FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 ---------------------------------- (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to -------- -------- <TABLE> <CAPTION> Exact Name of Commission Registrant State or other IRS Employer File as specified Jurisdiction of Identification Number in its charter Incorporation Number - ----------------------------------------------------------------- <S> <C> <C> <C> 1-12609 PG&E Corporation California 94-3234914 1-2348 Pacific Gas and California 94-0742640 Electric Company </TABLE> 77 Beale Street, P.O. Box 770000, San Francisco, California 94177 - -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrants' telephone number, including area code: (415) 973-7000 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ------- ------- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock Outstanding April 30, 1997: PG&E Corporation 408,852,050 shares Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY FORM 10-Q FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1997 TABLE OF CONTENTS PAGE PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME........................1 BALANCE SHEET...........................................2 STATEMENT OF CASH FLOWS ................................3 PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME........................4 BALANCE SHEET...........................................5 STATEMENT OF CASH FLOWS.................................6 NOTE 1: GENERAL...........................................7 NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING...................8 NOTE 3: NATURAL GAS MATTERS..............................12 NOTE 4: PG&E OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY PG&E SUBORDINATED DEBENTURES..............13 NOTE 5: COMMITMENTS AND CONTINGENCIES....................14 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.......................16 COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........17 ELECTRIC INDUSTRY RESTRUCTURING...........................17 Transition Cost Recovery...............................18 Competitive Market Framework...........................20 Accounting for the Effects of Regulation...............21 GAS INDUSTRY RESTRUCTURING................................23 ACQUISITIONS AND SALES....................................25 RESULTS OF OPERATIONS.....................................25 Common Stock Dividend..................................25 Earnings Per Common Share..............................26 Utility................................................26 Gas Holdings...........................................26 LIQUIDITY AND CAPITAL RESOURCES Sources of Capital.....................................26 Cost of Capital Application............................27 Environmental Matters..................................27 Legal Matters..........................................28 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS.........................................29 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......30 ITEM 5. OTHER INFORMATION.........................................33
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................34 SIGNATURE..........................................................36
PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> FOR THE THREE MONTHS ENDED MARCH 31, 1997 1996 ----------- ----------- <S> <C> <C> OPERATING REVENUES Electric and gas utility $2,273,978 $2,164,771 Gas transmission and marketing 1,048,883 52,642 Other 42,633 31,355 ----------- ----------- TOTAL OPERATING REVENUES 3,365,494 2,248,768 OPERATING EXPENSES Cost of electric energy 534,828 466,994 Cost of gas 1,205,354 188,137 Maintenance and other operating 452,487 456,474 Depreciation and decommissioning 459,117 302,947 Administrative and general 172,959 179,379 Property and other taxes 82,361 81,443 ----------- ----------- TOTAL OPERATING EXPENSES 2,907,106 1,675,374 ----------- ----------- OPERATING INCOME 458,388 573,394 Interest income 12,931 24,343 Interest expense (157,898) (169,560) Other income 18,065 4,071 Preferred dividend requirement and redemption premium (8,278) (8,278) ----------- ----------- PRETAX INCOME 323,208 423,970 Income Taxes 150,704 171,544 ----------- ----------- EARNINGS AVAILABLE FOR COMMON STOCK $ 172,504 $ 252,426 =========== =========== Weighted Average Common Shares Outstanding 408,526 414,351 EARNINGS PER COMMON SHARE $.42 $.61 Dividends Declared Per Common Share $.30 $.49 </TABLE> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 1
PG&E CORPORATION BALANCE SHEET (IN THOUSANDS) <TABLE> <CAPTION> BALANCE AT MARCH 31, DECEMBER 31, 1997 1996 ------------ ------------ <S> <C> <C> ASSETS PLANT IN SERVICE Electric $24,943,934 $24,757,479 Gas 6,671,501 6,558,413 Gas transmission 1,829,803 1,579,693 ------------ ------------ TOTAL PLANT IN SERVICE (AT ORIGINAL COST) 33,445,238 32,895,585 Accumulated depreciation and decommissioning (14,745,345) (14,301,934) ------------ ------------ NET PLANT IN SERVICE 18,699,893 18,593,651 CONSTRUCTION WORK IN PROGRESS 433,905 414,229 OTHER NONCURRENT ASSETS Nuclear decommissioning funds 898,954 882,929 Investment in nonregulated projects 819,925 817,259 Other assets 307,542 134,271 ------------ ------------ TOTAL OTHER NONCURRENT ASSETS 2,026,421 1,834,459 CURRENT ASSETS Cash and cash equivalents 120,334 143,402 Accounts receivable, net 1,511,427 1,539,186 Regulatory balancing accounts receivable 635,427 444,156 Inventories 490,762 530,085 Prepayments 58,107 54,116 ------------ ------------ TOTAL CURRENT ASSETS 2,816,057 2,710,945 DEFERRED CHARGES Income tax-related deferred charges 1,096,446 1,133,043 Other deferred charges 1,563,898 1,550,789 ------------ ------------ TOTAL DEFERRED CHARGES 2,660,344 2,683,832 ------------ ------------ TOTAL ASSETS $26,636,620 $26,237,116 ============ ============ CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity $ 8,420,791 $ 8,363,301 Preferred stock without mandatory redemption provisions 390,591 402,056 Preferred stock with mandatory redemption provisions 137,500 137,500 Company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures 300,000 300,000 Long-term debt 7,715,826 7,770,067 ------------ ------------ TOTAL CAPITALIZATION 16,964,708 16,972,924 CURRENT LIABILITIES Short-term borrowings 802,935 680,900 Current portion of long-term debt 12,643 209,867 Accounts payable Trade creditors 776,225 873,655 Other 515,329 365,499 Accrued taxes 529,779 310,271 Amounts due customers 302,046 186,899 Deferred income taxes 193,888 157,064 Interest payable 144,435 63,193 Dividends payable 133,470 123,310 Other 266,444 309,104 ------------ ------------ TOTAL CURRENT LIABILITIES 3,677,194 3,279,762 DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES Deferred income taxes 3,896,407 3,941,435 Deferred tax credits 369,919 379,563 Noncurrent balancing account liabilities 138,167 120,858 Other 1,590,225 1,542,574 ------------ ------------ TOTAL DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES 5,994,718 5,984,430 COMMITMENTS AND CONTINGENCIES (NOTES 2, 3, AND 5) -- -- ------------ ------------ TOTAL CAPITALIZATION AND LIABILITIES $26,636,620 $26,237,116 ============ ============ </TABLE> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 2
PG&E CORPORATION STATEMENT OF CASH FLOWS (IN THOUSANDS) <TABLE> <CAPTION> FOR THE THREE MONTHS ENDED MARCH 31, 1997 1996 --------- --------- <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income $172,504 $252,426 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and decommissioning 459,117 302,947 Amortization 33,720 24,204 Deferred income taxes and tax credits-net (43,905) (16,606) Other deferred charges (39,559) 79,424 Other noncurrent liabilities (23,570) (7,698) Noncurrent balancing account liabilities and other deferred credits 92,725 (48,919) Net effect of changes in operating assets and liabilities: Accounts receivable 107,129 299,289 Regulatory balancing accounts receivable (51,497) (142,412) Inventories 27,067 42,448 Accounts payable (33,764) (68,235) Accrued taxes 219,508 191,978 Other working capital 9,000 4,702 Other-net 40,880 23,801 --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 969,355 937,349 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (328,240) (218,437) Diversified operations (31,352) (38,339) Acquisition of Teco Pipeline Company (40,668) -- Other-net (15,771) (20,189) --------- --------- NET CASH USED BY INVESTING ACTIVITIES (416,031) (276,965) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock issued 13,544 57,657 Common stock repurchased (320,249) (39,364) Long-term debt matured, redeemed, or repurchased (257,486) (137,343) Short-term debt issued (redeemed)-net 122,035 (66,643) Dividends paid (130,737) (211,576) Other-net (3,499) (7,884) --------- --------- NET CASH USED BY FINANCING ACTIVITIES (576,392) (405,153) --------- --------- NET CHANGE IN CASH AND CASH EQUIVALENTS (23,068) 255,231 CASH AND CASH EQUIVALENTS AT JANUARY 1 143,402 734,295 --------- --------- CASH AND CASH EQUIVALENTS AT MARCH 31 $120,334 $989,526 ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid for: Interest (net of amounts capitalized) 67,448 67,477 Income taxes 26,010 45,638 </TABLE> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 3
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME (IN THOUSANDS) <TABLE> <CAPTION> FOR THE THREE MONTHS ENDED MARCH 31, 1997 1996 ----------- ----------- <S> <C> <C> OPERATING REVENUES Electric $1,722,005 $1,648,602 Gas 551,973 516,169 Other -- 83,997 ----------- ----------- TOTAL OPERATING REVENUES 2,273,978 2,248,768 OPERATING EXPENSES Cost of electric energy 510,118 466,994 Cost of gas 214,455 188,137 Maintenance and other operating 445,207 456,474 Depreciation and decommissioning 442,525 302,947 Administrative and general 137,400 179,379 Property and other taxes 79,029 81,443 ----------- ----------- TOTAL OPERATING EXPENSES 1,828,734 1,675,374 ----------- ----------- OPERATING INCOME 445,244 573,394 Interest income 10,404 24,343 Interest expense (144,042) (169,560) Other income and (expense) (1,068) 4,071 ----------- ----------- PRETAX INCOME 310,538 432,248 Income Taxes 137,959 171,544 ----------- ----------- NET INCOME 172,579 260,704 Preferred dividend requirement and redemption premium (8,278) (8,278) ----------- ----------- EARNINGS AVAILABLE FOR COMMON STOCK $ 164,301 $ 252,426 =========== =========== </TABLE> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 4
PACIFIC GAS AND ELECTRIC COMPANY BALANCE SHEET (IN THOUSANDS) <TABLE> <CAPTION> BALANCE AT MARCH 31, DECEMBER 31, 1997 1996 ------------ ------------ <S> <C> <C> ASSETS PLANT IN SERVICE Electric $24,931,831 $24,757,479 Gas 6,663,845 8,138,106 ------------ ------------ TOTAL PLANT IN SERVICE (AT ORIGINAL COST) 31,595,676 32,895,585 Accumulated depreciation and decommissioning (14,312,236) (14,301,934) ------------ ------------ NET PLANT IN SERVICE 17,283,440 18,593,651 CONSTRUCTION WORK IN PROGRESS 417,738 414,229 OTHER NONCURRENT ASSETS Nuclear decommissioning funds 898,954 882,929 Investment in nonregulated projects -- 817,259 Other assets 106,368 134,271 ------------ ------------ TOTAL OTHER NONCURRENT ASSETS 1,005,322 1,834,459 CURRENT ASSETS Cash and cash equivalents 39,879 143,402 Accounts receivable, net 1,013,045 1,539,186 Regulatory balancing accounts receivable 635,427 444,156 Inventories 476,901 530,085 Prepayments 25,068 54,116 ------------ ------------ TOTAL CURRENT ASSETS 2,190,320 2,710,945 DEFERRED CHARGES Income tax-related deferred charges 1,070,661 1,133,043 Other deferred charges 1,488,315 1,550,789 ------------ ------------ TOTAL DEFERRED CHARGES 2,558,976 2,683,832 ------------ ------------ TOTAL ASSETS $23,455,796 $26,237,116 ============ ============ CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity $ 7,148,657 $ 8,363,301 Preferred stock without mandatory redemption provisions 402,056 402,056 Preferred stock with mandatory redemption provisions 137,500 137,500 Company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures 300,000 300,000 Long-term debt 7,046,722 7,770,067 ------------ ------------ TOTAL CAPITALIZATION 15,034,935 16,972,924 CURRENT LIABILITIES Short-term borrowings 606,708 680,900 Current portion of long-term debt 9,587 209,867 Accounts payable Trade creditors 619,967 873,655 Other 420,834 365,499 Accrued taxes 509,331 310,271 Amounts due customers 302,046 186,899 Deferred income taxes 193,888 157,064 Interest payable 131,633 63,193 Dividends payable 8,318 123,310 Other 205,527 309,104 ------------ ------------ TOTAL CURRENT LIABILITIES 3,007,839 3,279,762 DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES Deferred income taxes 3,444,397 3,941,435 Deferred tax credits 369,579 379,563 Noncurrent balancing account liabilities 138,167 120,858 Other 1,460,879 1,542,574 ------------ ------------ TOTAL DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES 5,413,022 5,984,430 COMMITMENTS AND CONTINGENCIES (NOTES 2, 3, AND 5) -- -- ------------ ------------ TOTAL CAPITALIZATION AND LIABILITIES $23,455,796 $26,237,116 ============ ============ </TABLE> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 5
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CASH FLOWS (IN THOUSANDS) <TABLE> <CAPTION> FOR THE THREE MONTHS ENDED MARCH 31, 1997 1996 --------- --------- <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 172,579 $260,704 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and decommissioning 442,525 302,947 Amortization 33,060 24,204 Deferred income taxes and tax credits-net (61,602) (16,606) Other deferred charges (27,923) 79,424 Other noncurrent liabilities (16,371) (7,698) Noncurrent balancing account liabilities and other deferred credits 99,158 (48,919) Net effect of changes in operating assets and liabilities: Accounts receivable 68,016 299,289 Regulatory balancing accounts receivable (51,497) (142,412) Inventories 27,723 42,448 Accounts payable (144,757) (68,235) Accrued taxes 217,613 191,978 Other working capital (15,883) 4,702 Other-net 6,996 15,523 ----------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 749,637 937,349 ----------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (321,259) (218,437) Diversified operations -- (38,339) Other-net (97,468) (20,189) ----------- --------- NET CASH USED BY INVESTING ACTIVITIES (418,727) (276,965) ----------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Long-term debt matured, redeemed, or repurchased (222,719) (137,343) Short-term debt redeemed-net (74,192) (66,643) Dividends paid (130,889) (211,576) Other-net (6,633) 10,409 ----------- --------- NET CASH USED BY FINANCING ACTIVITIES (434,433) (405,153) ----------- --------- NET CHANGE IN CASH AND CASH EQUIVALENTS (103,523) 255,231 CASH AND CASH EQUIVALENTS AT JANUARY 1 143,402 734,295 ----------- --------- CASH AND CASH EQUIVALENTS AT MARCH 31 $ 39,879 $989,526 =========== ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Net assets of affiliates transferred to PG&E Corporation $1,142,294 -- Cash paid for: Interest (net of amounts capitalized) 65,388 67,477 Income taxes 25,957 45,638 </TABLE> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 6
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: GENERAL Holding Company Formation: - ------------------------- Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a subsidiary of its new parent holding company, PG&E Corporation. PG&E's ownership interest in Pacific Gas Transmission Company (PGT) and PG&E Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's outstanding common stock was converted on a share-for-share basis into PG&E Corporation's outstanding common stock. PG&E's debt securities and preferred stock were unaffected and remain securities of PG&E. Basis of Presentation: - --------------------- This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and PG&E. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation; PG&E; PGT; Enterprises; PG&E Gas Transmission, Texas Corporation (formerly known as Teco Pipeline Company); and PG&E Energy Trading (formerly known as Energy Source), as well as the accounts of their wholly owned and controlled subsidiaries (collectively, the Corporation). PG&E's consolidated financial statements include the accounts of PG&E and its wholly owned and controlled subsidiaries. Because PGT and Enterprises were wholly owned and controlled subsidiaries of PG&E during 1996, they are included in PG&E's 1996 consolidated financial statements. The "Notes to Consolidated Financial Statements" herein pertain to the Corporation and PG&E. Currently, PG&E's financial position and results of operations are the principal factors affecting the Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with the Corporation's and PG&E's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1996 Annual Report on Form 10-K. In the opinion of management, the accompanying statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. Certain amounts in the prior year's consolidated financial statements have been reclassified to conform to the 1997 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. Acquisitions and Sales: - ---------------------- In December 1996, PGT acquired Energy Source (now a part of PG&E Energy Trading) for approximately $23 million. PG&E Energy Trading, a gas marketing operation, has averaged $300 million in revenues each month since its acquisition. These revenues were offset by a corresponding increase in the cost of gas. In January 1997, PG&E Corporation acquired Teco Pipeline Company (now known as PG&E Gas Transmission, Texas Corporation) for approximately $380 million, consisting of $319 million of PG&E Corporation common stock and the purchase of a note payable of $61 million. PG&E Gas Transmission, Texas Corporation, a gas transmission and energy trading operation, has averaged $40 million in revenues each month since its acquisition. These revenues were primarily offset by an increase in the cost of gas. In April 1997, PG&E Corporation announced that it will consolidate certain energy trading and support operations of Teco Pipeline Company into PG&E Energy Trading. 7
On April 2, 1997, Bechtel Enterprises, Inc. (Bechtel) acquired Enterprises' interest in International Generating Company, Ltd., a joint venture between Enterprises and Bechtel. The sale resulted in an after-tax gain of approximately $110 million, which will be recorded in the second quarter of 1997. NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING In 1995, the California Public Utilities Commission (CPUC) issued a decision that provides a plan to restructure California's electric utility industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called "transition costs." In 1996, California legislation (restructuring legislation) was passed that adopts the basic tenets of the CPUC's restructuring decision, including recovery of transition costs. In addition, the restructuring legislation provides a 10 percent electric rate reduction for residential and small commercial customers by January 1, 1998, freezes electric customer rates for all other customers, and requires the accelerated recovery of transition costs associated with owned electric generation facilities. The restructuring legislation also establishes the operating framework for a competitive electric generation market. The rate freeze, mandated by the restructuring legislation, will continue until the earlier of March 31, 2002, or until PG&E has recovered its transition costs (the transition period). The freeze will hold rates at 1996 levels for all customers except those receiving the 10 percent rate reduction. The rate freeze will hold the rates for these customers at the reduced level. To achieve the 10 percent rate reduction, the restructuring legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current cost of capital. Once this portion of transition costs is financed, PG&E would collect a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs is expected to lower the amounts paid by these customers each year during the transition period, thereby achieving the 10 percent reduction in rates. During 1997, differences between authorized and actual base revenues (revenues to recover PG&E's non-energy costs and return on investment) and differences between the actual electric energy costs and the revenue designated for recovery of such costs are being recorded in balancing accounts. Any residual balance would be available for recovery of transition costs. Amounts recorded in balancing accounts will be subject to a reasonableness review by the CPUC. Transition Cost Recovery: - ------------------------ The restructuring legislation authorizes the CPUC to determine the costs eligible for recovery as transition costs. The amount of costs will be based on the aggregate of above-market and below-market values of utility-owned generation assets and obligations. PG&E has proposed that costs eligible for transition cost recovery include: (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and currently collected through rates) and future costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase 8
power at above-market prices from Qualifying Facilities (QFs) and other power suppliers, and (3) generation-related regulatory assets and obligations. PG&E cannot determine the exact amount of sunk costs that will be above market and recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each generation facility. This process will be completed during the transition period. In compliance with the CPUC's restructuring decision and the restructuring legislation, PG&E has filed numerous regulatory applications and proposals that detail its transition cost recovery plan. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of-service revenues for its electric operations into distribution, transmission, public purpose programs, and generation, (2) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period, and (3) accelerated recovery of transition costs. Under the proposed recovery plan, PG&E would receive a reduced return on common equity for certain transition costs related to generation facilities for which recovery is accelerated. The lower return reflects the reduced risk associated with the shorter amortization period and increased certainty of recovery. In applying its recovery plan to Diablo Canyon Nuclear Power Plant (Diablo Canyon), PG&E filed in 1996 a proposal for pricing Diablo Canyon generation at market prices and completing recovery of the investment in Diablo Canyon by the end of 2001. If this proposal is adopted, there would be a significant change to the manner in which Diablo Canyon earns revenues. Under its proposal, PG&E would replace the existing Diablo Canyon performance-based ratemaking (PBR) mechanism with: (1) a sunk cost revenue requirement to recover net investment in plant, including a return on this net investment, and (2) a PBR mechanism to recover the facility's variable and other operating costs and capital addition costs. As proposed by PG&E, the sunk cost revenue requirement would be set to accelerate recovery of Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five-year period beginning in 1997 and ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90 percent of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. PG&E's proposed PBR mechanism would establish a rate per kilowatt-hour (kWh) generated by the facility. This rate would be based upon a fixed forecast of on-going costs, capital additions, and capacity factors for the entire transition period. The reduced rate of return combined with a shorter recovery period is expected to result in an estimated $4 billion decrease in the net present value of PG&E's future revenues from Diablo Canyon operations. If the proposed cost recovery plan for Diablo Canyon had been adopted during 1996, PG&E's 1996 reported net income would have been reduced by $350 million ($0.85 per share), assuming that PG&E recovered no more than its actual variable costs under the PBR mechanism. In April 1997, an administrative law judge (ALJ) of the CPUC issued a Proposed Decision (ALJ PD) regarding PG&E's cost recovery plan for Diablo Canyon. The ALJ PD, which supersedes a previous proposed decision issued in February 1997, generally would adopt the overall ratemaking structure proposed by PG&E. However, the ALJ PD would exclude several items totaling $160 million from the sunk cost revenue requirement, including out-of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The ALJ PD requires that these costs be recovered through the PBR mechanism. The ALJ PD finds that PG&E's ratemaking proposal is subject to a requirement for a prudence review of the plant's original costs, and adopts a prudence disallowance which excludes approximately $70 million of Diablo Canyon construction costs from the sunk cost revenue requirement. In May 1997, a CPUC Commissioner issued an alternate proposed decision 9
(alternate PD) for the CPUC's consideration. Similar to the ALJ PD, the alternate PD would adopt the overall ratemaking structure proposed by PG&E. However, the alternate PD finds that a prudence review is not required and would include, in the sunk cost revenue requirement, the disallowed construction costs in the ALJ PD. The alternate PD also would include the above-market components of out-of-core nuclear fuel inventory, and materials and supplies inventory. Both the ALJ PD and the alternate PD would adopt the PBR mechanism that PG&E had proposed to recover Diablo Canyon's on-going costs and capital additions. However, both adopt PBR rates per kWh generated by Diablo Canyon which are different from those proposed by PG&E. Variances in these rates result principally from different assumptions used in the forecasts of Diablo Canyon capacity factors, operation and maintenance costs, and cost escalation factors. PG&E has proposed PBR rates for the years 1997 through 2001 of 3.59 cents, 3.71 cents, 3.86 cents, 4.04 cents, and 4.32 cents, respectively. The ALJ PD would set PBR rates for the years 1997 through 2001 of 3.26 cents, 3.31 cents, 3.37 cents, 3.43 cents, and 3.49 cents, respectively. The PBR rates set by the alternate PD are not fixed in advance but are subject to an escalation formula based on the previous year's consumer price index (CPI) less a 0.5 percent productivity factor. Based on a 3.1 percent annual CPI estimate, the alternate PD would set PBR rates for the years 1997 through 2001 of 3.54 cents, 3.62 cents, 3.71 cents, 3.80 cents, and 3.90 cents, respectively. If either the ALJ PD or the alternate PD is adopted, its effective date would be January 1, 1997. Both the ALJ PD and the alternate PD would terminate, rather than modify as proposed by PG&E, the existing Diablo Canyon ratemaking settlement on the date a final decision is adopted by the CPUC. PG&E has sought clarification from the CPUC that the termination of the settlement would not affect Diablo Canyon's "must take" status during the transition period. Neither the ALJ PD or the alternate PD is a final decision of the CPUC, and both are subject to change prior to final action by the CPUC. The PDs are currently scheduled for consideration by the full CPUC during the second quarter of 1997. Based upon PG&E's evaluation of the proposed decisions, the restructuring legislation, the CPUC's restructuring decision, and existing PG&E applications and proposals which would take effect in 1997, PG&E will depreciate Diablo Canyon over a five-year period ending in 2001. This five-year depreciation is consistent with PG&E's cost recovery plan which would provide sunk cost revenues over the same period. The change in depreciable life increased Diablo Canyon's first quarter depreciation expense by $144 million as compared to the same period in prior year. Most transition costs must be recovered by March 31, 2002. However, the restructuring legislation authorizes recovery of certain transition costs after that time. These costs include: (1) certain employee-related transition costs, (2) payments under existing QF and power purchase contracts, and (3) unrecovered implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. Excluding these exceptions, any transition costs not recovered during the transition period would be absorbed by PG&E. Nuclear decommissioning costs, which are not considered transition costs, will be recovered through a CPUC-authorized charge. During the transition period, this charge will be incorporated into the frozen electric rates. After the transition period, PG&E expects to assess an electric customer surcharge until the nuclear decommissioning costs are fully recovered. PG&E's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the extent to which application of the regulatory framework established by the restructuring legislation will continue to be applied, (2) the amount of 10
transition costs approved by the CPUC, (3) the market value of PG&E's generation plants, (4) future sales levels, (5) future fuel and operating costs, (6) the market price of electricity, and (7) the ratemaking methodology adopted for Diablo Canyon. Given its current evaluation of these factors, PG&E believes it will recover its transition costs and that its utility-owned generation plants are not impaired. However, a change in these factors could affect the probability of recovery of transition costs and result in a material loss. Accounting for the Effects of Regulation: - ---------------------------------------- PG&E accounts for the financial effect of regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows PG&E to record certain regulatory assets and liabilities which would be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires that regulatory assets be written off when they are no longer probable of recovery and that impairment losses be recorded for long-lived assets when related future cash flows are less than the carrying value of the assets. In applying the provisions of SFAS No. 71, PG&E has accumulated approximately $1.6 billion of regulatory assets attributable to electric generation at March 31, 1997. The net investments in Diablo Canyon and the other generation assets, including allocation of common plant, were $4.3 billion and $2.7 billion, respectively, at March 31, 1997. The net present value of above-market QF power purchase obligations is estimated to be $5.3 billion at January 1, 1998, at an assumed market price of $0.025 per kWh beginning in 1997 and escalating at 3.2 percent per year. PG&E believes that the restructuring legislation establishes a definitive transition to market-based pricing for electric generation that includes cost-of-service based ratemaking. In addition, under this framework, PG&E's generation-related transition costs will be collected through a nonbypassable charge. Based on this structure, PG&E believes its electric generation business will continue to meet the requirements of SFAS No. 71 as it relates to the transition costs throughout the transition period. At the conclusion of the transition period, PG&E believes it will be at risk to recover its generation costs through market-based revenues. At that time, PG&E expects to discontinue the application of SFAS No. 71 for the electric generation portion of its business. Since PG&E anticipates it will have recovered all transition costs required to be recovered during the transition period, including generation-related regulatory assets and above-market investments in net plant, the Corporation does not expect a material adverse impact on its or PG&E's financial position or results of operations from discontinuing the application at that time. As a result of California's electric industry restructuring and related legislation, the staff of the Securities and Exchange Commission (SEC) began discussions with PG&E and other California utilities regarding the appropriateness of the continued application of SFAS No. 71 for the generation portion of the electric utilities' businesses as of January 1, 1997. PG&E participated in discussions with the SEC staff and provided them with information in support of PG&E's position that it currently meets and will continue to meet the requirements to apply SFAS No. 71 throughout the transition period. Because of the importance of this issue to the electric utility industry in the United States, the SEC referred the issue to the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board. The EITF will provide the national forum needed to establish the uniform financial reporting and accounting standards necessary for determining if and when utilities should no longer be subject to SFAS No. 71 during a transition to market-based pricing within an industry restructuring. The SEC has 11
notified PG&E that it will no longer pursue the issue with PG&E unless the EITF cannot reach a consensus prior to the end of the year. The EITF will first meet to discuss this issue on May 22, 1997, with a decision expected this year. Once a standard is established by the EITF, PG&E will reevaluate the financial impact of electric industry restructuring in light of the new standard. If PG&E cannot meet the new standard established by the EITF and retain the accounting guidance provided by SFAS No. 71, PG&E would have a material write-off of its generation-related regulatory assets. In accordance with PG&E's cost recovery plan, approved by the CPUC in 1996, generation-related regulatory assets would continue to be recovered as part of the transition charge during the transition period. Given the current regulatory environment, PG&E's electric transmission business and most areas of the distribution business are expected to remain regulated and, as a result, PG&E will continue to apply the provisions of SFAS No. 71. However, in May 1997, the CPUC issued decisions that allow customers to choose their electricity provider beginning January 1, 1998. The decisions also allow the electricity provider to provide their customers with billing and metering services and indicate that electricity providers may be allowed to provide other distribution services (such as customer inquiries and uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these portions of PG&E's electric distribution business is not expected to have a material adverse impact on PG&E's or the Corporation's financial position or results of operations. NOTE 3: NATURAL GAS MATTERS In an effort to promote competition and to give all residential and smaller commercial (core) customers the same options that exist for industrial and larger commercial (noncore) customers, PG&E submitted the Gas Accord Settlement (Accord) to the CPUC for approval in 1996. In addition to offering increased customer choice, the Accord would establish gas transmission rates for the period July 1997 through December 2002 and resolve various pending regulatory issues. The major outstanding gas regulatory issues that the Accord would resolve include (1) the CPUC-ordered disallowances in connection with PG&E's 1988 through 1992 gas reasonableness proceedings and potential disallowances in connection with PG&E's 1993 through 1995 gas reasonableness proceedings; (2) the recovery of certain capital costs associated with PG&E's recently constructed California segment of the PG&E/PGT pipeline that extends from the Canadian border to Kern River Station in Southern California (the PG&E Pipeline Expansion); (3) the recovery of costs through 2002 related to PG&E's commitments to purchase capacity from Transwestern Pipeline Company; and (4) the recovery, through an interstate transition cost surcharge (ITCS), of fixed demand charges paid to El Paso Natural Gas Company and PGT for firm capacity held by PG&E on those pipelines. (ITCS costs are the difference between demand charges PG&E pays to El Paso Natural Gas Company and PGT for the reservation of interstate pipeline capacity that PG&E no longer uses to serve noncore customers, and the revenues PG&E obtains from brokering that capacity.) On March 24, 1997, an ALJ of the CPUC issued a PD rejecting the Accord. The major provisions of the Accord PD follow: (1) Under the Accord PD, the core procurement incentive mechanisms which had been proposed in the Accord to replace the traditional reasonableness review proceedings of PG&E's gas procurement costs for the periods 1994 through 1997 and 1998 through 2002 are not adopted. Therefore, the recovery of the cost of gas, as well as demand charges for gas transportation contracts used to procure gas, would be decided in various ongoing or future proceedings. (Demand charges are incurred by PG&E under gas transportation contracts with various Canadian and interstate pipeline companies for reserving pipeline capacity.) Further, under the Accord, PG&E agreed to forgo 12
recovery of $90 million of gas costs that the CPUC had disallowed in a 1988-90 reasonableness decision, irrespective of the results of PG&E's pending litigation in federal court challenging that decision. If the Accord is rejected by the CPUC, PG&E would consider whether to continue to pursue that challenge. (2) The Accord PD confirms the CPUC's 1994 finding that PG&E's decision to construct the PG&E Pipeline Expansion was reasonable based on the knowledge PG&E management had at the time. However, the Accord PD would reverse the CPUC's original order which found that PG&E would not be responsible for stranded costs caused by the PG&E Pipeline Expansion. The Accord PD defines stranded costs caused by the PG&E Pipeline Expansion to include ITCS costs and costs of unused original system transmission facilities on PG&E's two other major intrastate pipelines. The Accord PD states that PG&E should absorb these stranded costs to maintain incremental ratemaking and to avoid imposing the costs and risks of the PG&E Pipeline Expansion on the customers of the original transmission system. If the Accord PD were adopted without change by the CPUC, PG&E would be required to offer three separate unbundled pipeline services on its major intrastate transmission pipelines (the PG&E Pipeline Expansion and two others) and would be at risk for recovery of the cost of all such service, with no balancing account protection. (3) The Accord PD would disallow recovery of 25 percent of ITCS costs for 1993 and 1994, with reasonableness reviews to determine the amount of ITCS costs that could be recovered in subsequent years. In the Accord PD, the ALJ indicates that he supports a similar 25 percent disallowance for subsequent periods. However, the Accord PD also would suspend PG&E's authority to record ITCS costs for future recovery subsequent to the date of the final CPUC decision. The Accord PD would suspend such authority until PG&E could demonstrate that the conflict of interest the ALJ perceives to exist between ratepayer and shareholder interests causes ratepayers no harm due to lost revenues from brokering PG&E's unused interstate pipeline capacity. Under the Accord, in contrast, PG&E would forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated for collection from its core and noncore customers, respectively. (4) The Accord PD would set for further hearing the pipeline expansion project reasonableness (PEPR) proceeding to determine the capital costs and revenue requirements of the PG&E Pipeline Expansion, rejecting the resolution of those issues which had been proposed in the Accord. In the Accord, PG&E had agreed to set rates for the PG&E Pipeline Expansion based on total capital costs of $736 million. However, in the PEPR proceeding, PG&E had sought $810 million in capital costs. The CPUC's Office of Ratepayer Advocates had recommended a $100 million disallowance of capital costs and other parties had recommended a disallowance of $237 million. As of March 31, 1997, the Corporation has reserved approximately $529 million relating to various gas regulatory issues and capacity commitments, the majority of which are addressed by the Accord. As a result, the Corporation believes the ultimate resolution of these matters, whether through approval of the Accord or otherwise, will not have a material impact on its or PG&E's financial position or future results of operations. NOTE 4: PG&E OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY PG&E SUBORDINATED DEBENTURES PG&E, through its wholly owned subsidiary, PG&E Capital I (Trust), has outstanding $12 million shares of 7.90% cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to PG&E 371,135 shares of common securities with an aggregate liquidation value of approximately $9 million. The only assets of the Trust are deferrable interest subordinated debentures issued by PG&E with a face value of 13
approximately $309 million, an interest rate of 7.90%, and a maturity date of 2025. NOTE 5: COMMITMENTS AND CONTINGENCIES Nuclear Insurance: - ----------------- PG&E has insurance coverage for property damage and business interruption losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). Under these policies, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, PG&E may be subject to maximum assessments of $28 million (property damage) and $8 million (business interruption), in each case per policy period, in the event losses exceed the resources of NML or NEIL. PG&E has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $8.7 billion of coverage is provided by secondary financial protection which is mandated by federal legislation and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, PG&E may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: - ------------------------- The Corporation may be required to pay for environmental remediation at sites where the Corporation has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or the California Hazardous Substance Account Act. These sites include former manufactured gas plant sites and sites used by the Corporation 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 Corporation's financial responsibilities may include remediation of hazardous substances, even if the Corporation did not deposit those substances on the site. The Corporation records a liability when site assessments indicate remediation is probable and a range of reasonably likely cleanup costs can be estimated. The Corporation reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. Unless there is a better estimate within this range of possible costs, the Corporation records the lower end of this range (classified as other noncurrent liabilities). The cost of the hazardous substance remediation ultimately undertaken by the Corporation is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Corporation's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Corporation had an accrued liability at March 31, 1997, of $171 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $400 million if, among other things, other 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 Corporation is responsible. This upper limit of the range of costs was estimated using 14
assumptions least favorable to the Corporation, based upon a range of reasonably possible outcomes. Costs may be higher if the Corporation is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. PG&E will seek recovery of prudently incurred hazardous substance remediation costs through ratemaking procedures approved by the CPUC. PG&E has recorded a regulatory asset at March 31, 1997, of $142 million for recovery of these costs in future rates. Additionally, the Corporation will seek recovery of costs from insurance carriers and from other third parties. The Corporation believes the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. Helms Pumped Storage Plant (Helms): - ---------------------------------- Helms is a three-unit hydroelectric combined generating and pumped storage plant. At March 31, 1997, PG&E's net investment was $710 million. This net investment is comprised of the pumped storage facility (including regulatory assets of $51 million), common plant, and dedicated transmission plant. As part of the 1996 General Rate Case decision in December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of Helms. In July 1996, PG&E submitted its study, which concluded that the continued operation of Helms is cost effective. As a result of the study, PG&E recommended that the CPUC take no action and address Helms along with other generating plants in the context of electric industry restructuring. PG&E is currently unable to predict whether there will be a change in rate recovery resulting from the study. As with its other hydroelectric generating plants, PG&E expects to seek recovery of its net investment in Helms through PBR and transition cost recovery. PG&E believes that the ultimate outcome of this matter will not have a material adverse impact on its or the Corporation's financial position or results of operations. Legal Matters: - ------------- Cities Franchise Fees Litigation: In 1994, the City of Santa Cruz filed a class action suit in a state superior court (Court) against PG&E on behalf of itself and 106 other cities in PG&E's service area. The complaint alleges that PG&E has underpaid electric franchise fees to the cities by calculating those fees at different rates from other cities not included in the complaint. In September 1995, the Court certified the class of 107 cities in this suit and approved the City of Santa Cruz as the class representative. In January and March 1996, the Court made two rulings against certain cities effectively eliminating a major portion of the suit. The Court's rulings do not resolve the suit completely. The cities appealed both rulings. The trial has been postponed pending the cities' appeal. Should the cities prevail on the issue of franchise fee calculation methodology, PG&E's annual systemwide city electric franchise fees could increase by approximately $16 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $147 million (exclusive of interest, estimated to be $42 million at March 31, 1997). If the Court's January and March 1996 rulings become final, PG&E's annual systemwide city electric franchise fees for the remaining class member cities not subject to the Court's rulings could increase by approximately $5 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $40 million (exclusive of interest, estimated to be $11 million at March 31, 1997). The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or PG&E's financial position or results of operations. Chromium Litigation: In 1994 through 1997, several civil complaints were 15
filed against PG&E on behalf of more than 2,500 individuals. The complaints seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of PG&E's gas compressor stations at Hinkley, Kettleman, and Topock. PG&E is responding to the complaints and asserting affirmative defenses. PG&E will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defenses including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or PG&E's financial position or results of operations. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The "Management's Discussion And Analysis Of Financial Condition And Results Of Operations" herein pertain to Pacific Gas and Electric Company (PG&E) and its new parent holding company, PG&E Corporation, of which PG&E became a subsidiary effective January 1, 1997. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation; PG&E; Pacific Gas Transmission Company (PGT); PG&E Enterprises (Enterprises); PG&E Gas Transmission, Texas Corporation (formerly known as Teco Pipeline Company); and PG&E Energy Trading (formerly known as Energy Source), as well as the accounts of their wholly owned and controlled subsidiaries (collectively, the Corporation). It should be noted that the discussion and analysis of PG&E's financial condition and results of operations also apply to the Corporation since PG&E's financial condition and results of operations are currently the principal factors affecting the Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with the Corporation's and PG&E's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1996 Annual Report on Form 10-K. The following discussion of consolidated results of operations and financial condition contains forward-looking statements that involve risks and uncertainties. These forward-looking statements include discussion of the financial impacts of gas and electric industry restructuring. Words such as "estimates," "expects," "anticipates," "plans," "believes," and similar expressions also identify forward-looking statements involving risks and uncertainties. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas industries, the outcome of the regulatory proceedings related to that restructuring, the continued appropriateness and timing of the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," to the generation portion of the electric utility business, PG&E's ability to collect revenues sufficient to recover transition costs in accordance with its cost recovery plan, the final decision on the proposal for pricing generation from the Diablo Canyon Nuclear Power Plant (Diablo Canyon) at market prices, and the final decision regarding the Gas Accord Settlement (Accord). The ultimate impacts on future results of increased competition, the changing regulatory environment, and the Corporation's expansion into new businesses and markets are uncertain, but all are expected to fundamentally change how the Corporation conducts its business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by the Corporation and PG&E. 16
COMPETITION AND CHANGING REGULATORY ENVIRONMENT: The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and to ensure that these services were provided at fair prices. Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies are challenging the utilities' exclusive relationship with customers and are seeking to replace certain utility functions with their own. Customers, too, are asking for choice in their energy provider. These pressures are causing a move from the existing regulatory framework to a framework under which competition would be allowed in certain segments of the gas and electric industries. For several years, PG&E has been working with its regulators to achieve an orderly transition to competition and to ensure that PG&E has an opportunity to recover investments made under the traditional regulatory policies. In addition, PG&E has proposed alternative forms of regulation for those services for which prices and terms will not be determined by competition. These alternative forms include performance-based ratemaking (PBR) and other incentive-based alternatives. Over the next five years, a significant portion of PG&E's business will be transformed from the current utility monopoly to a competitive operation. This change will impact PG&E's financial results and may result in greater earnings volatility. During the transition period, PG&E expects the return on Diablo Canyon and certain other generation assets to be significantly lower than historical levels. ELECTRIC INDUSTRY RESTRUCTURING: In 1995, the California Public Utilities Commission (CPUC) issued a decision that provides a plan to restructure California's electric utility industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called "transition costs." In 1996, California legislation (restructuring legislation) was passed that adopts the basic tenets of the CPUC's restructuring decision, including recovery of transition costs. In addition, the restructuring legislation provides a 10 percent electric rate reduction for residential and small commercial customers by January 1, 1998, freezes electric customer rates for all other customers, and requires the accelerated recovery of transition costs associated with owned electric generation facilities. The restructuring legislation also establishes the operating framework for a competitive electric generation market. The rate freeze, mandated by the restructuring legislation, would continue until the earlier of March 31, 2002, or until PG&E has recovered its transition costs (the transition period). The freeze will hold rates at 1996 levels for all customers except those receiving the 10 percent rate reduction. The rate freeze will hold the rates for these customers at the reduced level. To achieve the 10 percent rate reduction, the restructuring legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend 17
beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current cost of capital. Once this portion of transition costs is financed, PG&E would collect a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs is expected to lower the amounts paid by these customers each year during the transition period, thereby achieving the 10 percent reduction in rates. During 1997, differences between authorized and actual base revenues (revenues to recover PG&E's non-energy costs and return on investment) and differences between the actual electric energy costs and the revenue designated for recovery of such costs are being recorded in balancing accounts. Any residual balance would be available for recovery of transition costs. Amounts recorded in balancing accounts will be subject to a reasonableness review by the CPUC. Absent the rate freeze, PG&E's rates would be expected to decline under existing cost-based ratemaking methodologies. The most significant reasons for the decrease in cost-based rates would be the declining cost of power committed under certain purchased power contracts, the reduction in the Diablo Canyon price for power under the existing CPUC-approved settlement (see below), and the decline in uncollected electric balancing accounts. Transition Cost Recovery: - ------------------------ The restructuring legislation authorizes the CPUC to determine the costs eligible for recovery as transition costs. The amount of costs will be based on the aggregate of above-market and below-market values of utility-owned generation assets and obligations. PG&E has proposed that costs eligible for transition cost recovery include: (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and currently collected through rates) and future costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from Qualifying Facilities (QFs) and other power suppliers, and (3) generation-related regulatory assets and obligations. PG&E cannot determine the exact amount of sunk costs that will be above market and recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each generation facility. This process will be completed during the transition period. In compliance with the CPUC's restructuring decision and the restructuring legislation, PG&E has filed numerous regulatory applications and proposals that detail its transition cost recovery plan. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of-service revenues for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period, and (3) accelerated recovery of transition costs. The unbundling of PG&E's revenue requirement would enable it to separate revenue provided by frozen rates into transmission, distribution, PPPs, and generation. As proposed, revenues collected under frozen rates would be assigned to transmission, distribution, and PPPs based upon their respective cost of service. Revenue would also be provided for other costs, including nuclear decommissioning, rate-reduction-bond debt service, the on-going cost of generation, and transition cost recovery. PG&E expects that the combination of a rate freeze and decreasing costs, based upon existing ratemaking and cost recovery periods, would provide an adequate amount of revenue available for full transition cost recovery. Under the proposed recovery plan, PG&E would receive a reduced return on common equity for certain transition costs related to generation facilities for which recovery is accelerated. The lower return reflects the reduced risk associated with the shorter amortization period and increased certainty of 18
recovery. In applying its recovery plan to Diablo Canyon, PG&E filed in 1996 a proposal for pricing Diablo Canyon generation at market prices and completing recovery of the investment in Diablo Canyon by the end of 2001. If this proposal is adopted, there would be a significant change to the manner in which Diablo Canyon earns revenues. Under its proposal, PG&E would replace the existing Diablo Canyon PBR mechanism with: (1) a sunk cost revenue requirement to recover net investment in plant, including a return on this net investment, and (2) a PBR mechanism to recover the facility's variable and other operating costs and capital addition costs. As proposed by PG&E, the sunk cost revenue requirement would be set to accelerate recovery of Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five-year period beginning in 1997 and ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90 percent of PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. PG&E's proposed PBR mechanism would establish a rate per kilowatt-hour (kWh) generated by the facility. This rate would be based upon a fixed forecast of on-going costs, capital additions, and capacity factors for the entire transition period. The reduced rate of return combined with a shorter recovery period is expected to result in an estimated $4 billion decrease in the net present value of PG&E's future revenues from Diablo Canyon operations. If the proposed cost recovery plan for Diablo Canyon had been adopted during 1996, PG&E's 1996 reported net income would have been reduced by $350 million ($0.85 per share), assuming that PG&E recovered no more than its actual variable costs under the PBR mechanism. In April 1997, an administrative law judge (ALJ) of the CPUC issued a Proposed Decision (ALJ PD) regarding PG&E's cost recovery plan for Diablo Canyon. The ALJ PD, which supersedes a previous proposed decision issued in February 1997, generally would adopt the overall ratemaking structure proposed by PG&E. However, the ALJ PD would exclude several items totaling $160 million from the sunk cost revenue requirement, including out-of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The ALJ PD requires that these costs be recovered through the PBR mechanism. The ALJ PD finds that PG&E's ratemaking proposal is subject to a requirement for a prudence review of the plant's original costs, and adopts a prudence disallowance which excludes approximately $70 million of Diablo Canyon construction costs from the sunk cost revenue requirement. In May 1997, a CPUC Commissioner issued an alternate proposed decision (alternate PD) for the CPUC's consideration. Similar to the ALJ PD, the alternate PD would adopt the overall ratemaking structure proposed by PG&E. However, the alternate PD finds that a prudence review is not required and would include in the sunk cost revenue requirement the disallowed construction costs in the ALJ PD. The alternate PD also would include the above-market components of out-of-core nuclear fuel inventory, and materials and supplies inventory. Both the ALJ PD and the alternate PD would adopt the PBR mechanism that PG&E had proposed to recover Diablo Canyon's on-going costs and capital additions. However, both adopt PBR rates per kWh generated by Diablo Canyon which are different from those proposed by PG&E. Variances in these rates result principally from different assumptions used in the forecasts of Diablo Canyon capacity factors, operation and maintenance costs, and cost escalation factors. PG&E has proposed PBR rates for the years 1997 through 2001 of 3.59 cents, 3.71 cents, 3.86 cents, 4.04 cents, and 4.32 cents, respectively. The ALJ PD would set PBR rates for the years 1997 through 2001 of 3.26 cents, 3.31 cents, 3.37 cents, 3.43 cents, and 3.49 cents, respectively. The PBR rates set by the alternate PD are not fixed in advance but are subject to an escalation formula based on the previous year's consumer price index (CPI) less a 0.5 percent productivity factor. Based on a 3.1 percent annual CPI 19
estimate, the alternate PD would set PBR rates for the years 1997 through 2001 of 3.54 cents, 3.62 cents, 3.71 cents, 3.80 cents, and 3.90 cents, respectively. If either the ALJ PD or the alternate PD is adopted, its effective date would be January 1, 1997. Both the ALJ PD and the alternate PD would terminate, rather than modify as proposed by PG&E, the existing Diablo Canyon ratemaking settlement on the date a final decision is adopted by the CPUC. PG&E has sought clarification from the CPUC that the termination of the settlement would not affect Diablo Canyon's "must take" status during the transition period. Neither the ALJ PD or the alternate PD is a final decision of the CPUC, and both are subject to change prior to final action by the CPUC. The PDs are currently scheduled for consideration by the full CPUC during the second quarter of 1997. Based upon PG&E's evaluation of the proposed decisions, the restructuring legislation, the CPUC's restructuring decision, and existing PG&E applications and proposals which would take effect in 1997, PG&E will depreciate Diablo Canyon over a five-year period ending in 2001. This five-year depreciation is consistent with PG&E's cost recovery plan which would provide sunk cost revenues over the same period. The change in depreciable life increased Diablo Canyon's first quarter depreciation expense by $144 million as compared to the same period in the prior year. Most transition costs must be recovered by March 31, 2002. However, the restructuring legislation authorizes recovery of certain transition costs after that time. These costs include: (1) certain employee-related transition costs, (2) payments under existing QF and power purchase contracts, and (3) unrecovered implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. Excluding these exceptions, any transition costs not recovered during the transition period would be absorbed by PG&E. Nuclear decommissioning costs, which are not considered transition costs, will be recovered through a CPUC authorized charge. During the transition period, this charge will be incorporated into the frozen electric rates. After the transition period, PG&E expects to assess an electric customer surcharge until the nuclear decommissioning costs are fully recovered. PG&E's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the extent to which application of the regulatory framework established by the restructuring legislation will continue to be applied, (2) the amount of transition costs approved by the CPUC, (3) the market value of PG&E's generation plants, (4) future sales levels, (5) future fuel and operating costs, (6) the market price of electricity, and (7) the ratemaking methodology adopted for Diablo Canyon. Given its current evaluation of these factors, PG&E believes it will recover its transition costs and that its utility-owned generation plants are not impaired. However, a change in these factors could affect the probability of recovery of transition costs and result in a material loss. Competitive Market Framework: - ---------------------------- In addition to transition cost recovery, the restructuring legislation establishes the operating framework for the competitive generation market in California. This framework will consist of a power exchange (PX) and an independent system operator (ISO). The PX, open to all electricity providers, will conduct a competitive auction to establish the price of electricity. The ISO is expected to ensure system reliability and provide all electricity generators with open and comparable access to transmission and distribution services. Although the PX will be available to all customers through their local 20
utility, the restructuring legislation allows customers to bypass the PX and purchase electricity directly from electricity providers. Customers electing to bypass the PX are referred to as direct access customers. In May 1997, the CPUC issued two decisions related to direct access: the direct access decision and the revenue cycle services decision. Under the direct access decision, beginning January 1, 1998, all electric customers may choose their electricity provider. Customers may choose to purchase their electricity (1) from the PX through PG&E, (2) from retail electricity providers (for example, marketers, brokers, and aggregators ) or (3) directly from power generators. Regardless of the customer's choice, PG&E will continue to provide electricity transmission and distribution services to all customers within its service territory. During the transition period, all customers will be billed for electricity used, for transmission and distribution services, and for recovery of competition transition costs (CTCs). (The method of billing the customers for these services is discussed below.) As a result, during the transition period, the overall electric rates of direct access customers would vary from customers who choose PG&E bundled services primarily to the extent that their direct access electricity price differs from the PX price. Because the CTC is nonbypassable (all customers will pay the CTC regardless of whether they select direct access or not), PG&E does not believe that direct access will have a material impact on the Corporation's ability to recover transition costs. The revenue cycle services decision allows electricity providers to choose the method of billing their customers and to choose whether to provide their customers with metering services. As related to the billing of direct access customers, the customer's electricity provider can choose one of the following three billing options. (1) The electricity provider would bill the customer for the electricity provided and PG&E would separately bill the customer for transmission and distribution services, including CTC. (2) PG&E could provide the customer with one consolidated bill for transmission and distribution services, including CTC, and for the electricity supplied by the electricity provider. (3) The electricity provider could provide the customer with one consolidated bill for the electricity provided and for transmission and distribution services, including CTC, provided by PG&E. Further, beginning in 1998, electricity providers may choose to provide metering services to their large electricity customers (customers with electricity demand of 20 kilowatts or more). And, beginning in 1999, these providers may choose to provide metering services to all of their customers regardless of size. The revenue cycle decision requires PG&E to separately identify cost savings that would result when billing, metering, and related services within PG&E's service territory are provided by another entity. Once these cost savings, or credits, are approved by the CPUC, they would be reflected on the customer's bill to the extent the customer's energy supplier is providing billing and metering services. To the extent that these credits equate to PG&E's actual cost savings from reduced billing, metering, and related services, PG&E does not expect a material adverse impact on its financial positions or results of operations. Accounting for the Effects of Regulation: - ---------------------------------------- PG&E accounts for the financial effects of regulation in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows PG&E to record certain regulatory assets and liabilities which would be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," requires that regulatory assets be written off when they are no longer probable of recovery and that impairment losses be recorded for long-lived assets when related future cash flows are less than the carrying value of the assets. In applying the provisions of SFAS No. 71, PG&E has accumulated approximately $1.6 billion of regulatory assets attributable to electric 21
generation at March 31, 1997. The net investments in Diablo Canyon and the other generation assets, including allocations of common plant, were $4.3 billion and $2.7 billion, respectively, at March 31, 1997. The net present value of above-market QF power purchase obligations is estimated to be $5.3 billion at January 1, 1998, at an assumed market price of $0.025 per kWh beginning in 1997 and escalating at 3.2 percent per year. PG&E believes that the restructuring legislation establishes a definitive transition to market-based pricing for electric generation that includes cost-of-service based ratemaking. In addition, under this framework, PG&E's generation-related transition costs will be collected through a nonbypassable charge. Based on this structure, PG&E believes its electric generation business will continue to meet the requirements of SFAS No. 71 as it relates to the transition costs throughout the transition period. At the conclusion of the transition period, PG&E believes it will be at risk to recover its generation costs through market-based revenues. At that time, PG&E expects to discontinue the application of SFAS No. 71 for the electric generation portion of its business. Since PG&E anticipates it will have recovered all transition costs required to be recovered during the transition period, including generation-related regulatory assets and above-market investments in net plant, the Corporation does not expect a material adverse impact on its or PG&E's financial position or results of operations from discontinuing the application at that time. As a result of California's electric industry restructuring and related legislation, the staff of the Securities and Exchange Commission (SEC) began discussions with PG&E and other California utilities regarding the appropriateness of the continued application of SFAS No. 71 for the generation portion of the electric utilities' businesses as of January 1, 1997. PG&E participated in discussions with the SEC staff and provided them with information in support of PG&E's position that it currently meets and will continue to meet the requirements to apply SFAS No. 71 throughout the transition period. Because of the importance of this issue to the electric utility industry in the United States, the SEC referred the issue to the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board. The EITF will provide the national forum needed to establish the uniform financial reporting and accounting standards necessary for determining if and when utilities should no longer be subject to SFAS No. 71 during a transition to market-based pricing within an industry restructuring. The SEC has notified PG&E that it will no longer pursue the issue with PG&E unless the EITF cannot reach a consensus prior to the end of the year. The EITF will first meet to discuss this issue on May 22, 1997, with a decision expected this year. Once a standard is established by the EITF, PG&E will reevaluate the financial impact of electric industry restructuring in light of the new standard. If PG&E cannot meet the new standard established by the EITF and retain the accounting guidance provided by SFAS No. 71, PG&E would have a material write-off of its generation-related regulatory assets. In accordance with PG&E's cost recovery plan, approved by the CPUC in 1996, generation-related regulatory assets would continue to be recovered as part of the transition charge during the transition period. Given the current regulatory environment, PG&E's electric transmission business and most areas of the distribution business are expected to remain regulated and, as a result, PG&E will continue to apply the provisions of SFAS No. 71. However, the CPUC's revenue cycle decision discussed above allows electricity providers to provide their customers with billing and metering services and indicate that electricity providers may be allowed to provide other distribution services (such as customer inquiries and uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these portions of PG&E's electric distribution business is not expected to have a material adverse impact on PG&E's or the Corporation's financial position or results of operations. 22
GAS INDUSTRY RESTRUCTURING: Restructuring of the natural gas industry at both the national and the state levels has given customers greater options in meeting their gas supply needs. PG&E's customers may buy commodity gas directly from competing suppliers, while buying only in-state transmission and distribution services (sold together at a combined rate) from PG&E. PGT, as an interstate pipeline, has provided nondiscriminatory transmission-only service since 1993 and no longer sells commodity gas. Most of PG&E's industrial and larger commercial (noncore) customers purchase their commodity gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers continue to buy commodity gas as well as transmission and distribution from PG&E as a bundled service. Since 1995, PG&E has actively pursued changes in the California gas industry in an effort to promote competition and increase options for all customers, as well as to position itself for the competitive marketplace. In 1996, PG&E submitted to the CPUC the Accord. The Accord is the result of an extensive negotiation process, begun in 1995, among a broad coalition of customer groups and industry participants. The Accord consists of three broad initiatives: (1) The Accord would separate, or "unbundle," PG&E's gas transmission and storage services from its distribution services and would change the terms of service and rate structure for gas transportation. Unbundling would give customers the opportunity to select from a menu of services offered by PG&E and would enable them to pay only for the services they use. PG&E would be at risk for variations in revenues resulting from differences between actual and forecasted transmission throughput. PG&E would also continue to provide cost-of-service based distribution service, much as it does today. (2) The Accord would increase opportunities for PG&E's core customers to purchase gas from competing suppliers and, therefore, could reduce PG&E's role in procuring gas for such customers. However, PG&E would continue to procure gas as a regulated utility supplier for those core customers who request it. The Accord also would establish principles for continuing negotiations between PG&E and California gas producers for the mutual release of supply contracts and the sale of gas gathering facilities. Also related to PG&E's procurement activities, PG&E has proposed that traditional reasonableness reviews of costs incurred to procure gas for core customers be replaced with a core procurement incentive mechanism (CPIM) for the period June 1, 1994, through 2002. Under the CPIM, PG&E would be able to recover its gas commodity and interstate transportation costs and would receive benefits or be penalized depending on whether its actual core procurement costs were within, below, or above a "tolerance band" constructed around market benchmarks. The CPIM proposal also requests authorization to use derivative financial instruments to reduce the risk of gas price and foreign currency fluctuations. Gains, losses, and transaction costs associated with the use of derivative financial instruments would be included in the purchased gas account and the measurement against the benchmarks. (3) The Accord would resolve various regulatory issues including: . the CPUC-ordered disallowances in connection with PG&E's 1988 through 1992 gas reasonableness proceedings and potential disallowances in connection with PG&E's 1993 through 1995 gas reasonableness proceedings; . the recovery of certain capital costs associated with PG&E's recently constructed California segment of the PG&E/PGT pipeline that extends from the Canadian border to Kern River Station in Southern California (PG&E Pipeline Expansion); . the recovery of costs through 2002 related to PG&E's commitments to purchase capacity from Transwestern Pipeline Company; and 23
. the recovery, through an interstate transition cost surcharge (ITCS), of fixed demand charges paid to El Paso Natural Gas Company and PGT for firm capacity held by PG&E on those pipelines. (ITCS costs are the difference between demand charges PG&E pays to El Paso and PGT for the reservation of interstate pipeline capacity that PG&E no longer uses to serve noncore customers and the revenues PG&E obtains from brokering that capacity.) On March 24, 1997, an ALJ of the CPUC issued a PD rejecting the Accord. The major provisions of the Accord PD follow: (1) Under the Accord PD, the core procurement incentive mechanism (CPIM) is not adopted. Therefore, the recovery of the cost of gas, as well as demand charges for gas transportation contracts used to procure gas, would be decided in various ongoing or future proceedings. (Demand charges are incurred by PG&E under gas transportation contracts with various Canadian and interstate pipeline companies for reserving pipeline capacity.) Further, under the Accord, PG&E agreed to forgo recovery of $90 million of gas costs that the CPUC had disallowed in a 1988-90 reasonableness decision, irrespective of the results of PG&E's pending litigation in federal court challenging that decision. If the Accord is rejected by the CPUC, PG&E would consider whether to continue to pursue that challenge. (2) The Accord PD confirms the CPUC's 1994 finding that PG&E's decision to construct the PG&E Pipeline Expansion was reasonable based on the knowledge PG&E management had at the time. However, the Accord PD would reverse the CPUC's original order which found that PG&E would not be responsible for stranded costs caused by the PG&E Pipeline Expansion. The Accord PD defines stranded costs caused by the PG&E Pipeline Expansion to include ITCS costs and costs of unused original system transmission facilities on PG&E's two other major intrastate pipelines. The Accord PD states that PG&E should absorb these stranded costs to maintain incremental ratemaking and to avoid imposing the costs and risks of the PG&E Pipeline Expansion on the customers of the original transmission system. If the Accord PD were adopted without change by the CPUC, PG&E would be required to offer three separate unbundled pipeline services on its major intrastate transmission pipelines (the PG&E Pipeline Expansion and two others) and would be at risk for recovery of the cost of all such service, with no balancing account protection. (3) The Accord PD would disallow recovery of 25 percent of ITCS costs for 1993 and 1994, with reasonableness reviews to determine the amount of ITCS costs that could be recovered in subsequent years. In the Accord PD, the ALJ indicates that he supports a similar 25 percent disallowance for subsequent periods. However, the Accord PD also would suspend PG&E's authority to record ITCS costs for future recovery subsequent to the date of the final CPUC decision. The Accord PD would suspend such authority until PG&E could demonstrate that the conflict of interest the ALJ perceives to exist between ratepayer and shareholder interests causes ratepayers no harm due to lost revenues from brokering PG&E's unused interstate pipeline capacity. Under the Accord, in contrast, PG&E would forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated for collection from its core and noncore customers, respectively. (4) The Accord PD would set for further hearing the pipeline expansion project reasonableness (PEPR) proceeding to determine the capital costs and revenue requirements of the PG&E Pipeline Expansion, rejecting the resolution of those issues which had been proposed in the Accord. In the Accord, PG&E had agreed to set rates for the PG&E Pipeline Expansion based on total capital costs of $736 million. However, in the PEPR proceeding, PG&E had sought $810 million in capital costs. The CPUC's Office of Ratepayer Advocates had recommended a $100 million disallowance and other parties had recommended a disallowance of $237 million. As of March 31, 1997, the Corporation has reserved approximately $529 million relating to various gas regulatory issues and capacity commitments, 24
the majority of which are addressed by the Accord. As a result, the Corporation believes the ultimate resolution of these matters, whether through approval of the Accord or otherwise, will not have a material impact on its or PG&E's financial position or future results of operations. ACQUISITIONS AND SALES: In January 1997, PG&E Corporation agreed to acquire Valero Energy Company (Valero), including its natural gas and natural gas liquids business but excluding its refining operations. Valero will be acquired for approximately $1.5 billion, consisting of approximately $720 million of PG&E Corporation common stock and the assumption of debt and liabilities. The acquisition of Valero, which is subject to the approval of Valero shareholders among other conditions, is expected to be completed in the third quarter of 1997. RESULTS OF OPERATIONS: The Corporation's results of operations were derived primarily from three business lines: utility (consisting of PG&E, including Diablo Canyon), Gas Holdings (consisting of PGT; PG&E Gas Transmission, Texas Corporation; and PG&E Energy Trading), and Enterprises (consisting of PG&E Enterprises' electric generation and energy services operations). The results of operations for the parent company, PG&E Corporation, alone are not material for separate disclosure as a business line and have been allocated among the three business lines based on their percentage of operating revenues. The results of operations and total assets for the three months ended March 31, 1997 and 1996, are reflected in the following table and discussed below: PG&E CORPORATION (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> GAS UTILITY HOLDINGS ENTERPRISES TOTAL -------- ------------ ----------- -------- <S> <C> <C> <C> <C> FOR THE THREE MONTHS ENDED MARCH 31, 1997 Operating revenues (1) $ 2,274 $1,049 $ 42 $ 3,365 Operating expenses 1,830 1,020 57 2,907 -------- ------- ------- -------- Operating income (loss) before income taxes 444 29 (15) 458 Net income 163 9 1 173 Earnings per common share .40 .02 .00 .42 Total assets at March 31 $23,456 $2,232 $ 949 $26,637 1996 Operating revenues $ 2,165 $ 53 $ 31 $ 2,249 Operating expenses 1,612 31 33 1,676 -------- ------- ------- -------- Operating income (loss) before income taxes 553 22 (2) 573 Net income 231 17 4 252 Earnings per common share .56 .04 .01 .61 Total assets at March 31 $24,455 $1,177 $1,032 $26,664 </TABLE> (1) Gas Holdings revenues equal gas transmission and marketing revenues reported on PG&E Corporation's Statement of Consolidated Income. Enterprises revenues equal other revenues reported on PG&E Corporation's Statement of Consolidated Income. Common Stock Dividend: - --------------------- PG&E Corporation's common stock dividend is based on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. PG&E Corporation's current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. 25
PG&E Corporation has identified a dividend payout ratio objective (dividends declared divided by earnings available for common stock) of between 50 and 65 percent (based on earnings exclusive of nonrecurring adjustments). PG&E's formation of a holding company was approved by the CPUC subject to a number of conditions, including the requirement that, on average, PG&E must maintain its CPUC-authorized capital structure. In the event that PG&E fails to maintain, on average, the CPUC-authorized capital structure, PG&E's ability to pay dividends to PG&E Corporation may be limited. However, PG&E shall request a waiver of this condition in the event that an adverse financial event reduces the utility's equity ratio by one percent or more. Earnings Per Common Share: - ------------------------- Earnings per common share for the three-month period ended March 31, 1997, decreased as compared with the same period in 1996 due primarily to a $144 million ($.21 per common share) increase in depreciation expense for Diablo Canyon assets. Utility: - ------- Utility operating revenues for the three-month period ended March 31, 1997, as compared with the same period in 1996 increased primarily due to an increase in energy cost revenues to recover energy cost increases in both natural gas prices and purchased electricity prices and volumes. Under energy cost recovery mechanisms, energy cost revenues generally equal energy cost expense, and thus, do not affect operating income. Utility operating expenses increased due to a $144 million increase in depreciation expense for Diablo Canyon. Gas Holdings: - ------------ Gas Holdings operating revenues for the three-month period ended March 31, 1997, as compared with the same period in 1996 increased $978 million primarily due to the operations of PG&E Energy Trading (formerly known as Energy Source). PG&E Energy Trading was acquired in December 1996 and has averaged $300 million in revenues each month since its acquisition. These revenues were offset by a corresponding increase in the cost of gas. LIQUIDITY AND CAPITAL RESOURCES: Sources of Capital: - ------------------ The Corporation's capital requirements are funded from cash provided by operations and, to the extent necessary, external financing. The Corporation's policy is to finance its assets with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to PG&E, complies with regulatory guidelines. Based on cash provided from operations and its capital requirements, the Corporation may repurchase equity and long-term debt in order to manage the overall balance of its capital structure. During the three-month period ended March 31, 1997, PG&E Corporation issued $331 million of common stock. Of this common stock, $319 million was issued in connection with the acquisition of Teco Pipeline Company and its subsidiaries (now known as PG&E Gas Transmission, Texas Corporation). The remaining $14 million was issued through the Dividend Reinvestment Plan and Stock Option Plan. Also during the three-month period ended March 31, 1997, PG&E Corporation repurchased $320 million of its common stock on the open market. In the first quarter of 1997, long-term debt matured, redeemed, or repurchased amounted to $257 million, of which $58 million related to PG&E's 26
redemption of its 12% Eurobond debentures and $167 million related to PG&E's repurchase of its mortgage bonds. PG&E intends to refinance $45 million of fixed-rate pollution control bonds in the second quarter of 1997. As discussed above in "Electric Industry Restructuring", to achieve the 10 percent rate reduction for residential and small commercial customers, the electric industry restructuring legislation authorizes utilities to finance a portion of the transition costs with "rate reduction bonds." In May 1997, PG&E filed an application with the CPUC for the issuance of an estimated $3.1 billion of these bonds by means of a special purpose entity. A CPUC decision is expected in September 1997, and if the decision is approved, PG&E expects these bonds would be issued in the fourth quarter of 1997. The special purpose entity will acquire from PG&E the right to be paid the revenues from a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The bonds will be nonrecourse to any other assets of the Corporation. Cost of Capital Application: - --------------------------- In May 1997, PG&E filed an application with the CPUC requesting the following cost of capital for 1998: Capital Weighted Ratio Cost/Return Cost/Return ------- ----------- ----------- Long-term debt 46.20% 7.37% 3.40% Preferred stock 5.80 6.65 0.39 Common equity 48.00 12.25 5.88 ----------- Total return on average utility base 9.67% =========== The proposed cost of common equity is 0.65 percentage points higher than the 11.6 percent adopted for 1997. This increase reflects the level of business and regulatory risks PG&E now faces. If adopted, the proposed cost of capital would increase PG&E's 1998 gas revenue requirement by $13 million. Consistent with the electric rate freeze, PG&E's proposed cost of capital would not change electric rates. Environmental Matters: - --------------------- The Corporation assesses, on an ongoing basis, compliance with laws and regulations related to hazardous substance remediation. At March 31, 1997, the Corporation had an accrued liability of $171 million for remediation costs at sites where such costs are probable and quantifiable. The costs at identified sites may be as much as $400 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or identifiable possible outcomes change. PG&E will seek recovery of prudently incurred compliance costs through ratemaking procedures approved by the CPUC. PG&E had recorded a regulatory asset at March 31, 1997, of $142 million for recovery of these costs in future rates. Additionally, the Corporation will seek recovery of costs from insurance carriers and from other third parties. (See Note 5 of Notes to Consolidated Financial Statements.) Effective January 1, 1997, the Corporation adopted the provisions of the American Institute of Certified Public Accountants' Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." The adoption of SOP 96-1 did not have a material adverse impact on the Corporation's financial position or results of operations. 27
Legal Matters: - ------------- In the normal course of business, both PG&E and the Corporation are named as parties in a number of claims and lawsuits. Substantially all of these have been litigated or settled with no material adverse impact on PG&E's or the Corporation's results of operations or financial position. In addition, both PG&E and the Corporation believe that the litigation or settlement of pending claims and lawsuits will not have a material adverse impact on their results of operations or financial position. See Note 5 to the Consolidated Financial Statements for further discussion of significant pending legal matters. 28
PART II. OTHER INFORMATION --------------------------- Item 1. Legal Proceedings ----------------- A. Compressor Station Chromium Litigation As previously disclosed in PG&E Corporation's and PG&E's Form 10-K for the fiscal year ended December 31, 1996, PG&E has been named as a defendant in several civil actions filed in southern California courts on behalf of more than 1,500 plaintiffs. Three additional civil actions have been filed in which PG&E has been named as a defendant. On November 27, 1996, a complaint was filed in Los Angeles Superior Court against PG&E and other defendants (Acosta v. Betz Laboratories, Inc.) on behalf of approximately 1,400 plaintiffs. PG&E was served with the complaint on April 1, 1997. As in the previously-filed complaints, plaintiffs are seeking unspecified compensatory and punitive damages for alleged personal injuries arising out of alleged exposure to chromium contamination in the vicinity of PG&E's gas compressor stations located in Hinkley, Kettleman and Topock, California. On February 14, 1997, a complaint was filed in San Francisco Superior Court against PG&E and other defendants (Riep v. PG&E). In this case, approximately 40 plaintiffs are seeking unspecified compensatory and punitive damages for alleged personal injuries arising out of alleged exposure to chromium contamination in the vicinity of PG&E's gas compressor station located in Hinkley, California. Also, on May 6, 1997, a complaint was filed in Los Angeles Superior Court against PG&E and other defendants (Petitt v. PG&E) on behalf of several plaintiffs. Plaintiffs are seeking unspecified compensatory and punitive damages for alleged personal injuries arising out of alleged exposure to chromium contamination in the vicinity of PG&E's gas compressor stations located in Hinkley, Kettleman and Topock, California. These cases, together with the cases listed under this item in Item 3 of PG&E Corporation's and PG&E's Form 10-K, are referred to collectively as the "Aguayo Litigation." The Corporation believes the ultimate outcome of the Aguayo Litigation will not have a material adverse impact on its financial position or results of operation. 29
Item 4. Submission of Matters to a Vote of Security Holders ---------------------------------------------------- PG&E Corporation: On April 16, 1997, PG&E Corporation held its annual meeting of shareholders. At that meeting, the following matters were voted as indicated: 1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors shall be elected and qualified: <TABLE> <CAPTION> For Withheld ----------- ---------- <S> <C> <C> Richard A. Clarke 299,085,133 12,428,978 Harry M. Conger 299,967,660 11,546,451 David A. Coulter 300,103,595 11,410,516 C. Lee Cox 300,426,072 11,088,039 William S. Davila 300,068,203 11,445,908 Robert D. Glynn, Jr. 300,281,567 11,232,544 David M. Lawrence, MD 299,775,438 11,738,673 Richard B. Madden 299,951,026 11,563,085 Mary S. Metz 299,878,110 11,636,001 Rebecca Q. Morgan 300,272,834 11,241,277 Samuel T. Reeves 300,257,575 11,256,536 Carl E. Reichardt 299,883,095 11,631,016 John C. Sawhill 300,097,997 11,416,114 Alan Seelenfreund 299,934,261 11,579,850 Stanley T. Skinner 299,511,391 12,002,720 Barry Lawson Williams 300,033,749 11,480,362 </TABLE> Simon Levine was duly nominated and received 65,007 votes. The vote for Mr. Levine did not constitute a plurality of votes cast and he was therefore not elected a director. 30
2. Ratification of the appointment of Arthur Andersen LLP as independent public accountants for the year 1997: For: 304,865,472 Against: 3,364,935 Abstain: 3,283,704 Broker non-votes(1): 0 3. Consideration of a shareholder proposal to appoint an independent Lead Director and Vice Chairman of the Board of Directors: For: 57,872,107 Against: 199,418,793 Abstain: 10,493,152 Broker non-votes:(1) 43,730,059 4. Consideration of a shareholder proposal to require a minimum of 90% attendance by directors at Board and committee meetings: For: 27,250,826 Against: 230,598,659 Abstain: 9,934,567 Broker non-votes:(1) 43,730,059 5. Consideration of a shareholder proposal to revoke the Restricted Stock Plan for Non-Employee Directors: For: 31,971,280 Against: 226,486,345 Abstain: 9,326,427 Broker non-votes:(1) 43,730,059 6. Consideration of a shareholder proposal to change the method of tabulating proxies: For: 31,563,299 Against: 214,834,996 Abstain: 21,385,757 Broker non-votes:(1) 43,730,059 - -------------------- (1) A non-vote occurs when a broker or other nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the broker or other nominee does not have discretionary voting power and has not received instructions from the beneficial owner. 31
7. Consideration of a shareholder proposal to provide that directors' compensation shall consist solely of common stock: For: 30,648,742 Against: 227,631,156 Abstain: 9,504,154 Broker non-votes:(1) 43,730,059 8. Consideration of a shareholder proposal taking exception to PG&E's action opposing Proposition 209: For: 24,833,836 Against: 226,949,420 Abstain 16,000,796 Broker non-votes:(1) 43,730,059 PG&E: On April 16, 1997, PG&E held its annual meeting of shareholders. Shares of capital stock of PG&E consist of shares of common stock, all of which are owned by PG&E Corporation, and shares of first preferred stock. At the annual meeting, the following matters were voted as indicated: 1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors shall be elected and qualified: <TABLE> <CAPTION> For (2) Withheld ------------ -------- <S> <C> <C> Richard A. Clarke 425,779,575 259,979 Harry M. Conger 425,783,946 255,608 David A. Coulter 425,781,433 258,121 C. Lee Cox 425,788,627 250,927 William S. Davila 425,784,262 255,292 Robert D. Glynn, Jr. 425,790,273 249,281 David M. Lawrence, MD 425,775,515 264,039 Richard B. Madden 425,782,861 256,693 Mary S. Metz 425,784,790 254,764 Rebecca Q. Morgan 425,784,247 255,307 Samuel T. Reeves 425,788,758 250,796 </TABLE> - -------------------- (2) All 409,120,387 shares of common stock, which are owned by PG&E Corporation, were voted for the nominees. The balance consists of the votes of shares of first preferred stock. 32
<TABLE> <S> <C> <C> Carl E. Reichardt 425,781,791 257,763 John C. Sawhill 425,779,329 260,225 Alan Seelenfreund 425,780,480 259,074 Stanley T. Skinner 425,784,681 254,873 Barry Lawson Williams 425,782,267 257,287 </TABLE> 2. Ratification of the appointment of Arthur Andersen LLP as independent public accountants for the year 1997: For: 425,687,188 (3) Against: 171,101 Abstain: 181,265 Broker non-votes(1): 0 Item 5. Other Information ----------------- A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends PG&E's earnings to fixed charges ratio for the three months ended March 31, 1997 was 3.01. PG&E's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 1997 was 2.79. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707 and 33-61959, relating to PG&E's various classes of debt and first preferred stock outstanding. - -------------------- (3) Includes all 409,120,387 shares of common stock. 33
Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: Exhibit 3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 28, 1997 Exhibit 11 Computation of Earnings Per Common Share Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends Exhibit 27.1 Financial Data Schedule for the quarter ended March 31, 1997 for PG&E Corporation Exhibit 27.2 Financial Data Schedule for the quarter ended March 31, 1997 for PG&E (b) Reports on Form 8-K during the first quarter of 1997 and through the date hereof (4): 1. January 2, 1997 Item 5. Other Events A. Holding Company Formation 2. January 7, 1997 Item 5. Other Events A. Electric Industry Restructuring B. 1997 ECAC 3. January 16, 1997 Item 5. Other Events A. Performance Incentive Plan - Year-to-Date Financial Results B. 1996 Consolidated Earnings (unaudited) - -------------------- (4) Unless otherwise noted, all Reports on Form 8-K were filed under both Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348 (PG&E) 34
4. January 31, 1997 Item 5. Other Events A. Acquisition of Valero Energy Corporation B. Acquisition of TECO Pipeline Company C. Electric Industry Restructuring Cost Recovery Plan 5. February 19, 1997 Item 7. Financial Statements, Pro Forma Financial Information and Exhibits A. 1996 Financial Statements 6. March 3, 1997 Item 5. Other Events A. Proposed Decision on Diablo Canyon Ratemaking Proposal 7. April 18, 1997 Item 5. Other Events A. Performance Incentive Plan -- Year-to-Date Financial Results B. Application of SFAS 71 C. Gas Accord D. Common Stock Repurchase Program E. Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends Item 7. Financial Statements, Pro Forma Financial Information and Exhibits (c) Exhibits 12.1 Computation of Ratio of Earnings to Fixed Charges (12/31/96) 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends (12/31/96) 8. May 9, 1997 Item 5. Other Events A. Electric Industry Restructuring 35
SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. PG&E CORPORATION and PACIFIC GAS AND ELECTRIC COMPANY May 15, 1997 By CHRISTOPHER P. JOHNS ------------------------------ CHRISTOPHER P. JOHNS Controller (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company) 36