating expenses were also specifically identified, including income tax expense. Administrative and general expense, principally labor costs, is allocated based on a study of labor costs. Interest is charged to Diablo Canyon based on an allocation of corporate debt. Note 5: Preferred Stock Nonredeemable preferred stock ($25 par value) consists of 5%, 5.5% and 6% series, which have rights to annual dividends per share of $1.25, $1.375 and $1.50, respectively. Redeemable preferred stock without mandatory redemption provisions (4.36 percent to 8.2 percent, $25 par value) is subject to redemption at the Company's option, in whole or in part, if the Company pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. Annual dividends and redemption prices per share range from $1.09 to $2.05, and from $25.75 to $28.125, respectively. The 6.30% (due 2004 to 2009) and the 6.57% (due 2002 to 2007) series of preferred stock are subject to mandatory redemption provisions and are entitled to sinking funds providing for the retirement of stock outstanding, beginning on January 31, 2004, and July 31, 2002, respectively, at par value plus accumulated and unpaid dividends through the redemption date. In addition, the 6.30% and 6.57% series may be redeemed at the Company's option at par value plus 33 26 accumulated and unpaid dividends on or after January 31, 2004, and July 31, 2002, respectively. The estimated fair value of the Company's preferred stock with mandatory redemption provisions at December 31, 1994 and 1993, was approximately $117 million and $81 million, respectively, based primarily on matrix pricing models. During 1994, the Company issued $63 million of 6.30% redeemable preferred stock and redeemed the 8.16% redeemable preferred stock with a par value of $75 million. During 1993, the Company issued $125 million of 6 7/8% redeemable preferred stock and $75 million of 7.04% redeemable preferred stock. Proceeds were used to finance a portion of the 1993 redemption of the Company's 9.00%, 9.30%, 9.48% and 10.17% redeemable preferred stock with an aggregate par value of $267 million. Dividends on preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Company, holders of the preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. Note 6: Long-term Debt Mortgage Bonds: The Company's First and Refunding Mortgage Bonds are issued in series, and at December 31, 1994, bear annual interest rates ranging from 4.25 percent to 12.75 percent and mature from 1995 to 2026. The Company had $5.9 billion and $6.0 billion of mortgage bonds outstanding at December 31, 1994 and 1993, respectively. Additional bonds may be issued, subject to CPUC approval, up to a maximum total amount outstanding of $10 billion, assuming compliance with indenture covenants for earnings coverage and property available as security. The Board of Directors (Board) may increase the amount authorized, subject to CPUC approval. The indenture requires that net earnings excluding depreciation and interest be equal to or greater than 1.75 times the annual interest charges on the Company's mortgage bonds outstanding. All real properties and substantially all personal properties of PG&E are subject to the lien of the indenture. The Company is required by the indenture to make semi-annual sinking fund payments on February 1 and August 1 of each year for the retirement of the bonds. These payments equal .5 percent of the aggregate bonded indebtedness outstanding on the preceding November 30 and May 31, respectively. Bonds of any series, with certain exceptions, may be used to satisfy this requirement. In addition, holders of series 84D bonds maturing in 2017 have an option to redeem their bonds in 1995. In conjunction with the Company's focus on reducing the levels of higher-cost debt, the Company redeemed or repurchased $80 million and $3,536 million of higher-cost mortgage bonds in 1994 and 1993, respectively. Interest rates on the bonds redeemed or repurchased ranged from 7.50 percent to 12.75 percent. In January 1995, the Board authorized the Company to redeem or repurchase up to $153 million of mortgage bonds. Included in the total of outstanding mortgage bonds are First and Refunding Mortgage Bonds issued by the Company to finance air and water pollution control and sewage and solid waste disposal facilities. These mortgage bonds are held in trust for the California Pollution Control Financing Authority (CPCFA), who arranged these financings, and are in addition to the Pollution Control Loan Agreements discussed below. At December 31, 1994 and 1993, the Company had outstanding $768 million of mortgage bonds held in trust for the CPCFA with interest rates ranging from 5.85 percent to 8.875 percent and maturity dates from 2007 to 2023. Pollution Control Loan Agreements: In addition to the pollution control loans secured by the Company's mortgage bonds (described above), the Company had loans totaling $925 million at December 31, 1994 and 1993, from the CPCFA to finance air and water pollution control and sewage and solid waste disposal facilities. Interest rates on the loans vary depending upon whether the loans are in a daily, weekly, commercial paper or fixed rate mode. Conversions from one mode to another take place at the Company's option. Average annual interest rates on these loans for 1994 ranged from 2.79 percent to 2.98 percent. These loans are subject to redemption on demand by the holder under certain circumstances and are secured by irrevocable letters of credit which mature as early as 1997. Medium-term Notes: The Company had $1,444 million of unsecured medium-term notes outstanding at December 31, 1994 with interest rates ranging from 4.13 percent to 9.90 percent and maturities from 1995 to 2014. At December 31, 1994, the Company has remaining $85 million on a previous authorization to repurchase medium-term notes. Holders of Series B medium-term notes maturing in 2004 have an option to redeem their notes in 1995. 34 27 Long-term Debt of Subsidiaries: PGT obtained long-term debt financing from a consortium of banks pursuant to a loan agreement dated April 30, 1993. Under the loan agreement, PGT borrowed $673 million to finance the pipeline expansion and its existing pipeline system. The debt is initially guaranteed by PG&E. The weighted average rate of interest on this loan during 1994 was 6.4 percent. The interest rate on the PGT debt (which ranged from 4.0 percent to 8.1 percent in 1994) is a floating rate subject to periodic determination in accordance with the terms of the loan agreement and may vary depending on the nature and the length of the borrowings, but is generally tied to the banks' base rate, domestic certificate of deposit rates, or the applicable London Interbank Offered Rates (LIBOR) for maturities ranging from one to twelve months. In 1994, PGT executed a series of interest rate swap transactions which converted $639 million of the floating rate debt to a fixed rate through July 31, 1999. The interest rate on the remaining debt outstanding, which is due in 1995, was fixed by utilizing options available to PGT under the loan agreement. At December 31, 1994, PGT had outstanding ten interest rate swap agreements with commercial banks with a total notional principal amount of $639 million. These swap agreements effectively change PGT's interest rate on its floating rate debt to a fixed rate of 8.4 percent. The interest rate swap agreements mature in July 1999. At December 31, 1994, the fair market value of these swap agreements represented an unrealized gain of $25.7 million. DALEN has a two-year revolving loan agreement expiring February 1997 which provides for maximum borrowings of $200 million at a variable interest rate. The revolving loan may be extended annually by consent of the banks and may be converted to a five-year term loan at DALEN's option. At December 31, 1994, approximately $115 million was outstanding at an effective interest rate of approximately 7 percent. The loan is secured by DALEN's oil and gas investments. Repayment Schedule: At December 31, 1994, the Company's combined aggregate amount of maturing long-term debt and sinking fund requirements, for the years 1995 through 1999, are $477 million, $373 million, $369 million, $715 million and $317 million, respectively. Fair Value: The estimated fair value of the Company's total long-term debt of $9.2 billion and $9.5 billion at December 31, 1994 and 1993, respectively, was approximately $8.6 billion (including the $25.7 million unrealized gain attributable to the PGT interest rate swap agreements) and $9.9 billion, respectively. The estimated fair value of long-term debt was determined based on quoted market prices, where available. Where quoted market prices were not available, the estimated fair value was determined using other valuation techniques (e.g., matrix pricing models or the present value of future cash flows). Note 7: Short-term Borrowings Short-term borrowings consist of commercial paper with a weighted average interest rate of 6.18 percent at December 31, 1994. The usual maturity for commercial paper is one to ninety days. Commercial paper outstanding at December 31, 1994 and 1993, was $525 million and $764 million, respectively. The carrying amount of short-term borrowings approximates fair value. The Company has a $1 billion revolving credit facility with various banks to support the sale of commercial paper and for other corporate purposes. There were no borrowings under this facility in 1994, 1993 or 1992. This credit facility expires in November 1999; however, it may be extended annually for additional one-year periods upon mutual agreement between the Company and the banks. Note 8: Investments in Debt and Equity Securities Effective January 1, 1994, the Company adopted SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," which established new financial accounting and reporting standards for investments in debt and equity securities. All of the Company's investments in debt and equity securities are included in Nuclear Decommissioning Funds and are classified as available-for-sale. These securities are held in external trust funds to be used for the decommissioning of the Company's nuclear facilities and are reported at fair value. Unrealized gains and losses are recorded to Accumulated Depreciation and Decommissioning, net of tax. Funds may not be released from the external trust funds until authorized by the CPUC. The proceeds received during 1994 from the sale of securities held as available-for-sale were approximately $1 billion. During 1994, the gross realized gains and losses on sales of securities held as available-for-sale were $9.9 million and $11.9 million, respectively. The cost of equity securities sold is determined by specific identification. The cost of debt securities sold is based on a first-in-first-out method. 35 28 The following table provides a summary of amortized cost and fair value by major security type:
- ------------------------------------------------------------------------------------------------ (in thousands) December 31, 1994 - ------------------------------------------------------------------------------------------------ Gross Gross unrealized unrealized Amortized holding holding Fair cost gains losses value --------- ---------- ---------- --------- Debt of U.S. Treasury and other federal entities $290,511 $ 20 $ (7,972) $282,559 State and local obligations 94,899 1,268 (2,485) 93,682 Equity Securities 184,954 18,556 (9,261) 194,249 Other 46,398 24 (275) 46,147 -------- ------- -------- -------- Total investments in securities $616,762 $19,868 $(19,993) $616,637 ======== ======= ======== ========
Investments in debt securities maturing within ten years totaled $293 million, and investments in debt securities with maturities in excess of ten years totaled $114 million. At December 31, 1993, the cost and estimated fair value of the decommissioning funds was $537 million and $576 million, respectively. Note 9: Employee Benefit Plans Retirement Plan: The Company provides a noncontributory defined benefit pension plan covering substantially all employees. The retirement benefits are based on years of service and the employee's base salary. The Company's funding policy is to contribute each year not more than the maximum amount deductible for federal income tax purposes and not less than the minimum contribution required under the Employee Retirement Income Security Act of 1974. At December 31, 1994, plan assets exceeded the projected benefit obligation by $517 million. The plan's funded status was:
December 31, ------------------------- (in thousands) 1994 1993 Actuarial present value of benefit obligations Vested benefits $(3,079,045) $(3,203,408) Nonvested benefits ( 131,489) (154,349) ----------- ----------- Accumulated benefit obligation (3,210,534) (3,357,757) Effect of projected future compensation increases ( 441,951) (577,926) ----------- ----------- Projected benefit obligation (3,652,485) (3,935,683) Plan assets at market value 4,169,516 4,376,110 ----------- ----------- Plan assets in excess of projected benefit obligation 517,031 440,427 Unrecognized prior service cost 93,425 117,312 Unrecognized net gain (908,485) (759,690) Unrecognized net transition obligation 108,800 120,253 ----------- ----------- Accrued pension liability $ (189,229) $ (81,698) =========== ===========
Plan assets consist substantially of common stocks and fixed-income securities. The unrecognized prior service cost is amortized over approximately 16 years. The unrecognized net transition obligation is amortized over approximately 18 years, beginning in 1987. The vested benefit obligation is the actuarial present value of vested benefits to which employees are currently entitled based on their expected termination dates. Assumptions used to calculate the projected benefit obligation to determine the plan's funded status were:
December 31, ---------------------- 1994 1993 Weighted average discount rate 8% 7% Average rate of projected future compensation increases 5% 5%
The cost of this plan is charged to expense and to plant in service through construction work in progress. Net pension cost, using the projected unit credit actuarial cost method, was:
Year ended December 31, ---------------------------------- (in thousands) 1994 1993 1992 Service cost for benefits earned $ 109,132 $ 129,166 $ 127,388 Interest cost 272,932 268,698 248,674 Actual loss (return) on plan assets 20,358 (511,526) (204,576) Net amortization and deferral (412,547) 177,597 (78,560) --------- --------- --------- Net pension (income) cost $ (10,125) $ 63,935 $ 92,926 ========= ========= =========
The decrease in net pension cost in 1994 compared to 1993 was primarily due to changes in the assumed rates of projected compensation increases and turnover to better reflect actual and expected rates. The decrease in net pension cost in 1993 compared to 1992 was primarily due to a change in the expected long-term rate of return on plan assets to better reflect actual and expected earnings on the funds invested. The expected long-term rate of return on plan assets used to calculate pension cost was nine percent for 1994 and 1993 and eight percent for 1992. Net pension cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future pension cost. In 1994, the plan experienced a negative rather 36 29 than an expected positive investment return on plan assets, due to weak performance in domestic equities and bonds. In 1993, actual return on plan assets exceeded expected return whereas, in 1992, actual return on plan assets was less than expected. In conformity with accounting for rate-regulated enterprises, regulatory adjustments have been recorded in the income statement and balance sheet for the difference between utility pension cost determined for accounting purposes and that for ratemaking, which is based on a contribution approach. Savings Fund Plan: The Company sponsors a defined contribution pension plan to which employees with at least one year of service may make contributions. Employees may contribute up to 15 percent of their covered compensation on a pretax or after-tax basis. These contributions, up to a maximum of six percent of covered compensation, are eligible for matching Company contributions at specified rates. The cost of Company contributions was charged to expense and to plant in service through construction work in progress and totaled $35 million, $36 million and $35 million for 1994, 1993 and 1992, respectively. Long-term Incentive Program: The Company implemented a Long-term Incentive Program (Program) in 1992. The Program allows eligible participants to be granted stock options with or without associated stock appreciation rights, dividend equivalents and/or performance-based units. The Program incorporates those shares previously authorized under the Company's 1986 Stock Option Plan. A total of 14.5 million shares of common stock have been authorized for award under the Program and the 1986 Stock Option Plan. Costs associated with the Program, which have not been significant, are not recoverable in rates. At December 31, 1994, stock options on 2,496,356 shares, granted at option prices ranging from $16.75 to $34.25, were outstanding. During 1994, 597,000 options were granted at an option price of $34.25, which was the market price per share on the date of grant. Outstanding stock options expire ten years and one day after the date of grant and become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant. Stock options also become exercisable within certain time limitations upon the optionee's termination due to retirement, disability or death, and upon certain changes in control of the Company. In 1994, 1993 and 1992, stock options on 52,143, 174,387 and 157,446 shares, respectively, were exercised at option prices ranging from $24.75 to $32.13, $16.75 to $33.13 and $16.75 to $26.63, respectively. At December 31, 1994, stock options on 940,076 shares were exercisable. Postretirement Benefits Other Than Pensions: The Company provides a contributory defined benefit medical plan for retired employees and their eligible dependents and a noncontributory defined benefit life insurance plan for retired employees. Substantially all employees retiring at or after age 55 are eligible for these benefits. The medical benefits are provided through plans administered by an insurance carrier or a health maintenance organization. Certain retirees are responsible for a portion of the cost based on past claims experience of the Company's retirees. In 1993, the Company implemented a plan change that will limit the amount it will contribute toward postretirement medical benefits. This limitation will take effect for all retirees beginning in 2001. The Company's funding policy for the medical and life insurance benefits is to contribute each year the amount provided for in rates. Life insurance benefits which are not funded are provided through an insurance company at a cost based on total current claims paid plus administrative fees. The cost of these plans is charged to expense and to plant in service through construction work in progress. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which requires accrual of the expected cost of these benefits during the employees' years of service. The assumptions and calculations involved in determining the accrual closely parallel pension accounting requirements. The Company previously recognized these costs as benefits were paid and funded, which was consistent with ratemaking. In December 1992, the CPUC issued a decision on the ratemaking treatment for these benefits in 1993 and beyond. The decision authorized recovery of these benefits, within certain guidelines, at a level equal to the lesser of the annual SFAS No. 106 cost, based on amortization of the transition obligation over 20 years, or the amount which can be contributed annually on a tax-deductible basis to appropriate trusts. Due to this regulatory treatment, adoption of SFAS No. 106 did not have a significant impact on the Company's financial position or results of operations. 37 30 At December 31, 1994, the accumulated postretirement benefit obligation exceeded plan assets by $427 million, principally due to recent adoption of SFAS No. 106. The medical and life insurance plans' funded status was:
(in thousands) December 31, ------------------------------- 1994 1993 Accumulated postretirement benefit obligation Retirees $(497,889) $(384,706) Other fully eligible participants (104,865) (148,018) Other active plan participants (219,639) (365,786) --------- --------- Total accumulated postretirement benefit obligation (822,393) (898,510) Plan assets at market value 394,939 345,938 --------- --------- Accumulated postretirement benefit obligation in excess of plan assets (427,454) (552,572) Unrecognized prior service cost 25,377 - Unrecognized net (gain) loss (115,249) 21,481 Unrecognized transition obligation 462,082 543,939 --------- --------- (Accrued) prepaid postretirement benefit liability $ (55,244) $ 12,848 ========= =========
The unrecognized prior service cost in 1994 reflects a plan amendment which provides an increase in benefits to certain retirees. It is amortized over approximately 18 years. Plan assets consist substantially of common stocks and fixed-income securities. In accordance with SFAS No. 106, the Company elected to amortize the actuarially-determined transition obligation over 20 years beginning in 1993. The plan change implemented in 1993 that will limit the Company's contributions toward postretirement medical benefits reduced the accumulated postretirement benefit obligation at July 1, 1993 by approximately $450 million. The assumptions used to calculate the benefit obligations included a weighted average discount rate of eight percent for 1994 and seven percent for 1993, and an average rate of projected future compensation increases of five percent for 1994 and 1993. The assumed health care cost trend rate for 1995 is approximately 11 percent, grading down to an ultimate rate in 2005 of approximately six percent. The effect of a one-percentage-point increase in the assumed health care cost trend rate for each future year would increase the accumulated postretirement benefit obligation at December 31, 1994, by approximately $110 million and the 1994 aggregate service and interest costs by approximately $13 million. Net postretirement medical and life insurance cost, using the projected unit credit actuarial cost method, was:
Year ended December 31, --------------------------- (in thousands) 1994 1993 Service cost for benefits earned $ 23,617 $ 38,496 Interest cost 64,872 73,502 Actual return on plan assets (1,232) (23,999) Amortization of unrecognized prior service cost 1,711 - Amortization of transition obligation 28,913 39,620 Net amortization and deferral (29,804) (3,390) -------- -------- Net postretirement benefit cost $ 88,077 $124,229 ======== ========
The decrease in net postretirement benefit cost in 1994 compared to 1993 was primarily due to the plan change implemented July 1, 1993 that will limit the Company's contributions toward postretirement medical benefits. The expected long-term rate of return on plan assets used to calculate postretirement medical and life insurance benefit costs was nine percent for 1994 and 1993. Net postretirement benefit cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future postretirement benefit cost. In 1994 and 1993, actual return on plan assets was less than expected return. For 1992, the cost of postretirement medical and life insurance benefits was based on benefits paid and funded and totaled $98 million. Workforce Reductions: The effects of workforce reductions announced by the Company in 1994 and 1993 are reflected in the pension and postretirement benefits funded status tables above and the costs are discussed in Note 10. Postemployment Benefits: Effective January 1, 1994, the Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits," which requires employers to adopt accrual accounting for benefits provided to former or inactive employees and their beneficiaries and covered dependents, after employment but before retirement. For the Company, such benefits consist primarily of long-term disability, workers' compensation, and continuation of medical and life insurance coverage. Due to current regulatory treatment, adoption of SFAS No. 112 did not have a significant impact on the Company's financial position or results of operations. Adoption of SFAS No. 112 resulted in an increase of approximately $90 million in noncurrent liabilities and deferred charges as of January 1, 1994. 38 31 Note 10: Workforce Reductions In 1994, the Company announced workforce reductions which when combined with the 3,000 positions eliminated in 1993 will result in the elimination of approximately 6,000 positions by the end of 1995. The majority of the reductions have occurred through voluntary retirement incentives (VRI) for employees 50 years of age with at least 15 years of service. Remaining reductions will be accomplished by severances and attrition in 1995. In December 1994, the Company expensed the total cost of the 1994 workforce reductions of $249 million and recorded a corresponding liability for benefits to be funded or paid. This amount consists of $136 million for additional pension benefits and $52 million for other postretirement benefits extended in connection with the VRI, and $61 million of estimated severance costs for approximately 1,500 severances. Most of these severances will be in the Customer Energy Services and Electric Supply business units, in functions that the Company has determined to be not absolutely necessary for safe, reliable and responsive service, including construction and certain staff and support services. The Company does not plan to seek rate recovery for the cost of the 1994 workforce reductions as it did with the 1993 workforce reductions. The total cost of the 1993 workforce reductions was $264 million, net of a curtailment gain relating to pension benefits. Included in this amount was $151 million for additional pension benefits and $22 million for other postretirement benefits extended in connection with the VRI. As a result of a freeze on electric rates, the Company expensed $190 million of workforce reduction costs relating to electric operations. The amount relating to gas operations was deferred for future rate recovery and is being amortized as savings are realized. At December 31, 1994, $31 million remained to be amortized. The Company recorded the costs and savings incurred in connection with the 1993 workforce reductions in a memorandum account authorized by the CPUC, with the recovery of such costs subject to a CPUC reasonableness review. Note 11: Income Taxes The current and deferred components of income tax expense were:
Year ended December 31, ----------------------------------- (in thousands) 1994 1993 1992 Current Federal $ 606,885 $ 417,558 $536,774 State 214,570 165,134 193,895 --------- ---------- -------- Total current 821,455 582,692 730,669 --------- ---------- -------- Deferred (substantially all federal) Depreciation 174,600 207,690 165,944 Regulatory balancing accounts 96,881 77,515 85,210 Workforce reduction (102,975) 24,765 - Gas reasonableness (47,952) (25,037) - (Gain) loss on reacquired debt (6,374) 42,405 15,959 Other--net (79,523) 12,270 (78,783) --------- ---------- -------- Total deferred 34,657 339,608 188,330 --------- ---------- -------- Investment tax credits--net (19,345) (20,410) (23,873) --------- ---------- -------- Total income tax expense $ 836,767 $ 901,890 $895,126 ========= ========== ======== Classification of income tax expense: Included in operating expenses $ 924,620 $1,006,774 $906,845 Included in other--net (87,853) (104,884) (11,719) --------- ---------- -------- Total income tax expense $ 836,767 $ 901,890 $895,126 ========= ========== ========
The significant components of net deferred income tax liabilities are as follows:
December 31, ------------------------------------ (in thousands) 1994 1993 - ----------------------------------------------------------------------------------------- Deferred income taxes assets: Deferred income taxes--current $ 173,357 $ 160,177 Deferred income taxes--noncurrent 959,459 647,018 ---------- ---------- Total deferred income tax assets 1,132,816 807,195 ========== ========== Deferred income tax liabilities: Deferred income taxes--current Regulatory balancing accounts 559,750 449,216 Other 45,633 26,545 ---------- ---------- Total deferred income taxes--current 605,383 475,761 ---------- ---------- Deferred income taxes-noncurrent Plant in service 3,627,294 3,386,122 Income tax-related deferred charges (1) 474,242 523,953 Other 760,568 715,893 ---------- ---------- Total deferred income taxes--noncurrent 4,862,104 4,625,968 ---------- ---------- Total deferred income tax liabilities 5,467,487 5,101,729 ========== ========== Total net deferred income taxes $4,334,671 $4,294,534 ========== ========== Classification of net deferred income taxes: Included in current liabilities $ 432,026 $ 315,584 Included in deferred credits 3,902,645 3,978,950 ---------- ---------- Total net deferred income taxes $4,334,671 $4,294,534 ========== ==========
(1) Represents the portion of the deferred income tax liability related to the revenues required to recover future income taxes. 39 32 The differences between income taxes and amounts determined by applying the federal statutory rate to income before income tax expense were:
Year ended December 31, ------------------------------- 1994 1993 1992 Federal statutory income tax rate 35.0% 35.0% 34.0% Increase (decrease) in income tax rate resulting from State income tax (net of federal benefit) 8.3 6.5 6.7 Effect of regulatory treatment of depreciation differences 3.7 4.5 5.0 Investment tax credits (1.1) (1.0) (1.2) Other--net (.5) .8 (1.2) ---- ---- ---- Effective tax rate 45.4% 45.8% 43.3% ==== ==== ====
Note 12: Commitments Capital Projects: Capital expenditures for 1995 are estimated to be approximately $1,544 million, consisting of $1,212 million for utility expenditures, $47 million for Diablo Canyon expenditures and $285 million for nonregulated expenditures. At December 31, 1994, Enterprises had firm commitments totaling $214 million to make capital contributions for its equity share of generating facility projects. The contributions, payable upon commercial operation of the projects, are estimated to be $100 million in 1995 and $114 million in 1996. QFs: Under the Public Utility Regulatory Policies Act of 1978, 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. QFs must meet certain performance obligations, depending on the contract, prior to receiving capacity payments. The total cost of both energy and capacity payments to QFs is recoverable in rates. The Company's contracts with QFs expire on various dates from 1995 to 2026. Under these contracts, the Company is required to make payments only when energy is supplied or when capacity commitments are met. Payments to QFs are expected to vary in future years. In 1994, the Company negotiated early termination or suspension of certain QF contracts at a cost of $155 million to be paid over a six-year period beginning in 1994. This amount was deferred and is expected to be recovered in future rates. QF deliveries in the aggregate account for approximately 21 percent of the Company's 1994 electric energy requirements and no single contract accounted for more than five percent of the Company's energy needs. QF deliveries in 1994 represented approximately 86 percent of the QFs' plant output, in the aggregate. The amount of energy received from QFs and the total energy and capacity payments made under these agreements were:
Year ended December 31, ----------------------------- (in millions) 1994 1993 1992 Kilowatthours received 21,699 21,242 21,173 Energy payments $ 1,196 $ 1,099 $ 1,084 Capacity payments $ 518 $ 503 $ 489
Irrigation Districts and Water Agencies: The Company has contracts with various irrigation districts and water agencies to purchase hydroelectric power. The contracts expire on various dates from 2004 to 2031. Under these contracts, the Company must make specified semi-annual minimum payments whether or not any energy is supplied, subject to the provider's retention of the FERC's authorization. Additional variable payments for operation and maintenance costs incurred by the providers are also required to be made under the contracts. The total cost of these payments is recoverable in rates. At December 31, 1994, the future minimum payments under these contracts are $34 million for each of the years 1995 through 1999 and a total of $451 million for periods thereafter. Total payments under these contracts were $49 million, $45 million and $54 million in 1994, 1993 and 1992, respectively. Note 13: Contingencies 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 1982 and various start-up problems related to the plant's generators, became commercially operable in 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 currently excluded from rate base and lost revenues during the period while the plant was under repair. In October 1994, the Company signed a settlement with the DRA regarding the recovery of Helms costs not currently in rate base and prior-year revenue requirements related to these costs. The settlement provides for recovery of substantially all of the remaining net unrecovered costs (after adjustment for depreciation) and revenues. The settlement has been submitted to the CPUC for approval. 40 33 The Company cannot predict whether the settlement will be approved by the CPUC. However, the Company does not believe the ultimate outcome of the matter will have a significant impact on its financial position or results of operations. Nuclear Insurance: The Company is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). Under these policies, if the nuclear plant of a member utility is damaged or the member incurs costs beyond those covered by insurance for business interruption due to a prolonged accidental outage, the Company may be subject to maximum assessments of $28 million (property damage) and $7 million (business interruption), in each case per policy period, in the event losses exceed the resources of NML or NEIL. The federal government has enacted laws that require all utilities with nuclear generating facilities to share in payment for claims resulting from a nuclear incident. The Price-Anderson Act limits industry liability for third-party claims resulting from any nuclear incident to $8.9 billion per incident. Coverage of the first $200 million is provided by a pool of commercial insurers. If a nuclear incident results in public liability claims in excess of $200 million, the Company may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental 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. The Company may be required to pay for remedial action at sites where the Company has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA; federal Superfund law) or the California Hazardous Substance Account Act (California Superfund law). These sites include former manufactured gas plant sites and sites used by the Company for the storage or disposal of materials which may be determined to present a significant threat to human health or the environment because of an actual or potential release of hazardous substances. Under CERCLA, the Company's financial responsibilities may include remediation of hazardous wastes, even if the Company did not deposit those wastes on the site. The overall costs of the hazardous materials and hazardous waste compliance and remediation activities ultimately undertaken by the Company are difficult to estimate due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Company has an accrued liability at December 31, 1994, of $95 million for hazardous waste remediation costs. The costs may be as much as $235 million if, among other things, the Company is held responsible for cleanup at additional sites, other potentially responsible parties are not financially able to contribute to these costs, or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. The Company will seek recovery of prudently incurred hazardous waste compliance and remediation costs through ratemaking procedures approved by the CPUC. The Company believes the ultimate outcome of these matters will not have a significant adverse impact on its financial position or results of operations. Legal Matters: Stanislaus Litigation: In 1993, a lawsuit was filed on behalf of the County of Stanislaus, California and a residential customer of the Company 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 lawsuit alleged that the purchase of natural gas in Canada by A&S was accomplished in violation of various antitrust laws resulting in increased prices of natural gas for PG&E's customers. Damages to the class members were estimated as potentially exceeding $800 million. The complaint indicated 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. In August 1994, a federal district court granted the Company's motion to dismiss the federal and state antitrust claims and the state unfair practices claims against the Company and PGT. The court also granted the plaintiffs' motion seeking class certification. In September 1994, the plaintiffs filed an amended complaint in which A&S has been added as a defendant. The amended complaint restates the claims in the original complaint and alleges that the defendants, through anticompetitive practices, precluded certain customers of the Company access to alternative sources of gas in Canada over the PGT pipeline. A new motion to dismiss was filed by the Company in early November 1994. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position. 41 34 Hinkley Litigation: In 1993, a complaint was filed in a state superior court on behalf 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, as well as punitive damages. The original complaint has been amended, and additional complaints have been filed, to include additional plaintiffs. The plaintiffs contend that the Company discharged chromium-contaminated wastewater into unlined ponds, which led to chromium percolating into the groundwater of surrounding property. The plaintiffs further allege that the Company discharged the chromium into those ponds to avoid costly alternatives. The Company has reached an agreement with plaintiffs pursuant to which those plaintiffs' actions will be submitted to binding arbitration for resolution of issues concerning the cause and extent of any damages suffered by plaintiffs as a result of the alleged chromium contamination. Under the terms of the agreement, the Company will pay an aggregate amount of no more than $400 million in settlement of such plaintiffs' claims, including $50 million paid to escrow to date. In turn, those plaintiffs, and their attorneys, agree to indemnify the Company against any additional losses the Company may incur with respect to related claims pursued by the identified plaintiffs who do not agree to this settlement or by other third parties who may be sued by the plaintiffs in connection with the alleged chromium contamination. At December 31, 1994, the Company has a remaining reserve of $50 million against any future potential liability in this case. The Company believes the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. County Franchise Fees Litigation: In March 1994, Santa Clara and Alameda counties filed a class action suit in a state superior court against the Company on behalf of themselves and 45 other counties in the Company's service area. This lawsuit alleges that the Company underpaid franchise fees to the counties for the right to use or occupy public streets or roads as a result of incorrectly computing these payments. Should the counties prevail, the amount of damages for alleged underpayments for the years 1987 through 1994 could be as high as $145 million, including interest, at Decmeber 31, 1994. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. City Franchise Fees Litigation: In May 1994, the City of Santa Cruz filed a class action suit in a state superior court against the Company on behalf of itself and 106 other cities in the Company's service area. The complaint alleges that the Company has underpaid electric franchise fees to the cities by calculating fees at different rates from other cities. Should the cities prevail, the amount of damages for alleged underpayments for the years 1987 through 1994 could be as high as $137 million, including interest, at December 31, 1994. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. 42 35 Pacific Gas and Electric Company Quarterly Consolidated Financial Data (Unaudited) Quarterly Financial Data: Due to the seasonal nature of the utility business and the scheduled refueling outages for Diablo Canyon, operating revenues, operating income and net income are not generated evenly by quarter during the year. In the first quarter of 1994, the Company took a charge against earnings of approximately $90 million as a result of the CPUC disallowances in the gas reasonableness proceedings for 1988 through 1990 and the Company's assessment of open reasonableness issues. In the second quarter of 1994, the Company increased its litigation reserves by $50 million. In the fourth quarter of 1994, the Company took a charge against earnings of $249 million related to 1994 workforce reductions. In the second quarter of 1993, the Company took a charge against earnings of $141 million related to the workforce reductions for management employees. In the third quarter of 1993, the Company's earnings reflected charges of $144 million resulting from the Company's workforce reductions, termination of Canadian gas contracts and an increase in the federal income tax rate. The fourth quarter of 1993 reflected charges against earnings of $126 million for Canadian gas costs incurred by the Company for 1988 through 1990 and for commitments for gas transportation capacity. The Company's common stock is traded on the New York, Pacific, London, Amsterdam, Basel and Zurich stock exchanges. There were approximately 230,000 common shareholders of record at December 31, 1994. Dividends are paid on a quarterly basis, and there are no significant restrictions on the present ability of the Company to pay dividends.
Quarter ended ---------------------------------------------------- (in thousands, except per share amounts) December 31 September 30 June 30 March 31 1994 Operating revenues $2,638,179 $2,855,221 $2,439,680 $2,514,271 Operating income 238,286 584,694 395,705 414,674 Net income 103,500 425,633 241,365 236,952 Earnings per common share (1) .21 .96 .53 .52 Dividends declared per common share .49 .49 .49 .49 Common stock price per share High 25.25 25.13 29.75 35.00 Low 21.38 22.00 22.50 28.50 1993 Operating revenues $2,707,171 $2,947,294 $2,464,125 $2,463,818 Operating income 428,914 525,981 387,707 420,328 Net income 208,382 356,099 245,350 255,664 Earnings per common share (1) .45 .79 .53 .56 Dividends declared per common share .47 .47 .47 .47 Common stock price per share High 36.75 36.63 35.38 35.75 Low 33.50 33.13 31.75 31.75
(1) Includes Diablo Canyon scheduled refueling outages which impacted earnings per common share for all quarters in 1994 and for the first and second quarters of 1993. In addition, Diablo Canyon experienced unscheduled outages in the second quarter of 1994. 43 36 Pacific Gas and Electric Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and the Board of Directors of Pacific Gas and Electric Company: We have audited the accompanying consolidated balance sheet and the statement of consolidated capitalization of Pacific Gas and Electric Company (a California corporation) and subsidiaries as of December 31, 1994 and 1993, and the related statements of consolidated income, cash flows, common stock equity and preferred stock, and the schedule of consolidated segment information for each of the three years in the period ended December 31, 1994. These financial statements and schedule of consolidated segment information are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements and schedule of consolidated segment information referred to above present fairly, in all material respects, the financial position of Pacific Gas and Electric Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. As discussed in Note 2 of Notes to Consolidated Financial Statements, in 1994, the California Public Utilities Commission (CPUC) issued a proposal to restructure the electric industry in California which could significantly alter the ratemaking applied to the Company. If this proposal is adopted or if electric generation rates are no longer based on cost of service, the Company would discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" for a portion of its operations. The CPUC's proposal could also impact the recovery of certain costs, including power purchase obligations and investments in related electric generation assets. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. As explained in Notes 1 and 9 of Notes to Consolidated Financial Statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits other than pensions and for income taxes. ARTHUR ANDERSEN LLP San Francisco, California February 6, 1995 44 37 Pacific Gas and Electric Company RESPONSIBILITY FOR FINANCIAL STATEMENTS The responsibility for the integrity of the financial information included in this report rests with management. Such information has been prepared in accordance with generally accepted accounting principles appropriate in the circumstances, and is based on the Company's best estimates and judgments after giving consideration to materiality. The Company maintains systems of internal controls supported by formal policies and procedures which are communicated throughout the Company. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and to produce the records necessary for the preparation of financial information. There are limits inherent in all systems of internal controls, based on the recognition that the costs of such systems should not exceed the benefits to be derived. The Company believes its systems provide this appropriate balance. In addition, the Company's internal auditors perform audits and evaluate the adequacy of and the adherence to these controls, policies and procedures. Arthur Andersen LLP, the Company's independent public accountants, considered the Company's systems of internal accounting controls and have conducted other tests as they deemed necessary to support their opinion on the consolidated financial statements. Their auditors' report contains an independent informed judgment as to the fairness, in all material respects, of the Company's reported results of operations and financial position. The financial data contained in this report have been reviewed by the Audit Committee of the Board of Directors. The Audit Committee is composed of six outside directors who meet regularly with management, the corporate internal auditors and Arthur Andersen LLP, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The Company maintains high standards in selecting, training and developing personnel to ensure that management's objectives of maintaining strong, effective internal controls and unbiased, uniform reporting standards are attained. The Company believes its policies and procedures provide reasonable assurance that operations are conducted in conformity with applicable laws and with its commitment to a high standard of business conduct. 45 38 EXHIBIT INDEX
Exhibit Sequentially Number Exhibit 11 Computation of Earnings per Common Share 12.1 Computation of Ratios of Earnings to Fixed Charges 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 23 Consent of Arthur Andersen LLP 27 Financial Data Schedule
EX-11 2 COMPUTATION OF EARNINGS PER COMMON SHARE 1 EXHIBIT 11 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF EARNINGS PER COMMON SHARE
- -------------------------------------------------------------------------------------------- Year ended December 31, ---------------------------------- (in thousands, except per share amounts) 1994 1993 1992 - -------------------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Net income $1,007,450 $1,065,495 $1,170,581 Less preferred dividends 57,603 63,812 78,887 ========== ========== ========== Net income for calculating EPS for Statement of Consolidated Income $ 949,847 $1,001,683 $1,091,694 ========== ========== ========== Average common shares outstanding 429,846 430,625 422,714 ========== ========== ========== EPS as shown in the Statement of Consolidated Income $ 2.21 $ 2.33 $ 2.58 ========== ========== ========== PRIMARY EPS (1) Net income $1,007,450 $1,065,495 $1,170,581 Less preferred dividends 57,603 63,812 78,887 ---------- ---------- ---------- Net income for calculating primary EPS $ 949,847 $1,001,683 $1,091,694 ========== ========== ========== Average common shares outstanding 429,846 430,625 422,714 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at average market price) 57 1,619 707 ---------- ---------- ---------- Average common shares outstanding as adjusted 429,903 432,244 423,421 ========== ========== ========== Primary EPS $ 2.21 $ 2.32 $ 2.58 ========== ========== ========== FULLY DILUTED EPS (1) Net income $1,007,450 $1,065,495 $1,170,581 Less preferred dividends 57,603 63,812 78,887 ---------- ---------- ---------- Net income for calculating fully diluted EPS $ 949,847 $1,001,683 $1,091,694 ========== ========== ========== Average common shares outstanding 429,846 430,625 422,714 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at the greater of average or ending market price) 57 1,895 1,134 ---------- ---------- ---------- Average common shares outstanding as adjusted 429,903 432,520 423,848 ========== ========== ========== Fully diluted EPS $ 2.21 $ 2.32 $ 2.58 ========== ========== ========== - --------------------------------------------------------------------------------------------
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K. This presentation is not required by APB Opinion No. 15, because it results in dilution of less than 3%. EX-12.1 3 COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES 1 EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- --------------------------------------------------------------------------------------- Year ended December 31, ---------------------------------------------------------- (dollars in thousands) 1994 1993 1992 1991 1990 - --------------------------------------------------------------------------------------- Earnings: Net income $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170 Company's equity in undistributed loss (earnings) of unconsolidated affiliates - - (3,349) 26,671 (2,799) Income tax expense 836,767 901,890 895,126 851,534 881,647 Net fixed charges 759,414 730,708 758,333 760,957 788,889 ---------- ---------- ---------- ---------- ---------- Total Earnings $2,603,631 $2,698,093 $2,820,691 $2,665,554 $2,654,907 ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 673,495 $ 642,408 $ 696,765 $ 682,811 $ 677,476 Interest on short- term debt 83,053 87,819 61,182 77,760 110,982 Interest on capital leases 1,758 1,737 1,737 1,737 1,737 ---------- ---------- ---------- ---------- ---------- Total Fixed Charges $ 758,306 $ 731,964 $ 759,684 $ 762,308 $ 790,195 ========== ========== ========== ========== ========== Ratios of Earnings to Fixed Charges 3.43 3.69 3.71 3.50 3.36 - ---------------------------------------------------------------------------------------
Note: For the purpose of computing the Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the Company's equity in undistributed earnings or loss of unconsolidated affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" consist of interest on short-term and long-term debt (including amortization of bond premium, discount and expense; and excluding interest on decommissioning trust funds [for which an equal amount of interest income is recorded] and amortization of the gain or loss on reacquired debt securities) and interest on capital leases (including capitalized interest). EX-12.2 4 RATIOS: EARNINGS TO COMB. FIXED CHARGES & PREF STK 1 EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- --------------------------------------------------------------------------------------- Year ended December 31, ---------------------------------------------------------- (dollars in thousands) 1994 1993 1992 1991 1990 - --------------------------------------------------------------------------------------- Earnings: Net income $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170 Company's equity in undistributed loss (earnings) of unconsolidated affiliates - - (3,349) 26,671 (2,799) Income tax expense 836,767 901,890 895,126 851,534 881,647 Net fixed charges 759,414 730,708 758,333 760,957 788,889 ---------- ---------- ---------- ---------- ---------- Total Earnings $2,603,631 $2,698,093 $2,820,691 $2,665,554 $2,654,907 ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 673,495 $ 642,408 $ 696,765 $ 682,811 $ 677,476 Interest on short- term debt 83,053 87,819 61,182 77,760 110,982 Interest on capital leases 1,758 1,737 1,737 1,737 1,737 ---------- ---------- ---------- ---------- ---------- Total Fixed Charges 758,306 731,964 759,684 762,308 790,195 ---------- ---------- ---------- ---------- ---------- Preferred Stock Dividends: Tax deductible dividends 4,672 4,814 5,136 5,136 5,136 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 96,039 108,937 130,147 154,404 175,881 ---------- ---------- ---------- ---------- ---------- Total Preferred Stock Dividends 100,711 113,751 135,283 159,540 181,017 ---------- ---------- ---------- ---------- ---------- Total Combined Fixed Charges and Preferred Stock Dividends $ 859,017 $ 845,715 $ 894,967 $ 921,848 $ 971,212 ========== ========== ========== ========== ========== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 3.03 3.19 3.15 2.89 2.73 - ---------------------------------------------------------------------------------------
Note: For the purpose of computing the Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the Company's equity in undistributed earnings or loss of unconsolidated affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" consist of interest on short-term and long-term debt (including amortization of bond premium, discount and expense; and excluding interest on decommissioning trust funds [for which an equal amount of interest income is recorded] and amortization of the gain or loss on reacquired debt securities) and interest on capital leases (including capitalized interest). "Preferred stock dividends" represent the sum of requirements for preferred stock dividends that are deductible for federal income tax purposes and requirements for preferred stock dividends that are not deductible for federal income tax purposes increased to an amount representing pretax earnings which would be required to cover such dividend requirements. EX-23 5 CONSENT OF ARTHUR ANDERSEN LLP 1 EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 6, 1995, included in Appendix I to the Report on Form 8-K dated March 2, 1995, into the Company's previously filed registration statements as follows: (1) Form S-3 Registration Statement File No. 33-7542 (relating to the Company's Common Stock Shelf Program); (2) Form S-3 Registration Statement File No. 33-54469 (relating to the Company's Dividend Reinvestment Plan); (3) Form S-3 Registration Statement File No. 33-64136 (relating to $2,000,000,000 aggregate principal amount of the Company's First and Refunding Mortgage Bonds and Medium-Term Notes); (4) Form S-3 Registration Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal amount of the Company's First and Refunding Mortgage Bonds); (5) Form S-3 Registration Statement File No. 33-38334 (relating to 2,414,892 shares of the Company's Common Stock); (6) Form S-8 Registration Statement File No. 33-50601 (relating to the Company's Savings Fund Plan for Employees); (7) Form S-8 Registration Statement File No. 33-23692 (relating to the Company's 1986 Stock Option Plan); and (8) Form S-3 Registration Statement File No. 33-62488 (relating to 10,000,000 shares of the Company's Redeemable First Preferred Stock). ARTHUR ANDERSEN LLP San Francisco, California March 2, 1995 EX-27 6 FINANCIAL DATA SCHEDULE
UT 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 19,398,778 1,952,669 3,539,055 2,918,631 0 27,809,133 2,151,213 3,806,508 2,677,304 8,635,025 137,500 732,995 8,675,091 0 0 524,685 477,047 0 0 0 8,626,790 27,809,133 10,447,351 924,620 7,889,372 8,813,992 1,633,359 118,794 1,752,153 744,703 1,007,450 57,603 949,847 840,627 651,912 2,947,687 2.21 2.21
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