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, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ---------- ---------- Exact Name of Commission Registrant State or other IRS Employer File as specified Jurisdiction of Identification Number in its charter Incorporation Number - ----------- -------------- --------------- -------------- 1-12609 PG&E Corporation California 94-3234914 1-2348 Pacific Gas and California 94-0742640 Electric Company Pacific Gas and Electric Company PG&E Corporation 77 Beale Street One Market, Spear Tower P.O. Box 770000 Suite 2400 San Francisco, California 94177 San Francisco, California 94105 - ---------------------------------------------------------------------- (Address of principal (Address of principal executive offices) (Zip Code) executive offices) (Zip Code) Pacific Gas and Electric Company PG&E Corporation (415) 973-7000 (415) 267-7000 - ---------------------------------------------------------------------- Registrant's telephone number, including area code 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, 1998: PG&E Corporation 381,473,556 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, 1998 TABLE OF CONTENTS PAGE PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME........................1 CONDENSED BALANCE SHEET.................................2 STATEMENT OF CASH FLOWS ................................3 PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME........................4 CONDENSED BALANCE SHEET.................................5 STATEMENT OF CASH FLOWS.................................6 NOTE 1: GENERAL...........................................7 NOTE 2: THE ELECTRIC BUSINESS.............................9 NOTE 3: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES...........13 NOTE 4: COMMITMENTS AND CONTINGENCIES....................13 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION.............16 RESULTS OF OPERATIONS.....................................18 Common Stock Dividend..................................18 Earnings Per Common Share..............................19 Utility Results........................................19 Unregulated Business Results...........................19 FINANCIAL CONDITION.......................................20 COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........20 THE ELECTRIC BUSINESS.....................................20 Electric Transition Plan...............................21 Rate Freeze and Rate Reduction.........................21 Transition Cost Recovery...............................21 Generation Divestiture.................................23 Customer Impacts of Transition Plan....................24 Voter Initiative.......................................25 THE GAS BUSINESS..........................................25 ACQUISITIONS AND SALES....................................26 YEAR 2000 COMPLIANCE....................................26 LIQUIDITY AND CAPITAL RESOURCES Sources of Capital.....................................27 Utility Cost of Capital................................29 1999 General Rate Case.............................29 Environmental Matters..................................30 Legal Matters..........................................30 Risk Management Activities.............................30 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.........................................31 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS.........................................32 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......32 ITEM 5. OTHER INFORMATION.........................................36 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................36 SIGNATURE..........................................................38
PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS <TABLE> PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME (in millions, except per share amounts) <CAPTION> Three months ended March 31, 1998 1997 --------- --------- <S> <C> <C> Operating Revenues Utility $ 2,025 $ 2,274 Energy commodities and services 2,328 1,091 -------- -------- Total operating revenues 4,353 3,365 Operating Expenses Cost of energy for utility 666 725 Cost of energy commodities and services 2,153 1,017 Operating and maintenance, net 508 700 Depreciation and decommissioning 561 459 -------- -------- Total operating expenses 3,888 2,901 -------- -------- Operating Income 465 464 Interest expense, net 203 160 Other income and expense (18) (20) -------- -------- Income Before Income Taxes 280 324 Income taxes 141 151 -------- -------- Net Income $ 139 $ 173 ======== ======== Weighted Average Common Shares Outstanding 381 409 Earnings Per Common Share, Basic and Diluted $ .36 $ .42 Dividends Declared Per Common Share $ .30 $ .30 <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PG&E CORPORATION CONDENSED BALANCE SHEET (in millions) <CAPTION> Balance at March 31, December 31, 1998 1997 ------------ ------------ <S> <C> <C> ASSETS Current Assets Cash and cash equivalents $ 214 $ 237 Short-term investments 49 1,160 Accounts receivable Customers, net 1,428 1,514 Regulatory balancing accounts 782 658 Energy marketing 897 830 Inventories and prepayments 600 626 -------- -------- Total current assets 3,970 5,025 Property, Plant, and Equipment Utility 33,294 32,972 Gas transmission 3,454 3,484 Other 217 57 -------- -------- Total property, plant, and equipment (at original cost) 36,965 36,513 Accumulated depreciation and decommissioning (16,648) (16,041) -------- -------- Net property, plant, and equipment 20,317 20,472 Other Noncurrent Assets Regulatory assets 2,218 2,337 Nuclear decommissioning funds 1,074 1,024 Other 1,757 1,699 -------- -------- Total noncurrent assets 5,049 5,060 -------- -------- TOTAL ASSETS $ 29,336 $ 30,557 ======== ======== LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 135 $ 103 Current portion of long-term debt 579 659 Current portion of rate reduction bonds 106 125 Accounts payable Trade creditors 752 754 Other 469 466 Energy marketing 777 758 Accrued taxes 482 226 Other 684 893 -------- -------- Total current liabilities 3,984 3,984 Noncurrent Liabilities Long-term debt 7,531 7,659 Rate reduction bonds 2,776 2,776 Deferred income taxes 4,067 4,029 Deferred tax credits 328 339 Other 2,017 2,034 -------- -------- Total noncurrent liabilities 16,719 16,837 Preferred Stock of Subsidiary With Mandatory Redemption Provisions 194 137 Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 300 300 Stockholders' Equity Preferred stock of subsidiary without mandatory redemption provisions Nonredeemable 145 145 Redeemable 183 257 Common stock 5,819 6,366 Reinvested earnings 1,992 2,531 -------- -------- Total stockholders' equity 8,139 9,299 Commitments and Contingencies (Notes 2 and 4) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,336 $ 30,557 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PG&E CORPORATION STATEMENT OF CASH FLOWS (in millions) <CAPTION> For the three months ended March 31, 1998 1997 ---------- ---------- <S> <C> <C> Cash Flows From Operating Activities Net income $ 139 $ 173 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, decommissioning, and amortization 587 493 Deferred income taxes and tax credits-net (105) (44) Other deferred charges and noncurrent liabilities (304) 29 Net effect of changes in operating assets and liabilities: Accounts receivable 19 107 Regulatory balancing accounts receivable 296 (52) Inventories 78 27 Accounts payable 20 (34) Accrued taxes 257 220 Other working capital (147) 9 Other-net 12 41 --------- --------- Net cash provided by operating activities 852 969 --------- --------- Cash Flows From Investing Activities Capital expenditures (506) (328) Investments in unregulated projects (7) (31) Acquisitions - (41) Other-net (3) (16) --------- --------- Net cash used by investing activities (516) (416) --------- --------- Cash Flows From Financing Activities Net increase (decrease) in short-term borrowings 32 122 Long-term debt issued 158 - Long-term debt matured, redeemed, or repurchased-net (400) (257) Preferred stock redeemed or repurchased (7) - Common stock issued 17 14 Common stock repurchased (1,122) (320) Dividends paid (134) (131) Other-net (14) (4) --------- --------- Net cash used by financing activities (1,470) (576) --------- --------- Net Change in Cash and Cash Equivalents (1,134) (23) Cash and Cash Equivalents at January 1 1,397 144 --------- --------- Cash and Cash Equivalents at March 31 $ 263 $ 121 ========= ========= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 141 $ 67 Income taxes 1 26 <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME (in millions) <CAPTION> Three months ended March 31, 1998 1997 --------- --------- <S> <C> <C> Electric utility $ 1,562 $ 1,722 Gas utility 463 552 -------- -------- Total operating revenues 2,025 2,274 Operating Expenses Cost of electric energy 488 510 Cost of gas 178 215 Operating and maintenance, net 726 661 Depreciation and decommissioning 529 443 Provision for regulatory adjustment mechanisms (322) - -------- -------- Total operating expenses 1,599 1,829 -------- -------- Operating Income 426 445 Interest expense, net 131 136 Other income and expense (4) (1) -------- -------- Income Before Income Taxes 299 310 Income taxes 144 138 -------- -------- Net Income 155 172 Preferred dividend requirement and redemption premium 7 8 -------- -------- Income Available for Common Stock $ 148 $ 164 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEET (in millions) <CAPTION> Balance at March 31, December 31, 1998 1997 ------------ ------------ <S> <C> <C> ASSETS Current Assets Cash and cash equivalents $ 89 $ 80 Short-term investments 24 1,143 Accounts receivable Customers, net 1,066 1,204 Regulatory balancing accounts 782 658 Related parties accounts receivable 851 459 Inventories and prepayments 475 523 --------- --------- Total current assets 3,287 4,067 Property, Plant, and Equipment Electric 26,330 26,033 Gas 6,964 6,939 --------- --------- Total property, plant, and equipment (at original cost) 33,294 32,972 Accumulated depreciation and decommissioning (16,129) (15,558) --------- --------- Net property, plant, and equipment 17,165 17,414 Other Noncurrent Assets Regulatory assets 2,177 2,283 Nuclear decommissioning funds 1,074 1,024 Other 351 359 -------- -------- Total noncurrent assets 3,602 3,666 -------- -------- TOTAL ASSETS $ 24,054 $ 25,147 ======== ======== LIABILITIES AND EQUITY Current Liabilities Current portion of long-term debt $ 503 $ 580 Current portion of rate reduction bonds 106 125 Accounts payable Trade creditors 440 441 Related parties 125 134 Other 426 424 Accrued taxes 506 229 Deferred income taxes 32 149 Other 472 527 -------- ------- Total current liabilities 2,610 2,609 Noncurrent Liabilities Long-term debt 5,945 6,218 Rate reduction bonds 2,776 2,776 Deferred income taxes 3,333 3,304 Deferred tax credits 327 338 Other 1,791 1,810 -------- ------- Total noncurrent liabilities 14,172 14,446 Preferred Stock of Subsidiary With Mandatory Redemption Provisions 137 137 Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 300 300 Stockholders' Equity Preferred stock without mandatory redemption provisions Nonredeemable 145 145 Redeemable 183 257 Common stock 4,132 4,582 Reinvested earnings 2,375 2,671 -------- -------- Total stockholders' equity 6,835 7,655 Commitments and Contingencies (Notes 2 and 4) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 24,054 $ 25,147 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CASH FLOWS (in millions) <CAPTION> For the three months ended March 31, 1998 1997 ----------- ----------- <S> <C> <C> Cash Flows From Operating Activities Net income $ 155 $ 173 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, decommissioning, and amortization 557 476 Deferred income taxes and tax credits-net (114) (62) Other deferred charges and noncurrent liabilities 18 55 Provision for regulatory adjustment mechanisms (322) - Net effect of changes in operating assets and liabilities: Accounts receivable (255) 68 Regulatory balancing accounts receivable 296 (52) Inventories 42 28 Accounts payable 18 (145) Accrued taxes 272 218 Other working capital (61) (16) Other-net 7 7 --------- --------- Net cash provided by operating activities 613 750 --------- --------- Cash Flows From Investing Activities Capital expenditures (331) (321) Other-net (9) (98) --------- --------- Net cash used by investing activities (340) (419) --------- --------- Cash Flows From Financing Activities Net increase (decrease) in short-term borrowings - (74) Long-term debt matured, redeemed, or repurchased-net (389) (223) Preferred stock redeemed or repurchased (65) - Common stock repurchased (800) - Dividends paid (123) (131) Other-net (6) (6) --------- --------- Net cash used by financing activities (1,383) (434) --------- --------- Net Change in Cash and Cash Equivalents (1,110) (103) Cash and Cash Equivalents at January 1 1,223 144 --------- --------- Cash and Cash Equivalents at March 31 $ 113 $ 41 ========= ========= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 96 $ 65 Income taxes - 26 <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: GENERAL Basis of Presentation: - ---------------------- This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and Pacific Gas and Electric Company (the Utility), a regulated subsidiary of PG&E Corporation. The Notes to Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries, including the Utility (collectively, the Corporation). The Utility's consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. The Utility'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 the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1997 Annual Report on Form 10-K. PG&E Corporation believes that 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. All significant intercompany transactions have been eliminated from the consolidated financial statements. Certain amounts in the prior year's consolidated financial statements have been reclassified to conform to the 1998 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, and liabilities and the disclosure of contingencies. Actual results could differ from these estimates. Acquisitions and Sales: - ----------------------- In August 1997, the Corporation announced that its subsidiary, U.S. Generating Company (USGen), had agreed to buy a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for $1.59 billion, plus $85 million for early retirement and severance costs previously committed to by NEES. Including fuel and other inventories and transaction costs, financing requirements are expected to total approximately $1.75 billion, of which approximately $1.25 billion will be funded through debt borrowed by USGen. In addition, approximately $500 million of equity will be contributed. The assets to be acquired contain a balance of hydro, coal, oil, and natural gas generation facilities. The acquisition is expected to be completed in the second half of 1998. The acquisition is subject to regulatory approvals. In addition, as discussed below in Generation Divestiture, as part of electric industry restructuring, the Utility has informed the California Public Utilities Commission (CPUC) that it does not intend to retain any of its non-nuclear generation facilities.
Accounting for Risk Management Activities: - ------------------------------------------ The Corporation, through its subsidiaries, engages in price risk management activities for both non-hedging and hedging purposes. The Corporation conducts non-hedging activities principally through its unregulated subsidiary, PG&E Energy Trading. Derivative and other financial instruments associated with the Corporation's electric power, natural gas, and related non-hedging activities are accounted for using the mark-to-market method of accounting. Additionally, the Corporation may engage in hedging activities using futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. Hedge transactions are accounted for under the deferral method with gains and losses on these transactions initially deferred and classified as inventories and prepayments and other liabilities in the Consolidated Balance Sheet and then recognized in cost of energy commodities and services when the hedged transaction occurs. The Utility manages price risk independently from the activities in the Corporation's unregulated businesses. In the first quarter of 1998, the CPUC granted approval for the Utility to use financial instruments to manage price volatility of gas purchased for the Utility's electric generation portfolio. The approval limits the Utility's outstanding financial instruments to $200 million, with downward adjustments occurring as fossil- fueled generation plants are divested. (See Generation Divestiture, below.) Authority to use these risk management instruments ceases upon the full divestiture of fossil-fueled generation plants or at the end of the current electric rate freeze (see Rate Freeze and Rate Reduction, below), whichever comes first. As stated above, the Corporation utilizes the mark-to-market method of accounting for its non-hedging commodity trading and price risk management activities. In accordance with the mark-to-market method of accounting, the Corporation's electric power, natural gas and related non-hedging contracts, including both physical and financial instruments, are recorded at market value, net of future servicing costs and reserves, and recognized in the income statement as revenue or expense in the period of contract execution. The market prices used to value these transactions reflect management's best estimates considering various factors including market quotes, time value, and volatility factors of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions. Changes in the market value (determined by reference to recent transactions) of these contract portfolios, resulting primarily from newly originated transactions and the impact of commodity price and interest rate movements, are recognized in operating revenue in the period of change. The resultant unrealized gains and losses and related reserves are recorded as inventories and prepayments and other liabilities. The Corporation's net gains and losses associated with price risk management activities for the quarter ended March 31, 1998, were not material.
NOTE 2: The Electric Business On March 31, 1998, California became one of the first states in the country to allow open competition in the electric generation business. In developing state legislation to implement a competitive market, it was recognized that the Utility's market-based revenues would not be sufficient to recover (that is, to collect from customers) all generation costs resulting from past CPUC decisions. To recover these uneconomic costs, called transition costs, and to ensure a smooth transition to the competitive environment, the Utility, in conjunction with other California electric utilities, the CPUC, state legislators, consumer advocates, and others, developed a transition plan, in the form of state legislation, to position California for the new market environment. There are three principal elements to this transition plan: (1) an electric rate freeze and rate reduction, (2) recovery of transition costs, and (3) economic divestiture of Utility-owned generation facilities. Each one of these three elements, and the impact of the transition plan on the Utility's customers are discussed below. The transition plan will remain in effect until the earlier of March 31, 2002, or when the Utility has recovered its authorized transition costs as determined by the CPUC. This period is referred to as the transition period. At the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. Rate Freeze and Rate Reduction: - ------------------------------- The first element of the transition plan is an electric rate freeze and an electric rate reduction. During 1997, electric rates for the Utility's customers were held at 1996 levels. Effective January 1, 1998, the Utility reduced electric rates for its residential and small commercial customers by 10 percent and will hold their rates at that level. All other electric customers' rates remained frozen at 1996 levels. The rate freeze will continue until the end of the transition period. During the first quarter of 1998, the electric rate reduction reduced operating revenue by approximately $94 million. To pay for the 10 percent rate reduction, the Utility financed $2.9 billion of its transition costs with rate reduction bonds. The bonds defer recovery of a portion of the transition costs until after the transition period. The transition costs associated with the rate reduction bonds are expected to be recovered over the term of the bonds. Transition Cost Recovery: - ------------------------ The second element of the transition plan is recovery of transition costs. Transition costs are costs which are unavoidable and which are not expected to be recovered through market-based revenues. These costs include: (1) the above-market cost of Utility-owned generation facilities, (2) costs associated with the Utility's 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. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) The costs of Utility-owned generation facilities are currently included in the Utility customers' rates. Above-market facility costs are those facilities whose values recorded on the Utility's balance sheet (book value) are expected to be in excess of their market values. Conversely, below- market facility costs are those whose market values are expected to be in excess of their book values. In general, the total amount of generation
facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below- market portion of these costs will reduce other unrecovered transition costs. A valuation of a Utility-owned generation facility where the market value exceeds the book value could result in a material charge if the valuation of the facility is determined based upon any method other than a sale of the facility to a third party. This is because any excess of market value over book value would be used to reduce other transition costs without being collected in rates. The Utility will not be able to determine the exact amount of generation facility costs that will be recoverable as transition costs until a market valuation process (appraisal, spin, or sale) is completed for each of the Utility's generation facilities. This market valuation process is expected to occur prior to the conclusion of the transition period. The first of these valuations occurred in 1997 when the Utility agreed to sell three Utility-owned electric generation plants for $501 million. The sale is scheduled to close during 1998. (See Generation Divestiture, below.) At March 31, 1998, the Utility's net investment in Diablo Canyon Nuclear Power Plant (Diablo Canyon) and non-nuclear generation facilities was $3.5 billion and $2.6 billion, respectively, including the plants to be sold in 1998. Costs associated with the Utility's long-term contracts to purchase power at above-market prices from QFs and other power suppliers are also eligible to be recovered as transition costs. The Utility has agreed to purchase electric power from these suppliers under long-term contracts expiring on various dates through 2028. Over the life of these contracts, the Utility estimates that it will purchase approximately 360 million megawatt-hours at an aggregate average price of 6.3 cents per kilowatt-hour. To the extent that this price is above the market price, the Utility is authorized to collect the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. Generation-related regulatory assets, net of regulatory obligations, are also eligible for transition cost recovery. As of March 31, 1998, the Utility has accumulated approximately $1.8 billion of these assets net of obligations. Under the transition plan, most transition costs must be recovered by March 31, 2002. This recovery period is significantly shorter than the recovery period of the related assets prior to restructuring. Effective January 1, 1998, in accordance with the transition plan, the Utility is recording depreciation of certain generating plants determined to be uneconomic in proceedings before the CPUC and amortization of most generation related regulatory assets over the transition period. The CPUC believes that the shortened recovery period reduces risks associated with recovery of all the Utility's generation assets, including Diablo Canyon and hydroelectric facilities. Accordingly, the Utility is receiving a reduced return for all of its Utility-owned generation facilities. In 1998, the reduced return on common equity is 6.77 percent. Although most transition costs must be recovered by March 31, 2002, certain transition costs can be included in customers' electric rates after the transition period. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing QF and power- purchase contracts discussed above, and (3) unrecovered electric industry restructuring 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. Further, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the facility. During the rate freeze, this charge will not increase the Utility customers' electric rates.
Excluding these exceptions, the Utility will write-off any transition costs not recovered during the transition period. The CPUC has the ultimate authority to determine the recoverable amount of transition costs. Reviews by the CPUC to determine the reasonableness of transition costs are being conducted and will continue to be conducted throughout the transition period. In addition, the CPUC is conducting a financial verification audit of the Utility's Diablo Canyon accounts at December 31, 1996. Diablo Canyon accounts include sunk costs at December 31, 1996 of $3.3 billion which reflects total construction costs of $7.1 billion. (Sunk costs are costs associated with Utility-owned generating facilities that are fixed and unavoidable and currently included in the Utility customers' electric rates.) The CPUC will hold a proceeding to review the results of the audit, including any proposed adjustments to the recovery of Diablo Canyon costs in rates, following the completion of the audit. Transition costs that are disallowed by the CPUC for collection from Utility customers will be written off and may result in a material charge. At this time, the amount of disallowance of transition costs, if any, cannot be predicted. Effective January 1, 1998, the Utility is collecting eligible transition costs through a CPUC-authorized nonbypassable charge. The amount of revenue collected for transition costs recovery is subject to seasonal fluctuations in the Utility's sales volumes. The first quarter amortization and depreciation of transition costs exceeded revenue associated with transition costs recovery by $322 million. In accordance with CPUC rate treatment of transition costs, the Utility deferred this excess. The Utility's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the market value of the Utility-owned generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which the Utility's authorized revenues to recover distribution costs are increased or decreased, and (7) the market price of electricity. Given the Utility's current evaluation of these factors, the Utility believes that it will recover its transition costs. Also, the Utility believes that its regulatory assets and Utility-owned generation facilities are not impaired. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. Generation Divestiture: - ----------------------- The third element of the transition plan is the economic divestiture of Utility-owned generation facilities. To alleviate market power concerns of the CPUC, the Utility has agreed to sell its fossil-fueled generation facilities. In 1997, the Utility agreed to sell three electric Utility-owned fossil- fueled generating plants to Duke Energy Power Services Inc. (Duke) through a competitive auction process. The aggregate bid accepted for these plants was $501 million. These three fossil-fueled plants have a combined book value at March 31, 1998, of approximately $370 million and a combined capacity of 2,645 megawatts (MW). The three power plants are located at Morro Bay, Moss Landing, and Oakland. The sales have been approved by the CPUC. However, they are still subject to various regulatory approvals including the approval of the transfer of various permits and licenses, and the Federal Energy Regulatory Commission's acceptance for filing of Duke's requested regulatory treatment.
Additionally, the Utility will retain liability for required environmental remediation of any pre-closing soil or groundwater contamination at these plants. Although the Utility is retaining such environmental remediation liability, the Utility does not expect any material impact on its or PG&E Corporation's financial position or results of operations. The sale of these three plants is scheduled to close in 1998. The Utility began an auction of four of its remaining fossil-fueled plants and its geothermal facilities in April 1998. These additional plants have a combined generating capacity of 4,718 MW and a combined book value at March 31, 1998, of approximately $720 million. During the transition period, the proceeds from the sale of the Utility- owned fossil-fueled and geothermal plants will be used to offset other transition costs. As a result, the Utility does not believe the sales will have a material impact on its results of operations. The Corporation has also informed the CPUC that it does not intend to retain the Utility's remaining 2,672 MW of fossil-fueled and hydroelectric facilities as part of the Utility. These remaining facilities have a combined book value at March 31, 1998, of approximately $1.7 billion. The Utility expects to announce a plan for disposition of these facilities by the third quarter of 1998. As previously mentioned, any plan for disposition of assets other than through sale to a third party could result in a material charge to the extent that the market value, as determined by the CPUC, is in excess of book value. Voter Initiative: - ----------------- Various consumer groups filed a voter initiative with the California Attorney General which would (1) require the Utility to provide an additional 10 percent rate reduction to its residential and small commercial customers; (2) eliminate transition cost recovery for nuclear investments (other than reasonable decommissioning costs); (3) restrict transition cost recovery for non-nuclear investments (other than costs associated with QFs), unless the CPUC finds that the Utility would be deprived of the opportunity to earn a fair rate of return; and (4) prohibit the collection of any customer charges for rate reduction bonds, or alternatively, require the Utility to offset such charges with an equal credit to customers. If the sponsors of the initiative obtain sufficient signatures to qualify the initiative for the November 1998, statewide ballot, and if the initiative were voted into law, a material charge would result to the extent that regulated rates would no longer be adequate to recover transition costs. In this event, we expect that legal challenges by the Utility and others would ensue. NOTE 3: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has outstanding 12 million shares of 7.90 percent 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 the Utility 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 the Utility with a face value of approximately $309 million, an interest rate of 7.90 percent, and a maturity date of 2025.
NOTE 4: COMMITMENTS AND CONTINGENCIES Nuclear Insurance: - ------------------ The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under these policies, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $18 million (property damage) and $6 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility 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, the Utility 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 Utility may be required to pay for environmental remediation at sites where the Utility 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, power plant sites, and sites used by the Utility for the storage or disposal of potentially hazardous materials. Under CERCLA, the Utility may be responsible for remediation of hazardous substances, even if the Utility did not deposit those substances on the site. The Utility records a liability when site assessments indicate remediation is probable and a range of reasonably likely cleanup costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. The cost of the hazardous substance remediation ultimately to be undertaken by the Utility 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 Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility had an accrued liability at March 31, 1998, of $246 million for hazardous waste remediation costs at identified sites, including fossil-fueled power plants. Environmental remediation at identified sites may be as much as $420 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. This upper limit of the range of costs was estimated using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.
Of the $246 million liability, discussed above, the Utility has recovered $68 million and expects to recover $153 million in future rates. Additionally, the Utility is seeking recovery of its costs from insurance carriers and from other third parties as appropriate. Further, as discussed in Generation Divestiture above, the Utility will retain the pre-closing remediation liability associated with divested generation facilities. The Corporation believes the ultimate outcome of these matters will not have a material impact on its or the Utility's 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, 1998, the Utility's net investment was $688 million. This net investment is comprised of the pumped storage facility (including regulatory assets of $48 million), common plant, and dedicated transmission plant. As part of the 1996 General Rate Case decision in December 1995, the CPUC directed the Utility to perform a cost-effectiveness study of Helms. In July 1996, the Utility submitted its study, which concluded that the continued operation of Helms is cost effective. The Utility recommended that the CPUC take no action and address Helms along with other generating plants in the context of electric industry restructuring. Under electric industry restructuring, the uneconomic, above-market portion of Helms is eligible for recovery as a transition cost. Ongoing operating costs of the facility are at risk for recovery through the newly restructured electric generation market. Because the CPUC has not specifically addressed the cost-effectiveness study, the Utility is currently unable to predict whether there will be further changes in rate recovery. The Corporation believes that the ultimate outcome of this matter will not have a material impact on its or the Utility's financial position or results of operations. The Corporation has also informed the CPUC that it does not intend to retain Helms as part of the Utility. See Generation Divestiture above. Stock Repurchase Program: - ------------------------- In January 1998, the Corporation repurchased in a specific transaction 37 million shares of PG&E Corporation common stock at $30.3125 per share. In connection with this transaction, the Corporation has entered into a forward contract with an investment institution. The Corporation will retain the risk of increases and the benefit of decreases in the price of the common shares purchased through the forward contract. This obligation will not be terminated until the investment institution has replaced the shares sold to the Corporation through purchases on the open market or through privately negotiated transactions. The contract is anticipated to expire by December 31, 1998. This additional obligation may be settled in either shares of stock or cash and is not expected to have a material impact on the Corporation's financial position or results of operations.
Legal Matters: - -------------- Chromium Litigation: In 1994 through 1997, several civil suits were filed against the Utility on behalf of approximately 3,000 individuals. During the first quarter of 1998, claims on behalf of 240 of these individuals were dismissed, subject to possible appeal. The suits seek an unspecified amount of compensatory and punitive damages for alleged personal injuries and, in some cases, property damage, resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and Topock. The Utility is responding to the suits and asserting affirmative defenses. The Utility 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 impact on its or the Utility's financial position or results of operations. Texas Franchise Fee Litigation: In connection with PG&E Corporation's acquisition of Valero Energy Corporation in July 1997, now known as PG&E Gas Transmission, Texas Corporation (GTT), GTT succeeded to the litigation described below. GTT and various of its affiliates are defendants in at least two class action suits and six separate suits filed by various Texas cities. The class action suits involve plaintiffs that serve as class representatives for classes consisting of every municipality in Texas (excluding certain cities which filed separate suits) in which any of the defendants engaged in business activities related to natural gas or natural gas liquids or sold or supplied gas or used public rights-of-way. Generally, these cities allege, among other things, that (1) the defendants that own or operate pipelines have occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities, and (2) the defendants that are gas marketers have failed to pay the cities for accessing and utilizing the pipelines located in the cities to flow gas under city streets. Plaintiffs also allege various other claims against the defendants for failure to secure the cities' consent. Damages are not quantified. The Corporation believes that the ultimate outcome of these matters will not have a material impact on its financial position. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION San Francisco-based PG&E Corporation provides integrated energy services. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation and its various business lines: - -Pacific Gas and Electric Company (Utility) - -Unregulated Business Operations consisting of: - Gas Transmission: through PG&E Gas Transmission - Electric Generation: through U.S. Generating Company (USGen) - Energy Commodities and Services: through PG&E Energy Trading and PG&E Energy Services
Overview: - --------- This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and Pacific Gas and Electric Company. Therefore, our Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition (MD&A) apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries, including the Utility (collectively, the Corporation). Our Utility's consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. This MD&A should be read in conjunction with the consolidated financial statements included herein. Further, this quarterly report should be read in conjunction with the Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1997 Annual Report on Form 10-K. In this MD&A, we explain the results of operations for the three months ended March 31, 1998, as compared to the corresponding period in 1997 and discuss our financial condition. Our discussion of financial condition includes: - - changes in the energy industry and how we expect these changes to influence future results of operations, - - liquidity and capital resources, including discussions of capital financing activities, and uncertainties that could affect future results, and - - risk management activities. This Quarterly Report on Form 10-Q, including our discussion of results of operations and financial condition below, contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," and similar expressions 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 in California and nationally, the continued application of the regulatory framework established by the California Public Utilities Commission (CPUC) and state legislation, the outcome of the regulatory proceedings related to those restructurings, our Utility's ability to collect revenues sufficient to recover transition costs in accordance with its transition cost recovery plan, the planned sale of the electric Utility-owned fossil-fueled generating plants and the retention of the environmental remediation liability for these plants, as discussed in the Competition and the Changing Regulatory Environment section below. Risks and uncertainties also include the impact of our planned acquisition as discussed in the Acquisitions and Sales section below, the approval of our Utility's 1999 General Rate Case application resulting in the Utility's ability to earn its authorized rate of return as discussed in the Liquidity and Capital Resources section below, and our ability to successfully compete outside our traditional regulated markets. The ultimate impacts on future results of increased competition, the changing regulatory environment, our expansion into new businesses and markets, and the CPUC decision on the 1999 General Rate Case application are uncertain, but all are expected to fundamentally change how we conduct our 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 PG&E Corporation.
RESULTS OF OPERATIONS In this section, we provide the components of our earnings for the three months ended March 31, 1998 and 1997. We then explain why operating revenues and expenses for 1998 and 1997 were different between the years. The following table shows our results of operations for the three months ended March 31, 1998 and 1997, and total assets at March 31, 1998 and 1997. The results of operations for PG&E Corporation on a stand-alone basis and intercompany eliminations have been shown as Corporate and Other. <TABLE> (in millions) <CAPTION> Unregulated Corporate Business and Utility Operations Other Total -------- ------------ --------- ------- <S> <C> <C> <C> <C> For the three months ended March 31, 1998 Operating revenues $ 2,025 $ 2,341 $ (13) $ 4,353 Operating expenses 1,599 2,302 (13) 3,888 ------- ------- ------ ------- Operating income before income taxes 426 39 - 465 Income available for common stock 148 6 (15) 139 Total assets at March 31 $24,054 $ 6,555 $(1,273) $29,336 1997 Operating revenues $ 2,274 $ 1,104 $ (13) $ 3,365 Operating expenses 1,829 1,085 (13) 2,901 ------- ------- ------- ------- Operating income before income taxes 445 19 - 464 Income available for common stock 164 11 (2) 173 Total assets at March 31 $23,456 $ 3,357 $ (176) $26,637 </TABLE> Common Stock Dividend: - ---------------------- Our common stock dividend is based on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. Our current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. The CPUC set a number of conditions when PG&E Corporation was formed as a holding company. One of these conditions requires our Utility to maintain, on average, its CPUC-authorized capital structure, potentially limiting the amount of dividends our Utility may pay PG&E Corporation. At March 31, 1998, our Utility was in compliance with its CPUC-authorized capital structure. We believe that our Utility will continue to meet this condition in the future without affecting our ability to pay common stock dividends to common shareholders. Earnings Per Common Share: - -------------------------- Earnings per common share for the three months ended March 31, 1998, decreased $.06 as compared to the same period in 1997. Earnings per common share were affected by the activity discussed below.
Utility Results: - ---------------- Our Utility operating revenues for the three month period ended March 31, 1998, decreased $249 million as compared to the same period in 1997. Operating revenues declined because of the 10 percent electric rate reduction provided to residential and small commercial customers and due to changes in regulatory adjustment mechanisms resulting from electric industry restructuring. During the first quarter of 1998, the electric rate reduction decreased operating revenues by approximately $94 million. Electric rates for all our other customers have been held at 1996 levels. In connection with electric industry restructuring, our volumetric (ERAM) and energy cost (ECAC) revenue balancing accounts were terminated. Balancing account revenues related to ERAM and ECAC totaled approximately $166 million in the three month period ended March 31, 1997. The ERAM and ECAC balancing accounts have been replaced with regulatory adjustment mechanisms which impact expenses instead of revenues as discussed in Transition Cost Recovery, below. Utility operating expenses decreased $230 million for the three month period ended March 31, 1998, as compared to the same period in 1997. Operating expenses declined primarily as a result of lower gas prices and expense deferrals related to electric industry restructuring, which were partially offset by system reliability, storm response costs, and costs associated with a refueling and maintenance outage at Diablo Canyon Nuclear Power Plant (Diablo Canyon) from February 14, 1998 through March 28, 1998. As previously indicated, electric industry restructuring provides for recovery of certain costs in future periods. Some costs will be recovered as electric sales volumes increase during the summer months. Others relate to transition costs which will be recovered after the conclusion of the transition period. Utility operations contributed $16 million less to net income in the three month period ended March 31, 1998, than in the same period in 1997 primarily due to the lower authorized rate of return on equity of 6.77 percent applicable to all of our Utility-owned electric generation-related assets. Unregulated Business Results: - ----------------------------- Our unregulated business operations includes those business activities that are not directly regulated by the CPUC. Unregulated business operating revenues for the three month period ended March 31, 1998, increased $1.2 billion while operating expenses also increased $1.2 billion as compared to the same period in 1997, due to the acquisitions of Teco Pipeline Company in January 1997 and the natural gas operations of Valero Energy Corporation in July 1997, and due to operations associated with our energy commodities and services activities. Unregulated business operations contributed $5 million less in net income in the three month period ended March 31, 1998, than was contributed in the same period in 1997, primarily due to start up costs associated with the energy service business, which was partially offset by income generated from independent power projects managed by USGen. FINANCIAL CONDITION We begin this section by discussing the energy industry. We also discuss how we are responding to restructuring on a national level, including a planned acquisition. We then discuss liquidity and capital resources and our risk management activities.
COMPETITION AND CHANGING REGULATORY ENVIRONMENT: Energy Industry: The Electric Business: On March 31, 1998, California became one of the first states in the country to allow open competition in the electric generation business. Today, Californians can choose who provides their electric generation power. Customers within our Utility's service territory can purchase electricity (1) from our Utility, (2) from retail electricity providers (for example, marketers including our energy service subsidiary, brokers, and aggregators), or (3) directly from unregulated power generators. Our Utility will continue to provide distribution services to substantially all electric consumers within its service territory. To create this competitive generation market, California has established a Power Exchange (PX) and an Independent Systems Operator (ISO). The PX is an open electric marketplace where electricity prices are set. The ISO oversees California's electric transmission grid making sure that all generators have comparable access. California utilities, while retaining ownership of utility transmission facilities, have relinquished operating control to the ISO. Starting March 31, 1998, the ISO schedules the delivery or regulatory "must-take" resources such as Qualifying Facilities (QFs) and Diablo Canyon. After scheduling must-take resources, the ISO satisfies the remaining aggregate demand from the PX. To meet the demand, the PX accepts the lowest bids from competing electric providers and establishes a market price. Customers choosing to buy power directly from non-regulated generators or retailers will pay for that generation based upon negotiated contracts. CPUC regulation requires our Utility to purchase all electric power for its retail customers from the PX or from must-take resources. And, excluding must-take resources, we must sell all of our Utility-generated electric power to the PX. In future periods, the Cost of Energy for Utility, reflected on the Statement of Consolidated Income, will be comprised of the cost of PX purchases and the cost of Utility generation net of sales to the PX. Generation revenues currently make up approximately 30 percent of our total Utility revenues. After the transition period, discussed below, generation revenues will be determined principally by an open electric commodity market. Over the past several years, we have been taking steps to prepare for competition in the electric generation business. We have been working with the CPUC to ensure a smooth transition into the competitive market environment. And, we have made strategic investments throughout the nation that will further position us as a national energy provider. The following sections discuss the transition plan. Electric Transition Plan: - ------------------------- In developing state legislation to implement a competitive market, it was anticipated that our Utility's market-based revenues would not be sufficient to recover (that is, to collect from customers) all generation costs resulting from past CPUC decisions. To recover these uneconomic costs, called transition costs, and to ensure a smooth transition to the competitive environment, our Utility in conjunction with other California electric utilities, the CPUC, state legislators, consumer advocates, and others, developed a transition plan, in the form of state legislation, to position California for the new market environment.
There are three principal elements to this transition plan: (1) an electric rate freeze and rate reduction, (2) recovery of transition costs, and (3) economic divestiture of Utility-owned generation facilities. Each one of these three elements, and the impact of the transition plan on our Utility's customers are discussed below. The transition plan will remain in effect until the earlier of March 31, 2002, or when we have recovered our authorized transition costs as determined by the CPUC. This period is referred to as the transition period. At the conclusion of the transition period, we will be at risk to recover any of our Utility's remaining generation costs through market-based revenues. Rate Freeze and Rate Reduction: - ------------------------------- The first element of the transition plan is an electric rate freeze and an electric rate reduction. During 1997, electric rates for our Utility's customers were held at 1996 levels. Effective January 1, 1998, we reduced electric rates for our Utility's residential and small commercial customers by 10 percent and will hold their rates at that level. All other electric customers' rates remained frozen at 1996 levels. The rate freeze will continue until the end of the transition period. During the first quarter of 1998, the rate reduction reduced operating revenue by approximately $94 million. To pay for the 10 percent rate reduction, we financed $2.9 billion of our transition costs with rate reduction bonds. The bonds defer recovery of a portion of the transition costs until after the transition period. The transition costs associated with the rate reduction bonds are expected to be recovered over the term of the bonds. Transition Cost Recovery: - ------------------------- The second element of the transition plan is recovery of transition costs. Transition costs are costs which are unavoidable and which are not expected to be recovered through market-based revenues. These costs include: (1) the above-market cost of Utility-owned generation facilities, (2) costs associated with the Utility's long-term contracts to purchase power at above-market prices from QFs and other power suppliers, and (3) generation- related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) The costs of Utility-owned generation facilities are currently included in our Utility customers' rates. Above-market facility costs are those facilities whose values recorded on our balance sheet (book value) are expected to be in excess of their market values. Conversely, below-market facility costs are those whose market values are expected to be in excess of their book values. In general, the total amount of generation facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. A valuation of a Utility-owned generation facility where the market value exceeds the book value could result in a material charge if the valuation of the facility is determined based upon any method other than a sale of the facility to a third party. This is because any excess of market value over book value would be used to reduce other transition costs without being collected in rates. We will not be able to determine the exact amount of generation facility costs that will be recoverable as transition costs until a market valuation process (appraisal, spin, or sale) is completed for each of our Utility's
generation facilities. This market valuation process is expected to occur prior to the conclusion of the transition period. The first of these valuations occurred in 1997 when we agreed to sell three Utility-owned electric generation plants for $501 million. The sale is scheduled to close during 1998 (See Generation Divestiture, below). At March 31, 1998, our Utility's net investment in Diablo Canyon and Utility-owned non-nuclear generation facilities was $3.5 billion and $2.6 billion, respectively, including the plants to be sold in 1998. Costs associated with the Utility's long-term contracts to purchase power at above-market prices from QFs and other power suppliers are also eligible to be recovered as transition costs. Our Utility has agreed to purchase electric power from these suppliers under long-term contracts expiring on various dates through 2028. Over the life of these contracts, the Utility estimates that it will purchase approximately 360 million megawatt-hours at an aggregate average price of 6.3 cents per kilowatt-hour. To the extent that this price is above the market price, our Utility expects to collect the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. Generation-related regulatory assets, net of regulatory obligations, are also eligible for transition cost recovery. As of March 31, 1998, we have accumulated approximately $1.8 billion of these assets net of obligations. Under the transition plan, most transition costs must be recovered by March 31, 2002. This recovery period is significantly shorter than the recovery period of the related assets prior to restructuring. Effective January 1, 1998, in accordance with the transition plan, the Utility is recording depreciation of certain generating plants determined to be uneconomic in proceedings before the CPUC and amortization of most generation related regulatory assets over the transition period. The CPUC believes that the shortened recovery period reduces risks associated with recovery of all the Utility's generation assets, including Diablo Canyon and hydroelectric facilities. Accordingly, we are receiving a reduced return for all of our Utility-owned generation facilities. In 1998, the reduced return on common equity is 6.77 percent. Although most transition costs must be recovered by March 31, 2002, certain transition costs can be included in customers' electric rates after the transition period. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing QF and power- purchase contracts discussed above, and (3) unrecovered electric industry restructuring 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. Further, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the facility. During the rate freeze, this charge will not increase the Utility customers' electric rates. Excluding these exceptions, the Utility will write-off any transition costs not recovered during the transition period. The CPUC has the ultimate authority to determine the recoverable amount transition costs. Reviews by the CPUC to determine the reasonableness of transition costs are being conducted and will continue to be conducted throughout the transition period. In addition, the CPUC is conducting a financial verification audit of the Utility's Diablo Canyon accounts at December 31, 1996. Diablo Canyon accounts include sunk costs at December 31, 1996 of $3.3 billion which reflects total construction costs of $7.1 billion. (Sunk costs are costs associated with Utility-owned generating facilities that are fixed and unavoidable and currently included in the Utility customers' electric rates.) The CPUC will hold a proceeding to review the results of the audit, including any proposed adjustments to the recovery of Diablo Canyon costs in rates, following the completion of the
audit. Transition costs that are disallowed by the CPUC for collection from Utility customers will be written off and may result in a material charge. At this time, the amount of disallowance of transition costs, if any, cannot be predicted. Effective January 1, 1998, the Utility is collecting eligible transition costs through a CPUC-authorized nonbypassable charge. The amount of revenue collected for transition costs recovery is subject to seasonal fluctuations in the Utility's sales volumes. The first quarter amortization and depreciation of transition costs exceeded revenue associated with transition costs recovery by $322 million. In accordance with CPUC rate treatment of transition costs, the Utility deferred this excess. Our Utility's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the market value of our Utility-owned generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which our Utility's authorized revenues to recover distribution costs are increased or decreased, and (7) the market price of electricity. Given our current evaluation of these factors, we believe that we will recover our transition costs. Also, we believe that our regulatory assets and Utility-owned generation facilities are not impaired. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. Generation Divestiture: - ----------------------- The third element of the transition plan is the economic divestiture of Utility-owned generation facilities. To alleviate market power concerns of the CPUC, we have agreed to sell our fossil-fueled generation facilities. In 1997, we agreed to sell three electric Utility-owned fossil-fueled generating plants to Duke Energy Power Services, Inc. (Duke) through a competitive auction process. The aggregate bid accepted for these plants was $501 million. These three fossil-fueled plants have a combined book value at March 31, 1998, of approximately $370 million and a combined capacity of 2,645 megawatts (MW). The three power plants are located at Morro Bay, Moss Landing, and Oakland. The sales have been approved by the CPUC. However, they are still subject to various regulatory approvals, including the approval of the transfer of various permits and licenses, and Federal Energy Regulatory Commission's (FERC) acceptance for filing of Duke's requested regulatory treatment. Additionally, the Utility will retain liability for required environmental remediation of any pre-closing soil or groundwater contamination at these plants. Although we are retaining such environmental remediation liability, we do not expect any material impact on the Utility's or our financial position or results of operations. The sale of these three plants is scheduled to close in 1998. We began an auction of four of our remaining Utility-owned fossil-fueled plants and our Utility-owned geothermal facilities in April 1998. These additional plants have a combined generating capacity of 4,718 MW and a combined book value at March 31, 1998, of approximately $720 million. We have also informed the CPUC that we do not intend to retain our remaining 2,672 MW of Utility-owned fossil-fueled and hydroelectric facilities as part of the Utility. These remaining facilities have a combined book value at March 31, 1998, of approximately $1.7 billion. Our
Utility expects to announce a plan for the disposition of the facilities by the third quarter of 1998. As previously mentioned, any plan for disposition of assets other than through sale to a third party could result in a material charge to the extent that the market value, as determined by the CPUC, is in excess of book value. During the transition period, the proceeds from the sale of our Utility- owned fossil-fueled and geothermal plants will be used to offset other transition costs. As a result, we do not believe the sales will have a material impact on our results of operations. However, a material charge may occur if the fair values of generation facilities, which are disposed by the Utility but retained by the Corporation, are determined to be in excess of the facilities' book values. This is because the excess would be used to reduce other transition costs without being collected in rates. Customer Impacts of Transition Plan: - ------------------------------------ Effective March 31, 1998, all Californians may choose their electric commodity provider. As of March 31, 1998, our Utility had accepted approximately 30,000 requests to switch their electric commodity supplier from the Utility to another electric commodity provider. Regardless of the customer's choice of electric commodity provider, during the transition period, all customers will be billed for electricity used, for transmission and distribution services, for public purpose programs, and for recovery of transition costs. Customers who choose to purchase their electricity from non-Utility energy providers will see a change in their total bill only to the extent that their contracted electric commodity price differs from the PX price. Transition costs are being recovered from all Utility distribution customers through a nonbypassable charge regardless of their choice in commodity provider. We do not believe that the availability of choice to our customers will have a material impact on our ability to recover transition costs. In addition to supplying commodity electric power, commodity electric providers can choose the method of billing their customers and whether to provide their customers with metering services. We are tracking cost savings that result when billing, metering, and related services within our Utility's service territory are provided by another entity. Once these cost savings, or credits, are approved by the CPUC and the customer's energy provider is performing billing and metering services, we will reduce the customer's bill by the savings. The electric provider will then charge their customers for these services. To the extent that these credits equate to our actual cost savings from reduced billing, metering, and related services, we do not expect a material impact on the Utility's or our financial condition or results of operations. Voter Initiative: - ----------------- Various consumer groups filed a voter initiative with the California Attorney General which would (1) require the Utility to provide an additional 10 percent rate reduction to its residential and small commercial customers; (2) eliminate transition cost recovery for nuclear investments (other than reasonable decommissioning costs); (3) restrict transition cost recovery for non-nuclear investments (other than costs associated with QFs), unless the CPUC finds that the Utility would be deprived of the opportunity to earn a fair rate of return; and (4) prohibit the collection of any customer charges for rate reduction bonds, or alternatively, require the Utility to offset such charges with an equal credit to customers. If the sponsors of the initiative obtain sufficient signatures to qualify the initiative for the November 1998, statewide ballot, and if the initiative
were voted into law, a material charge would result to the extent that regulated rates would no longer be adequate to recover transition costs. In this event, we expect that legal challenges by the Utility and others would ensue. The Gas Business: In March 1998, our Utility implemented the Gas Accord Settlement (Accord). The Accord is an agreement with a broad coalition of customer groups and industry participants that has restructured our Utility's natural gas business. Upon implementation, our Utility's gas business experienced five key changes: 1. The Accord separated (or unbundled) our Utility's gas transmission and storage services from its distribution services. 2. The Accord increased the opportunity for our Utility's residential and small commercial (core)customers to purchase gas from competing suppliers. 3. The Accord established a new method, based on market indices, to measure the reasonableness of our Utility's gas purchases to serve its core customers. 4. The Accord established gas transmission and storage rates for the period from March 1998 through December 2002. 5. The Accord eliminated regulatory protection for transmission revenues from our Utility's industrial and large commercial (noncore) customers. As a result, we are subject to an increased risk for variations in revenues arising from fluctuations in noncore transmission throughput. These differences were previously deferred in balancing accounts. We do not however expect these variations to have a material impact on the Utility's or the Corporation's financial position or results of operations. In January 1998, the CPUC opened a rule-making proceeding to further expand market-oriented policies in California's gas industry. Policies under consideration include the additional unbundling of services, streamlining regulation for noncompetitive services, mitigating the potential for anti-competitive behavior, and establishing appropriate consumer protections. The CPUC is currently studying various new alternative market structures with the goal of encouraging competition and customer choice, while maintaining a high standard of consumer protection. At this point, we cannot predict the outcome of these proceedings and their impact on our financial position and results of operations. ACQUISITIONS AND SALES: In 1997, PG&E Corporation announced that it had agreed to acquire, through its subsidiary USGen, a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for $1.59 billion, plus $85 million for early retirement and severance costs previously committed to by NEES. Including fuel and other inventories and transaction costs, financing requirements are expected to total approximately $1.75 billion, of which approximately $1.25 billion will be funded through debt borrowed by USGen. In addition, approximately $500 million of equity will be contributed. The assets contain a balance of hydro, coal, oil, and natural gas generation facilities. The acquisition is subject to regulatory approvals. The acquisition is expected to be completed in the second half of 1998. In addition, as discussed above in Generation Divestiture, as part of electric industry restructuring, our Utility has informed the CPUC that it does not intend to retain any of its non-nuclear generation facilities.
YEAR 2000 COMPLIANCE In 1995, we began and presently continue to review and assess our computer and information systems in anticipation of Year 2000 issues. The Year 2000 issue exists because many software products use only two digits to identify a year in the date field and were developed without considering the impact of the upcoming change in the century. Some of these software products are critical to our operations and business processes and might fail or function incorrectly if not repaired or replaced with Year 2000 compliant products. In addition, many electronic monitoring and control systems have two-digit date coding embedded within their circuitry and may also be susceptible to failure or incorrect operation unless corrected or replaced with Year 2000 compliant products. PG&E Corporation expects to complete critical software modifications by the end of 1998 and to complete validation of these systems in 1999. We are compiling an inventory of all systems with embedded electronic components and assessing the degree of Year 2000 compliance. During 1999, we also expect to have completed validation of all critical vendor-supplied embedded electronic systems or replacement of those systems found not to be Year 2000 compliant. Our various lines of business are also dependent upon external parties including customers, suppliers, business partners, government agencies, and financial institutions for the reliable delivery of our products and services. To the extent that any of these parties experience Year 2000 problems in their systems, our service reliability may be adversely affected. We plan to assess the degree to which each of these external parties has adequate plans to address Year 2000 problems in its systems. If judged necessary and if possible, we will develop contingency plans to reduce the risk of material impacts on our operations through external Year 2000 problems. We believe our plans of action are adequate to secure Year 2000 compliance of our critical systems and to reduce the risk of external impacts to our operations. Therefore, we do not currently anticipate any material impact on the Utility's or PG&E Corporation's financial position or results of operations as a result of the Year 2000 issue. Nevertheless, achieving Year 2000 compliance is subject to the risks and uncertainties described above. If our internal systems, or the internal systems of external parties, fail to achieve Year 2000 compliance, business or results of operations of the Utility or PG&E Corporation could be adversely affected. 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 the Utility, complies with regulatory guidelines. Based on cash provided from operations and the Corporation's 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 months ended March 31, 1998, PG&E Corporation issued $18 million of common stock, generally through the Dividend Reinvestment Plan and the Stock Option Plan. Also during the three months ended March 31, 1998, PG&E Corporation paid dividends of $126 million and declared
dividends of $114 million. The Utility paid dividends of $115 million and declared dividends of $100 million to PG&E Corporation during the three months ended March 31, 1998. The Utility began a program of buying back its stock from PG&E Corporation in the first quarter of 1998. As of December 31, 1997, the Board of Directors had authorized us to repurchase up to $1.7 billion of our common stock on the open market or in negotiated transactions. As part of this authorization, in January 1998, the Corporation repurchased in a specific transaction 37 million shares of common stock at $30.3125 per share. In connection with this transaction, the Corporation has entered into a forward contract with an investment institution. The Corporation will retain the risk of increases and the benefit of decreases in the price of the common shares purchased through the forward contract. This obligation will not be terminated until the investment institution has replaced the shares sold to the Corporation through purchases on the open market or through privately negotiated transactions. The contract is anticipated to expire by December 31, 1998. This additional obligation may be settled in either shares of stock or cash and is not expected to have a material impact on the Corporation's financial position or results of operations. The Corporation maintains a $500 million revolving credit facility, and in August 1997, we entered into an additional $500 million temporary credit facility. Both of these credit facilities are to be used for general corporate purposes. There were no borrowings under the credit facilities at March 31, 1998. At March 31, 1998, the Corporation, primarily through an unregulated business subsidiary, had $135 million of outstanding short-term bank borrowings related to separate short-term credit facilities. The borrowings are unrestricted as to use. The carrying amount of short-term borrowings approximates fair value. In April 1998, the Utility repurchased $800 million of its common stock from PG&E Corporation with proceeds from the rate reduction bonds issued in December 1997, to reduce equity. The Utility's long-term debt matured, redeemed, or repurchased during the three months ended March 31, 1998, amounted to $357 million. Of this amount, $249 million related to the Utility's redemption of its 8 percent mortgage bonds due October 1, 2025, and $94 million related to Utility's repurchase of its other mortgage bonds. The remaining $14 million related primarily to the scheduled maturity of long-term debt. In January 1998, the Utility redeemed its Series 7.44 percent preferred stock with a face value of $65 million. The Utility maintains a $1 billion revolving credit facility which expires in 2002. The facility may be extended annually for additional one- year periods upon mutual agreement between the Utility and the banks. There were no borrowings under this credit facility at March 31, 1998. The table below provides information on PG&E Corporation's debt obligations at March 31, 1998:
Expected Maturity Date 1998 1999 2000 2001 2002 Thereafter Total(1) - ---------------------- ---- ---- ---- ---- ---- ---------- ------- Long-term debt Fixed rate $566 $294 $460 $330 $515 $4,597 $6,762 Average interest rate 5.8% 6.3% 6.0% 7.8% 7.7% 7.2% 6.9% Variable rate - - - - - $1,348 $1,348 Rate reduction bonds $106 $265 $280 $300 $290 $1,641 $2,882 Average interest rate 5.9% 6.0% 6.2% 6.2% 6.3% 6.4% 6.3% (1) The fair value of the long-term debt and rate reduction bonds is the same as the book value. Utility Cost of Capital: - ------------------------ The CPUC authorized a return on rate base for the Utility's gas and electric distribution assets for 1998 of 9.17 percent. The authorized 1998 cost of common equity is 11.20 percent which is lower than the 11.60 percent authorized for 1997. On May 8, 1998, the Utility filed its Cost of Capital Application with the CPUC. The filing requests a return on common equity of 12.1 percent and an overall return on rate base of 9.53 percent for its gas and electric distribution operations. The Utility did not request a change in its currently authorized capital structure of 46.2 percent debt, 5.8 percent preferred equity and 48 percent common equity. A final CPUC decision is expected in December 1998, to be effective January 1, 1999. The Utility did not request a 1999 rate of return for its gas transmission, storage, or gas gathering operations because the CPUC has approved the Gas Accord which sets the rates and revenue requirements for these lines of business until 2002. Also, no request was included for electric transmission operations since under direct access the transmission network is regulated by the FERC. As discussed above, in Transition Cost Recovery, the CPUC separately reduced the authorized return on common equity on our Utility's hydroelectric and geothermal generation assets to 6.77 percent, or 90 percent of the Utility's 1997 adopted cost of debt. The Utility believes that this reduction is inappropriate and has sought a rehearing of this decision. The Utility will file a separate application if the rehearing request is granted. 1999 General Rate Case (GRC): - ----------------------------- In December 1997, we filed our 1999 GRC application with the CPUC. During the GRC process, the CPUC examines our Utility's non-fuel related costs to determine the amount we can charge customers. In our application, we requested an increase in our Utility's authorized revenues, effective January 1, 1999. The requested increase, as updated in April 1998, consists of an increase of $572 million in electric utility revenues and an increase of $460 million in gas utility revenues over authorized 1998 revenues. In April 1998, a CPUC commissioner issued a ruling which delays the projected date for a final CPUC decision in the GRC until January 1999, with a proposed decision scheduled to be issued in December 1998. This schedule delays the proceedings by approximately one month compared to previous expectations. The revised schedule reflects the desire by intervenor parties, including the CPUC's Office of Ratepayer Advocates, for more time to prepare analysis and testimony. To accommodate the delayed schedule, the ruling permits us to submit a plan for establishing interim rates, effective on January 1, 1999, to cover the period between that date and the date a final CPUC decision is issued. A decision on
interim rates is scheduled to be issued in November 1998. The 1999 GRC will not affect the authorized revenues for electric and gas transmission services or for gas storage services. The authorized revenues for each of these services are determined in other proceedings. Utility electric transmission revenues are authorized by the FERC. In March 1998, we filed an application with the FERC requesting 1998 Utility electric retail transmission revenues of $331 million. The requested revenue is consistent with Utility electric transmission revenues in CPUC- authorized 1997 electric rates. In the application, we requested to place the new rates in effect, subject to refund, on March 31, 1998, consistent with the ISO and PX operational date. The new rates will supersede the previously requested revenues of $305 million currently in effect, subject to refund. Also, revenues associated with gas transmission and storage services were authorized as part of the Gas Accord. See the Gas Business section, above, for a discussion of the Gas Accord. Environmental Matters: - --------------------- We are subject to laws and regulations established to both improve and maintain the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove or remedy the effect on the environment. At March 31, 1998, the Utility expects to spend $246 million for clean-up costs at identified sites over the next 30 years. If other responsible parties fail to pay or identified outcomes change, then these costs may be as much as $420 million. Of the $246 million, the Utility has recovered $68 million and expects to recover $153 million in future rates. Additionally, the Utility is seeking recovery of its costs from insurance carriers and from other third parties. Further, as discussed above, the Utility will retain the pre-closing remediation liability associated with divested generation facilities. (See Note 4 of Notes to Consolidated Financial Statements.) Legal Matters: - -------------- In the normal course of business, both the Utility 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 impact on the Utility's or the Corporation's results of operations or financial position. See Part II, Item 1, Legal Proceedings and Note 4 to the Consolidated Financial Statements for further discussion of significant pending legal matters. Risk Management Activities: - --------------------------- In the first quarter of 1998, the CPUC granted approval for the Utility to use financial instruments to manage price volatility of gas purchased for our Utility electric generation portfolio. The approval limits the Utility's outstanding financial instruments to $200 million, with downward adjustments occurring as fossil-fueled generation plants are divested (See Generation Divestiture, above). Authority to use these risk management instruments ceases upon the full divestiture of fossil-fueled generation plants or at the end of the current electric rate freeze (See Rate Freeze and Rate Reduction, above), whichever comes first.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information concerning PG&E Corporation's and Pacific Gas and Electric Company's market risk is included in the table providing information about debt obligations in the above section Sources of Capital, and also in the above section Risk Management Activities.
PART II. OTHER INFORMATION --------------------------- Item 1. Legal Proceedings ----------------- A. Compressor Station Chromium Litigation As previously disclosed in PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the fiscal year ended December 31, 1997, claims against Pacific Gas and Electric Company on behalf of approximately 2,800 plaintiffs were pending in eight civil actions filed in California courts (known collectively as the "Aguayo Litigation"). Two of these actions also name PG&E Corporation as a defendant; Little and Mustafa v Pacific Gas and Electric Company and PG&E Corporation, and Whipple, et al v. Pacific Gas and Electric Company and PG&E Corporation, both pending in San Bernardino Superior Court. Plaintiffs in both actions have agreed to dismiss PG&E Corporation as a defendant. Each of the complaints in the Aguayo Litigation, except Little and Mustafa v. Pacific Gas and Electric Company, alleges personal injuries and seeks compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of Pacific Gas and Electric Company's gas compressor stations located in Hinkley, Kettleman and Topock, California. The plaintiffs in the Aguayo Litigation include current and former Pacific Gas and Electric Company employees, residents in the vicinity of the compressor stations, and persons who visited the compressor stations, alleging exposure to chromium at or near the compressor stations. The plaintiffs also include spouses of these plaintiffs who claim loss of consortium or children of these plaintiffs who claim injury through the alleged exposure of their parents. On March 30, 1998, a Los Angeles Superior Court judge dismissed the claims of 240 plaintiffs in Aguayo v. Pacific Gas and Electric Company who were neither personally exposed to chromium nor yet conceived at the time of their parents' alleged exposure. The judge found that current California law precludes these types of preconception claims. It is expected that plaintiffs will appeal this ruling. The Corporation believes the ultimate outcome of the Aguayo Litigation will not have a material adverse impact on its or Pacific Gas and Electric Company's financial position or results of operation. Item 4. Submission of Matters to a Vote of Security Holders --------------------------------------------------- PG&E Corporation: On April 15, 1998, 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: For Withheld ---------- ---------- Richard A. Clarke 277,313,530 6,999,929 Harry M. Conger 278,179,795 6,133,664 David A. Coulter 275,721,980 8,591,479
Lee Cox 278,165,313 6,148,146 William S. Davila 278,194,826 6,118,633 Robert D. Glynn, Jr. 278,236,860 6,076,599 David M. Lawrence, MD 277,866,616 6,446,843 Richard B. Madden 278,145,725 6,167,734 Mary S. Metz 278,089,765 6,223,694 Rebecca Q. Morgan 275,597,117 8,716,342 Carl E. Reichardt 277,990,791 6,322,668 John C. Sawhill 278,166,923 6,146,536 Alan Seelenfreund 278,142,639 6,170,820 Barry Lawson Williams 278,077,940 6,235,519 2. Ratification of the appointment of Arthur Andersen LLP as independent public accountants for the year 1998: For: 279,482,833 Against: 2,005,818 Abstain: 2,824,808 The proposal was approved by a majority of the shares present and voting (including abstentions) which shares voting affirmatively also constituted a majority of the required quorum. Each of the shareholder proposals listed below was defeated as the number of shares voting affirmatively on each proposal constituted less than a majority of the shares voting and present (including abstentions) with respect to each proposal. 3. Consideration of a shareholder proposal to appoint independent directors to key Board committees: For: 72,457,935 Against: 158,238,439 Abstain: 9,002,693 Broker non-votes:(1) 44,614,392 4. Consideration of a shareholder proposal regarding super majority voting: For: 96,676,182 Against: 134,458,016 Abstain: 8,564,869 Broker non-votes:(1) 44,614,392 5. Consideration of a shareholder proposal regarding cumulative voting: For: 60,562,835 Against: 165,694,235 Abstain: 13,441,997 Broker non-votes:(1) 44,614,392 - -------------------- (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.
6. Consideration of a shareholder proposal regarding director compensation: For: 20,512,623 Against: 208,057,428 Abstain: 11,129,016 Broker non-votes:(1) 44,614,392 Pacific Gas and Electric Company: On April 15, 1998, Pacific Gas and Electric Company held its annual meeting of shareholders. Shares of capital stock of Pacific Gas and Electric Company consist of shares of common stock and shares of first preferred stock. PG&E Corporation, as owner of all of the 409,120,387 outstanding shares of common stock, holds approximately 95% of the combined voting power of the outstanding capital stock of Pacific Gas and Electric Company. PG&E Corporation voted all of its shares of common stock for the nominees named in the joint proxy statement, for the ratification of the appointment of Arthur Andersen LLP as independent public accountants for the year 1998, and for the management proposal to decrease the minimum number of directors. The balance of the votes shown below were cast by holders of 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: For Withheld ----------- ----------- Richard A. Clarke 423,365,574 269,854 Harry M. Conger 423,368,303 267,125 David A. Coulter 423,366,425 269,003 C. Lee Cox 423,370,269 265,159 William S. Davila 423,372,395 263,033 Robert D. Glynn, Jr. 423,374,990 260,438 David M. Lawrence, MD 423,366,246 269,182 Richard B. Madden 423,370,055 265,373 Mary S. Metz 423,361,953 273,475 Rebecca Q. Morgan 423,358,458 276,970 Carl E. Reichardt 423,362,050 273,378 John C. Sawhill 423,360,841 274,587 Alan Seelenfreund 423,365,942 269,486 Gordon R. Smith 423,374,019 261,409 Barry Lawson Williams 423,362,357 273,071 2. Ratification of the appointment of Arthur Andersen LLP as independent public accountants for the year 1998: For: 423,229,793 Against: 138,185 Abstain: 267,450 - -------------------- (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.
3. Management proposal regarding decrease in the minimum number of directors (Item 7 in the joint proxy statement): For: 423,002,572 Against: 249,621 Abstain: 383,235 Item 5. Other Information ----------------- A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends Pacific Gas and Electric Company's earnings to fixed charges ratio for the three months ended March 31, 1998 was 2.66. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 1998 was 2.50. 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 Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: Exhibit 3.1 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 Exhibit 3.2 Bylaws of Pacific Gas and Electric Company, dated May 6, 1998 Exhibit 10.1 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 Exhibit 10.2 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 Exhibit 11 Computation of Earnings Per Common Share Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company Exhibit 27.1 Financial Data Schedule for the quarter ended March 31, 1998 for PG&E Corporation Exhibit 27.2 Financial Data Schedule for the quarter ended March 31, 1998 for Pacific Gas and Electric Company (b) Reports on Form 8-K during the first quarter of 1998 and through the date hereof (2): 1. January 22, 1998 (as amended by Form 8-K/A dated February 5, 1998) Item 5. Other Events A. Performance Incentive Plan - Year-to-date Financial Results B. 1997 Consolidated Earnings (unaudited) C. Accelerated Share Repurchase Program 2. April 16, 1998 Item 5. Other Events A. First Quarter 1998 Consolidated Earnings (unaudited) B. Pacific Gas and Electric Company's General Rate Case Proceeding - -------------------- (2) 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 (Pacific Gas and Electric Company)
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 CHRISTOPHER P. JOHNS May 15, 1998 By______________________________ CHRISTOPHER P. JOHNS Controller (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company)
Exhibit Index Exhibit No. Description of Exhibit 3.1 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 3.2 Bylaws of Pacific Gas and Electric Company, dated May 6, 1998 10.1 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 10.2 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 11 Computation of Earnings Per Common Share 12.1 Computation of Ratio of Earnings to Fixed Charges for Pacific Gas and Electric Company 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company 27.1 Financial Data Schedule for the quarter ended March 31, 1998 for PG&E Corporation 27.2 Financial Data Schedule for the quarter ended March 31, 1998 for Pacific Gas and Electric Company