-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, AffGBevki8YLhk++2zSJkAp1uEW8H10BllhpaAxtB1c45xEqTVsA2eIT8CY2q/FW MX8ImAWbDZVJVO4BfOZsbg== 0000075488-98-000022.txt : 19980817 0000075488-98-000022.hdr.sgml : 19980817 ACCESSION NUMBER: 0000075488-98-000022 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19980630 FILED AS OF DATE: 19980814 SROS: NYSE SROS: PCX FILER: COMPANY DATA: COMPANY CONFORMED NAME: PG&E CORP CENTRAL INDEX KEY: 0001004980 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 943234914 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-12609 FILM NUMBER: 98690913 BUSINESS ADDRESS: STREET 1: ONE MARKET SPEAR TOWER STREET 2: SUITE 2400 CITY: SAN FRANCISCO STATE: CA ZIP: 94105 BUSINESS PHONE: 4152677000 MAIL ADDRESS: STREET 1: ONE MARKET SPEAR TOWER STREET 2: SUITE 2400 CITY: SAN FRANCISCO STATE: CA ZIP: 94105 FORMER COMPANY: FORMER CONFORMED NAME: PG&E PARENT CO INC DATE OF NAME CHANGE: 19951214 10-Q 1 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 June 30, 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 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 August 6, 1998: PG&E Corporation 381,991,996 shares Pacific Gas and Electric Company Wholly owned by PG&E Corporation PACIFIC GAS AND ELECTRIC COMPANY FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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...........16 NOTE 4: COMMITMENTS AND CONTINGENCIES....................16 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION.............19 RESULTS OF OPERATIONS.....................................21 Common Stock Dividend..................................22 Earnings Per Common Share..............................22 Utility Results........................................22 Unregulated Business Results...........................23 FINANCIAL CONDITION.......................................23 COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........23 THE UTILITY ELECTRIC GENERATION BUSINESS..................23 Competitive Market Framework...........................23 Electric Transition Plan...............................24 Rate Freeze and Rate Reduction.........................25 Transition Cost Recovery...............................25 Utility Generation Divestiture.........................27 Utility Generation Impairment..........................28 Customer Impacts of Transition Plan....................28 California Voter Initiative............................29 THE UTILITY ELECTRIC TRANSMISSION BUSINESS................30 THE UTILITY ELECTRIC DISTRIBUTION BUSINESS................31 THE UTILITY GAS BUSINESS..................................31 UNREGULATED BUSINESS OPERATIONS...........................32 PG&E CORPORATION..........................................32 ACQUISITIONS AND SALES....................................32 YEAR 2000.................................................33 LIQUIDITY AND CAPITAL RESOURCES Sources of Capital.....................................34 Utility Cost of Capital................................35 1999 General Rate Case.................................36 Environmental Matters..................................36 Legal Matters..........................................37 Risk Management Activities.............................37 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.........................................37 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS.........................................38 ITEM 5. OTHER INFORMATION.........................................39 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................39 SIGNATURE..........................................................41 PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME (in millions, except per share amounts)
Three months ended June 30, Six months ended June 30, 1998 1997 1998 1997 -------- -------- -------- -------- Operating Revenues Utility $ 2,117 $ 2,279 $ 4,143 $ 4,553 Energy commodities and services 2,670 804 4,997 1,896 -------- -------- -------- -------- Total operating revenues 4,787 3,083 9,140 6,449 -------- -------- -------- -------- Operating Expenses Cost of energy for utility 569 659 1,235 1,383 Cost of energy commodities and services 2,468 735 4,620 1,753 Operating and maintenance, net 609 852 1,116 1,553 Depreciation and decommissioning 581 466 1,143 925 -------- -------- -------- -------- Total operating expenses 4,227 2,712 8,114 5,614 -------- -------- -------- -------- Operating Income 560 371 1,026 835 Interest expense, net 202 164 405 322 Other income and (expense) (5) 75 14 92 -------- -------- -------- -------- Income Before Income Taxes 353 282 635 605 Income taxes 179 89 322 240 -------- -------- -------- -------- Net Income $ 174 $ 193 $ 313 $ 365 ======== ======== ======== ======== Weighted Average Common Shares Outstanding 382 398 382 403 Earnings Per Common Share, Basic and Diluted $ .46 $ .49 $ .82 $ .91 Dividends Declared Per Common Share $ .30 $ .30 $ .60 $ .60 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION CONDENSED BALANCE SHEET (in millions)
Balance at June 30, December 31, 1998 1997 ------------ ----------- ASSETS Current Assets Cash and cash equivalents $ 311 $ 237 Short-term investments 39 1,160 Accounts receivable Customers, net 1,437 1,514 Regulatory balancing accounts 590 658 Energy marketing 807 830 Inventories and prepayments 638 626 -------- -------- Total current assets 3,822 5,025 Property, Plant, and Equipment Utility 24,736 24,185 Gas transmission 3,484 3,484 Other 263 57 -------- -------- Total property, plant, and equipment (at original cost) 28,483 27,726 Accumulated depreciation and decommissioning (12,196) (11,617) -------- -------- Net property, plant, and equipment 16,287 16,109 Other Noncurrent Assets Regulatory assets 6,335 6,700 Nuclear decommissioning funds 1,098 1,024 Other 1,747 1,699 -------- -------- Total noncurrent assets 9,180 9,423 -------- -------- TOTAL ASSETS $ 29,289 $ 30,557 ======== ======== LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 576 $ 103 Current portion of long-term debt 508 659 Current portion of rate reduction bonds 289 125 Accounts payable Trade creditors 622 754 Other 434 466 Energy marketing 734 758 Accrued taxes 390 226 Other 722 893 -------- -------- Total current liabilities 4,275 3,984 Noncurrent Liabilities Long-term debt 7,503 7,659 Rate reduction bonds 2,511 2,776 Deferred income taxes 4,028 4,029 Deferred tax credits 317 339 Other 1,958 1,978 -------- -------- Total noncurrent liabilities 16,317 16,781 Preferred Stock of Subsidiary With Mandatory Redemption Provisions 193 193 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 184 257 Common stock 5,834 6,366 Reinvested earnings 2,041 2,531 -------- -------- Total stockholders' equity 8,204 9,299 Commitments and Contingencies (Notes 2 and 4) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,289 $ 30,557 ======== ======== The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION STATEMENT OF CASH FLOWS (in millions)
For the six months ended June 30, 1998 1997 ---------- ---------- Cash Flows From Operating Activities Net income $ 313 $ 365 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, decommissioning, and amortization 1,199 985 Deferred income taxes and tax credits-net (31) (106) Other deferred charges and noncurrent liabilities (607) 8 Gain on sale of assets - (110) Loss on sale of assets 21 - Net effect of changes in operating assets and liabilities: Accounts receivable 100 92 Regulatory balancing accounts receivable 365 (41) Inventories 42 (3) Accounts payable (187) (128) Accrued taxes 165 115 Other working capital (135) (175) Other-net 5 141 --------- --------- Net cash provided by operating activities 1,250 1,143 --------- --------- Cash Flows From Investing Activities Capital expenditures (925) (770) Investments in unregulated projects (22) (97) Acquisitions - (41) Proceeds from sale of assets - 137 Other-net 36 (32) --------- --------- Net cash used by investing activities (911) (803) --------- --------- Cash Flows From Financing Activities Common stock issued 33 27 Common stock repurchased (1,123) (575) Long-term debt issued 199 50 Long-term debt matured, redeemed, or repurchased-net (644) (344) Short-term debt issued (redeemed)-net 473 848 Preferred stock redeemed or repurchased (63) (5) Dividends paid (255) (262) Other-net (6) (15) --------- --------- Net cash used by financing activities (1,386) (276) --------- --------- Net Change in Cash and Cash Equivalents (1,047) 64 Cash and Cash Equivalents at January 1 1,397 144 --------- --------- Cash and Cash Equivalents at June 30 $ 350 $ 208 --------- --------- Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 394 $ 315 Income taxes 209 237 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME (in millions)
Three months ended June 30, Six months ended June 30, 1998 1997 1998 1997 -------- -------- -------- -------- Electric utility $ 1,708 $ 1,877 $ 3,270 $ 3,599 Gas utility 409 402 873 954 -------- -------- -------- -------- Total operating revenues 2,117 2,279 4,143 4,553 -------- -------- -------- -------- Operating Expenses Cost of electric energy 465 597 953 1,107 Cost of gas 104 62 282 276 Operating and maintenance, net 688 802 1,414 1,463 Depreciation and decommissioning 544 448 1,074 891 Provision for regulatory adjustment mechanisms (181) - (503) - -------- -------- -------- -------- Total operating expenses 1,620 1,909 3,220 3,737 -------- -------- -------- -------- Operating Income 497 370 923 816 Interest expense, net 165 147 333 291 Other income and (expense) 30 14 71 23 -------- -------- -------- ------- Income Before Income Taxes 362 237 661 548 Income taxes 169 107 312 245 -------- -------- -------- ------- Net Income 193 130 349 303 Preferred dividend requirement and redemption premium 7 8 15 17 -------- -------- -------- ------- Income Available for Common Stock $ 186 $ 122 $ 334 $ 286 ======== ======== ======== ======= The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEET (in millions)
Balance at June 30, December 31, 1998 1997 ----------- ----------- ASSETS Current Assets Cash and cash equivalents $ 77 $ 80 Short-term investments 21 1,143 Accounts receivable Customers, net 1,124 1,204 Regulatory balancing accounts 590 658 Related parties accounts receivable 496 459 Inventories and prepayments 489 523 -------- -------- Total current assets 2,797 4,067 Property, Plant, and Equipment Electric 17,705 17,246 Gas 7,031 6,939 -------- -------- Total property, plant, and equipment (at original cost) 24,736 24,185 Accumulated depreciation and decommissioning (11,638) (11,134) -------- -------- Net property, plant, and equipment 13,098 13,051 Other Noncurrent Assets Regulatory assets 6,293 6,646 Nuclear decommissioning funds 1,098 1,024 Other 332 359 -------- -------- Total noncurrent assets 7,723 8,029 -------- -------- TOTAL ASSETS $ 23,618 $ 25,147 ======== ======== LIABILITIES AND EQUITY Current Liabilities Current portion of long-term debt $ 430 $ 580 Current portion of rate reduction bonds 289 125 Accounts payable Trade creditors 390 441 Related parties 47 134 Other 401 424 Accrued taxes 383 229 Deferred income taxes 36 149 Other 474 527 -------- -------- Total current liabilities 2,450 2,609 Noncurrent Liabilities Long-term debt 5,878 6,218 Rate reduction bonds 2,511 2,776 Deferred income taxes 3,260 3,304 Deferred tax credits 316 338 Other 1,742 1,810 -------- -------- Total noncurrent liabilities 13,707 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 184 257 Common stock 4,132 4,582 Reinvested earnings 2,563 2,671 -------- -------- Total stockholders' equity 7,024 7,655 Commitments and Contingencies (Notes 2 and 4) - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 23,618 $ 25,147 ======== ======== The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CASH FLOWS (in millions)
For the six months ended June 30, 1998 1997 -------- -------- Cash Flows From Operating Activities Net income $ 349 $ 303 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, decommissioning, and amortization 1,135 949 Deferred income taxes and tax credits-net (79) (111) Other deferred charges and noncurrent liabilities (211) 25 Provision for regulatory adjustment mechanisms (503) - Net effect of changes in operating assets and liabilities: Accounts receivable 43 - Regulatory balancing accounts receivable 365 (41) Inventories 19 - Accounts payable (45) (155) Accrued taxes 154 113 Other working capital (58) (168) Other-net 13 13 --------- --------- Net cash provided by operating activities 1,182 928 --------- --------- Cash Flows From Investing Activities Capital expenditures (671) (743) Other-net 83 (114) --------- --------- Net cash used by investing activities (588) (857) --------- --------- Cash Flows From Financing Activities Common stock repurchased (800) - Long-term debt issued - 44 Long-term debt matured, redeemed, or repurchased-net (618) (316) Short-term debt issued (redeemed)-net - 497 Preferred stock redeemed or repurchased (65) - Dividends paid (230) (362) Other-net (6) (8) --------- --------- Net cash used by financing activities (1,719) (145) Net Change in Cash and Cash Equivalents (1,125) (74) Cash and Cash Equivalents at January 1 1,223 144 --------- --------- Cash and Cash Equivalents at June 30 $ 98 $ 70 --------- --------- Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 315 $ 277 Income taxes 260 243 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: GENERAL Basis of Presentation: - ---------------------- This Quarterly Report 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 Form 10-K. PG&E Corporation believes that the accompanying statements reflect all adjustments 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 July 1998, the Corporation sold its Australian energy holdings to Duke Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation. The assets, located in the southeast corner of the Australian state of Queensland, include a 627-kilometer gas pipeline, pipeline operations, and trading and marketing operations. PG&E Corporation had previously announced that it was evaluating its Australian holdings in light of its intention to focus on its national energy strategy. The sale to DEI represents a premium on the price in local currency of PG&E Corporation's 1996 investment in the assets. However, the transaction resulted in a non-recurring charge of $.06 per share in the second quarter primarily due to the 22 percent currency devaluation of the Australian dollar against the U.S. dollar during the past two years. In 1997, the Corporation agreed to acquire, through its subsidiary U.S. Generating (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, the Corporation expects financing requirements to total approximately $1.805 billion, to be funded through $1.38 billion of USGen debt and a $425 million equity contribution. The assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 megawatts (MW) and 23 multi-year power purchase agreements representing an additional 1,100 MW of production capacity. The Corporation expects to complete the acquisition in the third quarter of 1998. The Corporation agreed to acquire these generating facilities and power supply contracts in anticipation of deregulation of the electric industry in several New England states. In Massachusetts, electric industry restructuring legislation took effect March 1, 1998. However, a referendum to repeal this legislation is on the November ballot. If the voters approve the referendum, then the restructuring legislation in Massachusetts may be repealed. As Massachusetts represents only a portion of the New England market, the Corporation does not expect that any repeal will have a material impact on its results of operations or financial position. In addition, as discussed below in Utility Generation Divestiture, as part of electric industry restructuring, the California Public Utilities Commission (CPUC) has been informed that the Utility does not intend to retain any of its remaining non-nuclear generation facilities as part of the Utility. 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. The Corporation accounts for hedge transactions under the deferral method. Initially, the Corporation defers gains and losses on these transactions and classifies them as inventories and prepayments and other liabilities in the Consolidated Balance Sheet. When the hedged transaction occurs, the Corporation recognizes the gain or loss in Cost of Energy Commodities and Services in the Statement of Consolidated Income. 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 the Utility divests of its fossil-fueled generation plants. (See Utility 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. In the second quarter of 1998, the CPUC granted conditional authority to the Utility to use natural gas-based financial instruments to manage the impact of natural gas prices on the cost of electricity purchased pursuant to existing power purchase contracts. Under the authority granted in the CPUC decision, no natural gas-based financial instruments shall have an expiration date later than December 31, 2001. Furthermore, if the rate freeze ends before December 31, 2001, the Utility shall net any outstanding financial instrument contracts through equal and opposite contracts, within a reasonable amount of time. Also during the second quarter, the Utility filed an application with the CPUC to use natural gas-based financial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets. As stated above, the Corporation utilizes the mark-to-market method of accounting for its non-hedging commodity trading and price risk management activities. Accordingly, 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. In the period of contract execution, income or expense is recognized. 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. 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 three- and six- month periods ended June 30, 1998, were not material. In June 1998, the Financial Accounting Standards Board issued Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," which is required to be adopted in years beginning after June 15, 1999. The Statement permits early adoption as of the beginning of any fiscal quarter. The Corporation will adopt the new Statement by January 1, 2000. The Statement will require the Corporation to recognize all derivatives, as defined in the statement, on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of derivatives either will be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or will be recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be immediately recognized in earnings. The Corporation is currently evaluating what the effect of Statement 133 will be on the earnings and financial position of the Corporation. NOTE 2: The Utility Electric Generation 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, many Californians can choose an energy service provider who will provide their electric generation power. Customers within the Utility's service territory can purchase electricity: (1) from the Utility; (2) from retail electricity providers (for example, marketers including our energy service subsidiary, brokers, and aggregators); or (3) directly from unregulated power generators. The Utility will continue to provide distribution services to substantially all electric consumers within its service territory. Competitive Market Framework: - ----------------------------- To create the competitive generation market, California 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, under the jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees California's electric transmission grid ensuring that all users 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 has scheduled the delivery of regulatory "must-take" resources such as Qualifying Facilities (QFs) and Diablo Canyon Nuclear Power Plant (Diablo Canyon). After scheduling must- take resources, the ISO satisfies the remaining aggregate demand from the PX and purchases necessary generation and ancillary services to maintain grid reliability. 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 the Utility to purchase all electric power for its retail customers from the PX or from must-take resources. Excluding must-take resources, the Utility must sell all of its generated electric power to the PX. During the second quarter of 1998, the Cost of Energy for Utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services purchased from the ISO, and the cost of Utility generation, net of sales to the PX as follows: For the three months ended June 30, 1998 Cost of electric generation 502 Cost of purchase from PX 110 Proceeds from sales to PX (147) ------ Cost of electric energy 465 Utility cost of gas 104 ------ Cost of energy for Utility 569 Electric Transition Plan: - ------------------------- 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. The California legislature passed the legislation and the Governor signed it in 1996. As discussed below in Voter Initiative, the November 1998 California ballot will include provisions to overturn major portions of the current electric utility restructuring legislation and could have a material adverse impact on the Utility. There are two principle elements of the transition plan established by the restructuring legislation: (1) an electric rate freeze and rate reduction; and (2) recovery of transition costs. Both of these elements are discussed below. The restructuring legislation has established a transition period, which continues until the earlier of March 31, 2002, or when the Utility has recovered its authorized transition costs as determined by the CPUC. 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 established by the restructuring legislation 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. For the three- and six- month periods ended June 30, 1998, the electric rate reduction caused operating revenues to decrease by approximately $86 million and $180 million, respectively, as compared to the same periods in 1997. As authorized by the restructuring legislation, to pay for the 10 percent rate reduction, the Utility financed $2.9 billion of its transition costs with rate reduction bonds, which have maturities ranging from three months to ten years. The bonds defer recovery of a portion of the transition costs until after the transition period. We expect to recover the transition costs associated with the rate reduction bonds over the term of the bonds. Transition Cost Recovery: - ------------------------- The second element of the transition plan established by the restructuring legislation is recovery of transition costs. Transition costs are costs that are unavoidable and 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. (Regulatory assets are expenses deferred in the current or prior periods to be included in rates in future periods.) The costs of Utility-owned generation facilities are currently included in the Utility customers' rates. Above-market facility costs are those facilities whose book values 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. 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. The first of these valuations occurred on July 1, 1998, when the Utility sold three Utility-owned electric generation plants for $501 million. (See Utility Generation Divestiture, below.) For generation facilities that the Utility has not divested, the CPUC will approve the methodology to be used in the market valuation process. 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 345 million megawatt-hours at an aggregate average price of 6.5 cents per kilowatt-hour. To the extent that this price is above the market price, the 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 June 30, 1998, the Utility has accumulated approximately $6.3 billion of these assets net of obligations including the amounts reclassified from Property, Plant, and Equipment, discussed in Utility Generation Impairment below. The restructuring legislation specifies that the Utility must recover most transition costs 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, as authorized by the CPUC in consideration of the restructuring legislation, the Utility is recording 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 for these facilities is 6.77 percent. Although the Utility must recover most transition costs by March 31, 2002, certain transition costs may 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 through the collection of the Fixed Transition Amount (FTA) charge from customers. 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, the FTA and nuclear decommissioning charges 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 restructuring legislation gives the CPUC ultimate authority to determine the recoverable amount of transition costs. With this authority, the CPUC will review transition costs to determine reasonableness 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 sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. (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. Transition costs 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 transition cost disallowances, if any, cannot be predicted. Effective January 1, 1998, the Utility has been collecting eligible transition costs through a CPUC-authorized nonbypassable charge called the competition transition charge (CTC). The amount of revenue collected from frozen rates for recovery of transition costs is subject to seasonal fluctuations in the Utility's sales volumes. The amortization and depreciation of transition costs exceeded associated revenues for the three- and six- month periods ended June 30, 1998, by $181 million and $503 million, respectively. In accordance with CPUC rate treatment of transition costs, the Utility deferred this excess as a regulatory asset. 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. Based upon its current evaluation of these factors, the Corporation believes that the Utility will recover its transition costs. However, a change in one or more of these factors, including voter approval of Proposition 9 discussed below, could affect the probability of recovery of transition costs and result in a material charge. Utility Generation Divestiture: - ------------------------------- To alleviate market power concerns of the CPUC, the Utility has agreed to sell its fossil-fueled generation facilities. On July 1, 1998, the Utility completed the sale of three electric Utility-owned fossil-fueled generating plants to Duke Energy Power Services Inc. (Duke) for $501 million. These three fossil-fueled plants have a combined book value at July 1, 1998, of approximately $351 million and a combined capacity of 2,645 megawatts (MW). The three power plants are located at Morro Bay, Moss Landing, and Oakland. The Utility will continue to operate and maintain the plants under a two- year operating and maintenance agreement. Additionally, the Utility will retain the 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. See Note 4, Environmental Remediation, below. In July 1998, the Utility agreed with the City of San Francisco to withdraw from the auction process the Hunters Point Power Plant and permanently close it when reliable alternative electricity resources are operational. This agreement with the City of San Francisco is subject to CPUC approval. Hunters Point is a fossil-fueled plant with a generating capacity of 423 MW and a book value, including plant-related regulatory assets, at June 30, 1998, of $42 million. The Utility will proceed with the auction and sale of its remaining fossil-fueled and geothermal facilities, Potrero, Pittsburg, Contra Costa, and Geysers power plants. These remaining fossil-fueled and geothermal facilities have a combined generating capacity of 4,289 MW and a combined book value at June 30, 1998, of approximately $688 million. On August 5, 1998, the CPUC issued a draft environmental impact report on the Utility's proposed sale of these plants. Comments on the draft environmental impact report are due on September 21, 1998. The Utility expects to receive final bids to purchase these plants during the fourth quarter of 1998, subject to CPUC approval. The Utility expects that the sale of these plants will be completed during 1999. 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 Utility informed the CPUC that it does not intend to retain its remaining 4,000 MW of fossil-fueled and hydroelectric facilities as part of the Utility. These remaining facilities have a combined book value, including plant-related regulatory assets, at June 30, 1998, of approximately $1.5 billion. The Utility expects to announce a plan for disposition of these facilities in 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. Utility Generation Impairment: - ------------------------------ In the third quarter of 1997, the Emerging Issues Task Force (EITF)of the Financial Accounting Standards Board reached a consensus on its issue No. 97-4, entitled "Deregulation of the Pricing of Electricity - Issues Related to the Application of SFAS (Statement of Financial Accounting Standard) No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS No. 71" (EITF 97-4), which provided authoritative guidance on the applicability of SFAS No. 71 during the transition period. EITF 97-4 required the Utility to discontinue the application of SFAS No. 71 for the generation portion of its operations as of July 24, 1997, the effective date of EITF 97-4. EITF 97-4 requires that regulatory assets and liabilities (both those in existence today and those created under the terms of the transition plan established by the restructuring legislation) be allocated to the portion of the business from which the source of the regulated cash flows is derived. Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", an impairment analysis was required of the generating assets no longer subject to the guidance of SFAS No. 71. The Utility compared the cash flows from all sources, including CTC revenues, to the cost of the generating facilities and found that the assets were not impaired. During the second quarter of 1998, the Staff of the Securities and Exchange Commission (SEC) issued interpretive guidance regarding the application of EITF 97-4 and SFAS No. 121. The guidance states that an impairment analysis should exclude CTC revenues from the recovery stream. Under this interpretation, the Utility performed the impairment analysis excluding CTC revenues and determined that $3.9 billion of its generation facilities are impaired. Because the Utility expects to recover the impaired assets as a transition cost under the transition plan established by the restructuring legislation, discussed above, the Utility recorded a regulatory asset for the impaired amounts as required by EITF 97-4. Accordingly, at June 30, 1998, this amount has been reclassified from Property, Plant, and Equipment to Regulatory assets on the accompanying balance sheets. In addition, prior year balances have been reclassified. California Voter Initiative: - ---------------------------- On November 24, 1997, various consumer groups filed a voter initiative (Proposition 9) with the California Attorney General that would overturn major provisions of California's electric industry restructuring legislation discussed above. On June 24, 1998, the California Secretary of State announced that Proposition 9 had qualified for the November 1998 statewide ballot. Proposition 9 proposes to: (1) require the Utility and the other California investor-owned utilities to provide a 10 percent rate reduction to their residential and small commercial customers in addition to the 10 percent rate reduction mandated by the electric restructuring legislation; (2) eliminate transition cost recovery for nuclear generation plants and related assets and obligations (other than reasonable decommissioning costs); (3) eliminate transition cost recovery for non-nuclear generation plants and related assets and obligations (other than costs associated with QFs), unless the CPUC finds that the utilities would be deprived of the opportunity to earn a fair rate of return; and (4) prohibit the collection of any customer charges necessary to pay principal and interest on the rate reduction bonds or, if a court finds that such prohibition is not legal, require that utility rates be reduced to fully offset the cost of the customer surcharges. If the voters approve Proposition 9, then legal challenges by the California utilities, including the Utility, would ensue. Although the Corporation believes the arguments in litigation challenging Proposition 9 would be compelling, no assurances can be given whether or when Proposition 9 would be overturned. In addition to the potential impacts on the Utility discussed below, any such litigation may adversely affect the secondary market for the rate reduction bonds. Further, the collection of the FTA charges necessary to pay the rate reduction bonds while the litigation is pending would be precluded, if an immediate stay is not granted. Even if a stay is granted, there may be terms and conditions imposed in connection with the stay that may adversely affect the cash flow for timely interest payments on the rate reduction bonds. The failure to pay interest when due could give rise to an event of default, which would permit acceleration of the maturity of the rate reduction bonds. Finally, if Proposition 9 is upheld against legal challenge, then the primary source for payments on the rate reduction bonds would become unavailable and holders of the rate reduction bonds could incur a loss of their investment. If Proposition 9 is approved and implemented, and if the Utility were unable to conclude that it is probable that Proposition 9 ultimately would be found invalid, then under applicable accounting principles the Utility would be required to write-off generation-related regulatory assets and certain investments in electric generation plant which would no longer be probable of recovery because of reductions in future revenues. The Utility anticipates that such a write-off could amount to approximately $2 billion after-tax, or, based on conservative assumptions, $3 billion after-tax. The duration and amount of the rate decrease contemplated by Proposition 9 is uncertain and, if Proposition 9 is approved, will be subject to interpretation by the courts and regulatory agencies. However, if all provisions of Proposition 9 ultimately are upheld against legal challenge and interpreted in an adverse manner, the amount of the average earnings reductions could be approximately $200 million per year from 1999 through 2001 (based on current frozen rates which would otherwise be in effect and assuming rates are reduced to offset the charges for the rate reduction bonds) and approximately $50 million per year from 2002 (based on rates under current regulatory decisions assuming such decisions are in effect after the latest date on which the rate freeze would otherwise end) to 2007 (the longest maturity date of the rate reduction bonds). The earnings reduction estimates depend on how the courts and regulators interpret Proposition 9 and how future rate changes unrelated to Proposition 9 affect the Utility's electric revenues. 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, then 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. Secondary financial protection provides an additional $8.7 billion in coverage, which is mandated by federal legislation. It 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, then 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 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 June 30, 1998, of $263 million for hazardous waste remediation costs at identified sites, including fossil- fueled power plants. Environmental remediation at identified sites may be as much as $474 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. The Utility estimated this upper limit of the range of costs 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 expected outcomes change. Of the $263 million liability, discussed above, the Utility has recovered $80 million and expects to recover $156 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 Utility 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 June 30, 1998, the Utility's net investment was $626 million. 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, Helms' sunk costs are 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 cost 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 Utility 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 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 replaces the shares sold to the Corporation through purchases on the open market or through privately negotiated transactions. The Corporation anticipates that the contract will expire by December 31, 1998. The Corporation may settle this additional obligation in either shares of stock or cash. The Corporation does not expect the program to have a material impact on the Corporation's financial position or results of operations. Legal Matters: - -------------- Chromium Litigation Several civil suits are pending against the Utility in various California state courts. 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, California. Two of these cases also name PG&E Corporation as a defendant. In 1998, the court dismissed 240 plaintiffs' claims; the dismissals are subject to possible appeal. In other cases, the courts dismissed more than 100 additional plaintiffs' claims for failure to respond to discovery or otherwise pursue their claims. Also in 1998, various court rulings were issued finding that certain of the claims are not recognizable under California law. Currently, there are claims pending on behalf of approximately 2,300 individuals. The Utility is responding to the suits and asserting affirmative defenses. One of the cases, involving 40 plaintiffs, is scheduled for trial beginning December 7, 1998, in San Francisco. 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, 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 classes of every municipality in Texas (excluding certain cities that filed separate suits) in which any of the defendants engaged in business activities related to natural gas or natural gas liquids, sold or supplied gas, or used public rights-of-way. Generally, these cities allege, among other things, that: (1) owners or operators of pipelines occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities; and (2) the gas marketers 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 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) applies 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 Form 10-K. In this MD&A, we explain the results of operations for the three- and six- month periods ended June 30, 1998, as compared to the corresponding periods 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. These statements are based on the beliefs and assumptions of management and on information currently available to management. Words such as "estimates," "expects," "anticipates," "plans," "believes," and similar expressions identify forward-looking statements involving risks and uncertainties. Actual results may differ materially from those expressed in the forward-looking statements. The important factors that could affect future results and that could cause actual results to differ materially from those expressed in the forward looking statements, or from historical results, include, but are not limited to: (1) the ongoing restructuring of the electric and gas industries in California and nationally; (2) the continued application of the regulatory framework established by the California Public Utilities Commission (CPUC) and state legislation; (3) the outcome of the regulatory proceedings related to the restructuring; (4) the outcome of Proposition 9; (5) our Utility's ability to collect revenues sufficient to recover transition costs in accordance with its transition cost recovery plan, specifically in light of Proposition 9; (6) the planned sale of the Utility- owned fossil-fueled electric generating plants; (7) the impact of our planned acquisition of the New England Electric System (NEES) assets; (8) the approval of our Utility's 1999 General Rate Case application resulting in the Utility's ability to earn its authorized rate of return; (9) increased competition; (10) our ability to expand into new markets and to compete successfully in those markets; (11) fluctuations in the prices of commodity gas and electricity and our ability to successfully hedge against such price risk; and (12) the potential impact from internal or external Year 2000 problems. We discuss each of these items in greater detail below. RESULTS OF OPERATIONS In this section, we provide the components of our earnings for the three- and six- month periods ended June 30, 1998, and 1997. We then explain why operating revenues and expenses varied from 1998 to 1997. The following table shows our results of operations for the three- and six- month periods ended June 30, 1998, and 1997, and total assets at June 30, 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. (in millions)
Unregulated Corporate Business and Utility Operations Other Total -------- ------------ --------- ------- For the three months ended June 30, 1998 Operating revenues $ 2,117 $ 2,851 $ (181) $ 4,787 Operating expenses 1,620 2,788 (181) 4,227 ------- ------- ------ ------- Operating income (loss) before income taxes 497 63 - 560 Income available for common stock 186 (5) (7) 174 1997 Operating revenues $ 2,279 $ 815 $ (11) $ 3,083 Operating expenses 1,909 813 (10) 2,712 ------- ------- ------- ------- Operating income (loss) before income taxes 370 2 (1) 371 Income available for common stock 122 77 (6) 193 For the six months ended June 30, 1998 Operating revenues $ 4,143 $ 5,334 $ (337) $ 9,140 Operating expenses 3,220 5,231 (337) 8,114 ------- ------- ------ ------- Operating income (loss) before income taxes 923 103 - 1,026 Income available for common stock 334 (1) (20) 313 Total assets at June 30 $23,618 $ 6,520 $ (849) $29,289 1997 Operating revenues $ 4,553 $ 1,920 $ (24) $ 6,449 Operating expenses 3,737 1,897 (20) 5,614 ------- ------- ------- ------- Operating income (loss) before income taxes 816 23 (4) 835 Income available for common stock 286 87 (8) 365 Total assets at June 30 $23,531 $ 3,439 $ (295) $26,675
Common Stock Dividend: - ---------------------- We base our common stock dividend 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 requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay the Corporation. At June 30, 1998, the Utility was in compliance with its CPUC-authorized capital structure. The Utility believes that it will continue to meet this condition in the future without affecting the Corporation's ability to pay common stock dividends. However, see the discussion of the California Voter Initiative below and its potential impact on future earnings. Earnings Per Common Share: - -------------------------- Earnings per common share for the three- and six- month periods ended June 30, 1998, decreased $.03 and $.09 cents, respectively, as compared to the same periods in 1997. The activity discussed below affected earnings per common share. Utility Results: - ---------------- Utility operating revenues for the three- and six- month periods ended June 30, 1998, decreased $162 million and $410 million, respectively, as compared to the same periods in 1997. Operating revenues declined due to: (1) a 10 percent electric rate reduction, discussed below, provided to residential and small commercial customers, which caused a decrease of $86 million and $180 million for both the three- and six- month periods ended June 30, 1998, respectively; (2) the termination of our volumetric (ERAM) and energy cost (ECAC) revenue balancing accounts, which totaled approximately $96 million in the six-month period ended June 30, 1997, (we replaced the ERAM and ECAC balancing accounts with the transition cost balancing account (TCBA), which impacts expenses instead of revenues as discussed in Transition Cost Recovery, below); (3) a decrease in usage and sales to medium and large electric customers resulting from the effects of competition; and (4) a decrease in usage and sales to commercial and agricultural electric customers resulting from their lower demand for irrigation water pumping as a result of heavier rainfall in the current year. Utility operating expenses decreased $289 million and $517 million, respectively, for the three- and six- month periods ended June 30, 1998, as compared to the same periods in 1997. Operating expenses declined primarily as a result of lower gas prices, lower transmission pipeline demand charges, the lack of a refueling outage at Diablo Canyon Power Plant (Diablo Canyon), and expense deferrals related to electric industry restructuring. Increased expenses incurred for system reliability and accelerated amortization of regulatory assets recovered under the transition plan established by the restructuring legislation partially offset these decreases. As previously indicated, electric industry restructuring provides for recovery of certain costs in future periods. Some costs, associated with the expense deferrals mentioned above, 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. Unregulated Business Results: - ----------------------------- Our unregulated business operations include those business activities that are not directly regulated by the CPUC. Unregulated business operating revenues for the three- and six- month periods ended June 30, 1998, increased approximately $2.0 billion and $3.4 billion, respectively, while operating expenses also increased approximately $2.0 billion and $3.3 billion, respectively, as compared to the same periods in 1997. These increases were due to operations associated with our energy commodities and services activities and due to the acquisition of the natural gas operations of Valero Energy Corporation in July 1997. Energy trading volumes continue to increase over 1997 levels. The resultant gross operating margin increases, however, were partially offset by decreases in our gas transmission operating margins due to low transmission and natural gas liquids prices in Texas. Unregulated business operations contributed $82 million and $88 million less, respectively, in net income in the three- and six- month periods ended June 30, 1998, than in the same periods in 1997, primarily due to the sale of our Australian holdings (See Acquisitions and Sales, below.) In addition, in the second quarter of 1997, the Corporation recognized a $110 million gain on the sale of its interest in Intergen, which was partially offset by write-offs of unregulated investments of approximately $41 million. 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: The Utility Electric Generation 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, many Californians can choose an energy service provider who will provide 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. Competitive Market Framework: - ----------------------------- To create the 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, under the jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees California's electric transmission grid, ensuring 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 has scheduled the delivery of 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 and purchases necessary generation and ancillary services to maintain grid reliability. 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. Excluding must-take resources, we must sell all of our Utility-generated electric power to the PX. During the second quarter of 1998, the Cost of Energy for our Utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services purchased from the ISO, and the cost of Utility generation, net of sales to the PX as follows: For the three months ended June 30, 1998 Cost of electric generation 502 Cost of purchase from PX 110 Proceeds from sales to PX (147) ------- Cost of electric energy 465 Utility cost of gas 104 ------- Cost of energy for Utility 569 Electric Transition Plan: - ------------------------- 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. In addition, we have made strategic investments throughout the nation that will further position us as a national energy provider. In developing state legislation to implement a competitive market, it was recognized 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. The California Legislature passed the legislation and the Governor signed it in 1996. As discussed below in Voter Initiative, the November 1998 California ballot will include provisions to overturn major portions of the current electric utility restructuring legislation and could have a material adverse impact on the Utility. There are two principle elements to the transition plan established by restructuring legislation: (1) an electric rate freeze and rate reduction; and (2) recovery of transition costs. Both of these elements, and the impact of the approved transition plan on our Utility's customers, are discussed below. The restructuring legislation has established a transition period, which continues until the earlier of March 31, 2002, or when the Utility has recovered its authorized transition costs as determined by the CPUC. 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 established by restructuring legislation 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. For the three- and six- month periods ended June 30, 1998, the rate reduction caused operating revenues to decrease by approximately $86 million and $180 million, respectively, as compared to the same periods in 1997. As authorized by the restructuring legislation, to pay for the 10 percent rate reduction, the Utility financed $2.9 billion of our transition costs with rate reduction bonds, which have maturities ranging from three months to ten years. The bonds defer recovery of a portion of the transition costs until after the transition period. We expect to recover the transition costs associated with the rate reduction bonds over the term of the bonds. Transition Cost Recovery: - ------------------------- The second element of the transition plan, established by restructuring legislation, is recovery of transition costs. Transition costs are costs that are unavoidable and 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. (Regulatory assets are expenses deferred in the current or prior periods to be included in rates in future periods.) The costs of Utility-owned generation facilities are currently included in our Utility customers' rates. Above-market facility costs are those facilities whose book values 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. 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 our Utility's generation facilities. The first of these valuations occurred on July 31, 1998, when the Utility sold three Utility-owned electric generation plants for $501 million. (See Utility Generation Divestiture, below.) For generation facilities that the Utility has not divested, the CPUC will approve the methodology to be used in the market valuation process. 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 345 million megawatt-hours at an aggregate average price of 6.5 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 June 30, 1998, the Utility has accumulated approximately $6.3 billion of these assets net of obligations including the amounts reclassified from Property, Plant, and Equipment, discussed in Utility Generation Impairment below. The restructuring legislation specifies that 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, as authorized by the CPUC in consideration of the restructuring legislation, the Utility is recording 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 for these facilities is 6.77 percent. Although the Utility must recover most transition costs by March 31, 2002, the Utility may include certain transition costs 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 through the collection of the Fixed Transition Amount (FTA) charge from customers. 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, the FTA and nuclear decommissioning charges 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 restructuring legislation gives the CPUC ultimate authority to determine the recoverable amount of transition costs. With this authority, the CPUC will review transition costs to determine the reasonableness 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 sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. (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. Transition costs 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 has been collecting eligible transition costs through a CPUC-authorized nonbypassable charge called the competition transition charge (CTC). The amount of revenue collected from frozen rates for transition cost recovery is subject to seasonal fluctuations in the Utility's sales volumes. The amortization and depreciation of transition costs exceeded associated revenue for the three- and six- month periods ended June 30, 1998, by $181 million and $503 million, respectively. In accordance with CPUC rate treatment of transition costs, the Utility deferred this excess as a regulatory asset. 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 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. Based upon its evaluation of these factors, the Corporation believes that the Utility will recover its transition costs. However, a change in one or more of these factors, including voter approval of Proposition 9 discussed below, could affect the probability of recovery of transition costs and result in a material charge. Utility Generation Divestiture: - ------------------------------- To alleviate market power concerns of the CPUC, we have agreed to sell our fossil-fueled generation facilities. On July 1, 1998, the Utility completed the sale of three electric Utility-owned fossil-fueled generating plants to Duke Energy Power Services Inc. (Duke) for $501 million. These three fossil-fueled plants have a combined book value at July 1, 1998, of approximately $351 million and a combined capacity of 2,645 megawatts (MW). The three power plants are located at Morro Bay, Moss Landing, and Oakland. The Utility will continue to operate and maintain the plants under a two- year operating and maintenance agreement. Additionally, the Utility will retain the 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. In July 1998, the Utility agreed with the City of San Francisco to withdraw from the auction process the Hunters Point Power Plant and permanently close it when reliable alternative electricity resources are operational. This agreement with the City of San Francisco is subject to CPUC approval. Hunters Point is a fossil-fueled plant with a generating capacity of 423 MW and a book value, including plant-related regulatory assets, at June 30, 1998, of $42 million. The Utility will proceed with the auction and sale of its remaining fossil-fueled and geothermal facilities, Potrero, Pittsburg, Contra Costa, and Geysers power plants. These remaining fossil-fueled and geothermal facilities have a combined generating capacity of 4,289 MW and a combined book value at June 30, 1998, of approximately $688 million. On August 5, 1998, the CPUC issued a draft environmental impact report on the Utility's proposed sale of these plants. Comments on the draft environmental impact report are due on September 21, 1998. The Utility expects to receive final bids to purchase these plants during the fourth quarter of 1998, subject to CPUC approval. The Utility expects that the sale of these plants will be completed during 1999. 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. The Utility informed the CPUC that it does not intend to retain its remaining 4,000 MW of fossil-fueled and hydroelectric facilities as part of the Utility. These remaining facilities have a combined book value, including plant-related regulatory assets, at June 30, 1998, of approximately $1.5 billion. Our Utility expects to announce a plan for the disposition of the facilities in 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. Utility Generation Impairment: - ------------------------------ In the third quarter of 1997, the Emerging Issues Task Force (EITF)of the Financial Accounting Standards Board reached a consensus on its issue No. 97-4, entitled "Deregulation of the Pricing of Electricity - Issues Related to the Application of SFAS (Statement of Financial Accounting Standard) No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS No. 71" (EITF 97-4), which provided authoritative guidance on the applicability of SFAS No. 71 during the transition period. EITF 97-4 required the Utility to discontinue the application of SFAS No. 71 for the generation portion of its operations as of July 24, 1997, the effective date of EITF 97-4. EITF 97-4 requires that regulatory assets and liabilities (both those in existence today and those created under the terms of the transition plan) be allocated to the portion of the business from which the source of the regulated cash flows is derived. Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", an impairment analysis was required of the generating assets no longer subject to the guidance of SFAS No. 71. The Utility compared the cash flows from all sources, including CTC revenues, to the cost of the generating facilities and found that the assets were not impaired. During the second quarter of 1998, the Staff of the Securities and Exchange Commission (SEC) issued interpretive guidance regarding the application of EITF 97-4 and SFAS No. 121. The guidance states that an impairment analysis should exclude CTC revenues from the recovery stream. Under this interpretation, the Utility performed the impairment analysis excluding CTC revenues and determined that $3.9 billion of its generation facilities are impaired. Because the Utility expects to recover the impaired assets as a transition cost under the transition plan established by the restructuring legislation, discussed above, the Utility recorded a regulatory asset for the impaired amounts as required by EITF 97-4. Accordingly, at June 30, 1998, this amount has been reclassified from Property, Plant, and Equipment to Regulatory assets on the accompanying balance sheets. In addition, prior year balances have been reclassified. Customer Impacts of Transition Plan: - ------------------------------------ Effective March 31, 1998, all Californians may choose their electric commodity provider. As of July 31, 1998, our Utility had accepted approximately 55,000 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 substantially 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 may 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: (1) refund the savings to customers where the Utility provides the billing for these services; or (2) remit the savings to the electric providers where the electric provider bills for these services. The electric providers 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. California Voter Initiative: - ---------------------------- On November 24, 1997, various consumer groups filed a voter initiative (Proposition 9) with the California Attorney General that would overturn major provisions of California's electric industry restructuring legislation discussed above. On June 24, 1998, the California Secretary of State announced that Proposition 9 had qualified for the November 1998 statewide ballot. Proposition 9 proposes to: (1) require the Utility and the other California investor-owned utilities to provide a 10 percent rate reduction to their residential and small commercial customers in addition to the 10 percent rate reduction mandated by the electric restructuring legislation; (2) eliminate transition cost recovery for nuclear generation plants and related assets and obligations (other than reasonable decommissioning costs); (3) eliminate transition cost recovery for non-nuclear generation plants and related assets and obligations (other than costs associated with QFs), unless the CPUC finds that the utilities would be deprived of the opportunity to earn a fair rate of return; and (4) prohibit the collection of any customer charges necessary to pay principal and interest on the rate reduction bonds or, if a court finds that such prohibition is not legal, require that utility rates be reduced to fully offset the cost of the customer surcharges. On May 22, 1998, a group known as "Californians for Affordable and Reliable Electric Services" (CARES) filed a petition in the California Third District Court of Appeal to exclude Proposition 9 from the November 1998 ballot on the grounds that it represents an unconstitutional impairment of contract rights and that it is an unconstitutional attempt to implement actions by statute that only can be done through a state constitutional amendment. Supporters of CARES include the California State Chamber of Commerce, the state's investor-owned utilities (including Pacific Gas and Electric Company), and a wide range of business, environmental, and consumer groups. On July 2, 1998, the Court denied the CARES petition. CARES appealed the decision to the California Supreme Court and the court denied the appeal without comment. Neither court ruled on the merits of the case, leaving open the option of legal action following the election. If the voters approve Proposition 9, further legal challenges by the California utilities, including the Utility, would ensue. Although the Corporation believes the arguments in litigation challenging Proposition 9 would be compelling, no assurances can be given whether or when Proposition 9 would be overturned. In addition to the potential impacts on the Utility discussed below, any such litigation may adversely affect the secondary market for the rate reduction bonds. Further, the collection of the FTA charges necessary to pay the rate reduction bonds while the litigation is pending would be precluded, if an immediate stay is not granted. Even if a stay is granted, there may be terms and conditions imposed in connection with the stay that may adversely affect the cash flow for timely interest payments on the rate reduction bonds. The failure to pay interest when due could give rise to an event of default, which would permit acceleration of the maturity of the rate reduction bonds. Finally, if Proposition 9 is upheld against legal challenge, then the primary source for payments on the rate reduction bonds would become unavailable and holders of the rate reduction bonds could incur a loss of their investment. If Proposition 9 is approved and implemented, and if the Utility were unable to conclude that it is probable that Proposition 9 ultimately would be found invalid, then under applicable accounting principles the Utility would be required to write-off generation-related regulatory assets and certain investments in electric generation plant which would no longer be probable of recovery because of reductions in future revenues. The Utility anticipates that such a write-off could amount to approximately $2 billion after-tax, or, based on conservative assumptions, $3 billion after-tax. The duration and amount of the rate decrease contemplated by Proposition 9 is uncertain and, if Proposition 9 is approved, will be subject to interpretation by the courts and regulatory agencies. However, if all provisions of Proposition 9 ultimately are upheld against legal challenge and interpreted in an adverse manner, the amount of the average earnings reductions could be approximately $200 million per year from 1999 through 2001 (based on current frozen rates which would otherwise be in effect and assuming rates are reduced to offset the charges for the rate reduction bonds) and approximately $50 million per year from 2002 (based on rates under current regulatory decisions assuming such decisions are in effect after the latest date on which the rate freeze would otherwise end) to 2007 (the longest maturity date of the rate reduction bonds). The earnings reduction estimates depend on how the courts and regulators interpret Proposition 9 and how future rate changes unrelated to Proposition 9 (such as changes resulting from the General Rate Case proceeding, discussed below) affect the Utility's electric revenues. The Utility Electric Transmission Business: Utility electric transmission revenues are under FERC jurisdiction. In December 1997, the FERC put into effect rates to recover annual retail electric transmission revenues of $301 million, effective March 31, 1998, the operational date of the ISO and PX. The authorized revenues were consistent with Utility electric transmission revenues in CPUC-authorized 1997 electric rates. In May 1998, the FERC allowed a $30 million increase in retail electric transmission revenues to be effective October 30, 1998. All 1998 retail electric transmission revenues are subject to refund pending further analysis by the FERC. The Utility does not expect a material change in transmission revenues resulting from the FERC's final decision. The Utility Electric Distribution Business: During the second quarter of 1998, the CPUC issued various decisions in which it indicated its support for the construction of duplicative electric distribution facilities to allow competition within the electric distribution market. We believe that these regulatory pronouncements contradict prior CPUC policy on duplicative distribution facilities and that these pronouncements have increased substantially the uncertainty surrounding the future role of California's utility distribution companies. In addition, we believe that the CPUC made these regulatory pronouncements without a comprehensive examination of such fundamental issues as: (1) recovery of electric distribution transition costs; (2) the shifting of costs among customer classes and geographic regions; (3) the economic impacts of duplicate distribution facilities; and (4) the distribution utilities' statutory obligation to serve. At this time, we cannot predict the extent that the CPUC will encourage the future construction of duplicative distribution facilities or the impact that future duplicative distribution facilities and increased competition will have on our or the Utility's future financial condition and results of operations. The Utility Gas Business: In March 1998, the Utility implemented a CPUC-approved accord with a broad coalition of customer groups and industry participants that adopted market- oriented policies in the Utility's natural gas transmission business. The accord unbundled the Utility's gas transmission and storage services from its distribution services and established gas transmission and storage rates for the period March 1998 through December 2002. In addition, the accord increases the opportunity for the Utility's residential and small commercial (core) customers to purchase gas from competing suppliers. 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 new alternative market structures with the goal of encouraging competition and customer choice, while maintaining a high standard of consumer protection. On August 6, 1998, the CPUC directed its Energy Division to prepare proposed consumer protection guidelines for the restructuring of the natural gas industry. The CPUC stated that it intends to issue a proposed market structure decision after it reviews various reports and materials scheduled to be completed this summer and fall. The CPUC also directed utilities to file applications identifying gas cost functional categories, due February 26, 1999. However, on August 12, 1998, the California legislature passed Senate Bill (SB) 1602, which requires legislative approval of any CPUC decisions regarding gas unbundling issued after July 1, 1998. SB 1602 awaits the Governor's signature. At this point, we cannot predict the outcome of these proceedings and their impact on our financial position and results of operations. Unregulated Business Operations: We provide a wide range of integrated energy products and services designed to take advantage of the competitive energy marketplace throughout the United States. Through our unregulated subsidiaries, we: (1) provide gas transmission services in Texas and the Pacific Northwest; (2) develop, build, operate, own, and manage electric generation facilities across the country; (3) provide customers nationwide with services to manage and make more efficient their energy consumption; and (4) purchase and resell energy commodities and related financial instruments. In providing integrated energy products and services, we continually evaluate the composition of our assets. PG&E Corporation: PG&E Corporation became the holding company of the Utility in 1997. At that time, we transferred the unregulated subsidiaries of the Utility to PG&E Corporation. A condition of the CPUC's approval of the holding company formation was that the CPUC's Office of Ratepayer Advocates (ORA) conduct and supervise an audit of transactions between the Utility and its affiliates from 1994 to 1996. The audit report, completed in November 1997, was critical of the Utility's affiliate transaction internal controls and compliance. The auditors recommended imposing conditions affecting the financing and business composition of the Corporation. In April 1998, the Utility filed testimony with the CPUC opposing the recommended conditions. Hearings to determine if the additional recommended conditions should be imposed on PG&E Corporation are scheduled to begin in the second half of 1998. We expect a final CPUC decision in early 1999. If the CPUC imposed the recommended financial conditions on the Corporation without modification, then such conditions could have an adverse material impact on future results of operations. ACQUISITIONS AND SALES: In July 1998, the Corporation sold its Australian energy holdings to Duke Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation. The assets, located in the southeast corner of the Australian state of Queensland, include a 627-kilometer gas pipeline, pipeline operations, and trading and marketing operations. PG&E Corporation had previously announced that it was evaluating its Australian holdings in light of its intention to focus on its national energy strategy . The sale to DEI represents a premium on the price in local currency of our 1996 investment in the assets. However, the transaction resulted in a non-recurring charge of $.06 per share in the second quarter primarily due to the 22 percent currency devaluation of the Australian dollar against the U.S. dollar during the past two years. In 1997, the Corporation agreed to acquire, through its subsidiary USGen, a portfolio of electric generating assets and power supply contracts from 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, the Corporation expects financing requirements to total approximately $1.805 billion, to be funded through $1.38 billion of USGen debt and a $425 million equity contribution. The assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 MW and 23 multi-year power purchase agreements representing an additional 1,100 MW of production capacity. The Corporation expects to complete the acquisition in the third quarter of 1998. The Corporation agreed to acquire these generating facilities and power supply contracts in anticipation of deregulation of the electric industry in several New England states. In Massachusetts, electric industry restructuring legislation took effect March 1, 1998. However, a referendum to repeal this legislation is on the November ballot. If the voters approve the referendum, then the restructuring legislation in Massachusetts may be repealed. As Massachusetts represents only a portion of the New England market, the Corporation does not expect that any repeal will have a material impact on its results of operation or financial position. In addition, as discussed above in Utility Generation Divestiture, as part of electric industry restructuring, the CPUC has been informed that the Utility does not intend to retain any of its remaining non-nuclear generation facilities as part of the Utility. YEAR 2000: 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. Currently, we are focusing our efforts to be Year 2000 ready on those software and embedded systems, which are critical to our business. We expect to complete remediation of the critical software systems by the end of 1998 and to complete testing of these systems by the third quarter of 1999. Although we have completed an enterprise-wide inventory of all embedded systems to assess the degree of Year 2000 compliance, additional embedded systems that require Year 2000 remediation may be discovered as we begin the remediation and testing phases of our compliance effort. We expect to complete assessment of all critical embedded systems and to repair or replace those systems found to be non-compliant by the fourth quarter of 1999. We also depend upon external parties including customers, suppliers, business partners, government agencies, and financial institutions to reliably deliver our products and services. To the extent that any of these parties experience Year 2000 problems in their systems, the demand for and the reliability of our services may be adversely affected. We have begun to assess the degree to which third parties with whom we have significant business relationships have adequate plans to address Year 2000 problems. We expect to complete such assessment by the fourth quarter of 1998. To the extent appropriate, we plan to develop contingency plans to reduce the risk of material impacts on our operations from Year 2000 problems. Due to the speculative nature of contingency planning, it is uncertain whether such plans actually will be sufficient to reduce the risk of material impacts on our operations due to Year 2000 problems. Through June 30, 1998, we have spent approximately $135 million over the past few years to assess and remediate Year 2000 problems and to replace non-compliant software systems. In large part, these non-compliant software systems were replaced for business purposes other than addressing Year 2000 issues. The replacement costs for these systems were capitalized. The remaining costs, including costs incurred to assess and remediate Year 2000 problems, were expensed. Currently, we estimate that we will spend approximately $100 million in the aggregate for the remainder of 1998 and 1999 to address Year 2000 issues, to replace non-compliant software systems, and to replace hardware in non-compliant embedded systems and computer systems. We expect that approximately $30 million of the estimated aggregate amount will represent replacement costs incurred primarily for business purposes other than to address Year 2000 issues. This amount will be capitalized. The remaining amount, approximately $70 million, will be expensed. As we continue to assess our systems and as the remediation and testing phases of our compliance effort progresses, our estimated costs may increase. Further, we expect to incur costs after the Year 1999 to remediate and replace less critical software and embedded systems. Our current schedule is subject to change, depending on developments that may arise through further assessment of our systems, and through the remediation and testing phases of our compliance effort. Further, our current schedule is partially dependent on the efforts of third parties including vendors, suppliers, and customers. Therefore, delays by third parties may cause our schedule to change. Based on our current schedule for the completion of Year 2000 tasks, we believe our plan is adequate to secure Year 2000 readiness of our critical systems. Nevertheless, achieving Year 2000 readiness is subject to various risks and uncertainties, many of which are described above. We are not able to predict all the factors that could cause actual results to differ materially from our current expectations as to our Year 2000 readiness. However, if we, or third parties with whom we have significant business relationships, fail to achieve Year 2000 readiness with respect to critical systems, there could be a material adverse impact on the Utility's and PG&E Corporation's financial position, results of operations, and cash flows. LIQUIDITY AND CAPITAL RESOURCES: Sources of Capital: - ------------------- The Corporation funds capital requirements 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 six-month period ended June 30, 1998, the Corporation issued $36 million of common stock, primarily through the Dividend Reinvestment Plan and the Stock Option Plan. Also during the six-month period ended June 30, 1998, the Corporation paid dividends of $240 million and declared dividends of $229 million. The Utility paid dividends of $215 million to PG&E Corporation during the six-month period ended June 30, 1998. In July 1998, the Utility declared dividends of $100 million payable to PG&E Corporation in July. As of December 31, 1997, the Board of Directors had authorized the repurchase of 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 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 replaces the shares sold to the Corporation through purchases on the open market or through privately negotiated transactions. We anticipate that the contract will expire by December 31, 1998. The Corporation may settle this additional obligation in either shares of stock or cash. The Corporation does not expect the program to have a material impact on its 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. We use both of these credit facilities for general corporate purposes. There were no borrowings under the credit facilities at June 30, 1998. At June 30, 1998, the Corporation, primarily through an unregulated business subsidiary, had $127 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 July 1998, the Utility repurchased $800 million of its common stock from PG&E Corporation, in addition to its $800 million common stock repurchase from PG&E Corporation in April 1998. The Utility used 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 six month period ended June 30, 1998, amounted to $498 million. Of this amount, $249 million related to the Utility's redemption of its 8 percent mortgage bonds due October 1, 2025, and $186 million related to the Utility's repurchase of its other mortgage bonds. The remaining $63 million related primarily to the scheduled maturity of long-term debt. In January 1998, the Utility redeemed its Series 7.44 percent stock with a face value of $65 million. In July 1998, the Utility redeemed its Series 6 7/8 percent preferred stock with a face value of $43 million. The Utility maintains a $1 billion revolving credit facility, which expires in 2002. The Utility may extend the facility annually for additional one-year periods upon agreement with the banks. There were no borrowings under this credit facility at June 30, 1998. 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 1999 Cost of Capital Application with the CPUC. The Utility requested 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. We expect a final CPUC decision in February 1999. 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 sought no change in the cost of capital for the hydroelectric and geothermal generation assets in its 1999 Cost of Capital application. The Utility will file a separate application if the rehearing request is granted. 1999 General Rate Case (GRC): - ----------------------------- In December 1997, the Utility filed its 1999 GRC application with the CPUC. During the GRC process, the CPUC examines the Utility's non-fuel related costs to determine the amount it can charge customers. The Utility has requested an increase in authorized revenues, to be effective January 1, 1999, of $572 million in electric base revenues and an increase of $460 million in gas base revenues over authorized 1998 revenues. On June 26, 1998, the CPUC's ORA provided their revenue requirement calculation, which supplements ORA's June 8, 1998, report on the 1999 GRC proceeding. In the aggregate, the ORA is recommending a net increase of $5 million compared to the Utility's request for an aggregate increase of $1.03 billion. The ORA has recommended a decrease of $86 million in electric base revenues and an increase in gas base revenues of $91 million, over the Utility's 1998 authorized base revenues. Hearings for the GRC before an administrative law judge will take place August 24, 1998, through October 16, 1998. The administrative law judge will consider testimony and other evidence from many parties, including the ORA. The Utility expects the CPUC to issue a proposed decision by the administrative law judge in March 1999. The CPUC may accept all, part, or none of ORA's recommendations. We cannot predict the amount of base revenue increase or decrease the CPUC will ultimately approve. In the event of an adverse decision by the CPUC, and if the Utility is unable to lower expenses to conform to the base revenue amounts adopted by the CPUC while maintaining safety and system reliability standards, the ability of the Utility to earn its authorized rate of return for the years 1999 through 2001 would be adversely affected. The CPUC permitted the Utility to submit a plan for establishing interim rates, effective January 1, 1999, to cover the period between that date and the date the CPUC issues its decision. The CPUC plans to issue a decision on interim rates in November 1998. The 1999 GRC will not affect the authorized revenues for electric and gas transmission services or for gas storage services. The Utility determines the authorized revenues for each of these services in other proceedings. 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 June 30, 1998, the Utility expects to spend $263 million for clean-up costs at identified sites over the next 30 years. If other responsible parties fail to pay or expected outcomes change, then these costs may be as much as $474 million. Of the $263 million, the Utility has recovered $80 million and expects to recover $156 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. 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 the Utility divests of its fossil-fueled generation plants (see Utility 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. In the second quarter of 1998, the CPUC granted conditional authority to the Utility to use natural gas-based financial instruments to manage the impact of natural gas prices on the cost of electricity purchased pursuant to existing power purchase contracts. Under the authority granted in the CPUC decision, no natural gas-based financial instruments shall have an expiration date later than December 31, 2001. Furthermore, if the rate freeze ends before December 31, 2001, the Utility shall net any outstanding financial instrument contracts through equal and opposite contracts, within a reasonable amount of time. Also during the second quarter, the Utility filed an application with the CPUC to use natural gas-based financial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets. See Note 1 for additional discussion of risk management activities. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK PG&E Corporation's and Pacific Gas and Electric Company's primary market risk results from changes in energy prices. We engage in price risk management activities for both non-hedging and hedging purposes. Additionally, we 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. (See Risk Management Activities, above.) 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, and PG&E Corporation's and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 1998, various civil actions were filed against Pacific Gas and Electric Company (known collectively as the "Aguayo Litigation") in several California state courts. Each of the pending 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 April 28, 1998, a Los Angeles Superior Court judge found that claims by plaintiffs in Acosta v. Pacific Gas And Electric Company who were neither personally exposed to chromium nor yet conceived at the time of their parents' alleged exposure are not recognizable under current California law and should be dismissed. On June 25, 1998, the judge issued a similar order in Aguilar v. Pacific Gas and Electric Company. The judge has requested plaintiffs' counsel in both cases to identify those plaintiffs whose claims are based solely upon preconception exposure so the claims can be dismissed. Further, during the second quarter, approximately 100 additional plaintiffs have been dismissed from the Aguayo Litigation for failure to respond to discovery or otherwise pursue their claims. The trial in Riep v Pacific Gas and Electric Company has been continued to December 7, 1998, in San Francisco Superior Court. The eight plaintiffs in Pettit v. Pacific Gas and Electric Company dismissed their claims without prejudice in February 1998. Two of the pending 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. Although plaintiffs in both actions originally agreed to dismiss PG&E Corporation as a defendant, it is not clear whether plaintiffs will voluntarily file such dismissals. As described above, currently there are six pending cases comprising the Aguayo Litigation involving approximately 2300 remaining plaintiffs. As a result of the court's rulings barring preconception claims in Acosta v. Pacific Gas and Electric Company and Aguilar v. Pacific Gas and Electric Company, Pacific Gas and Electric Company expects that approximately 100 additional plaintiffs will be dismissed from these cases. Pacific Gas and Electric Company anticipates that plaintiffs will appeal these rulings. 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 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 six months ended June 30, 1998 was 2.88. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 1998 was 2.71. 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. B. Notice of Shareholder Proposals for 1999 Annual Meeting In accordance with new Securities and Exchange Commission (SEC) Rule 14a-5(e), shareholder proxies obtained by the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company in connection with their 1999 annual meetings of shareholders will confer on the proxyholders discretionary authority to vote on any matters presented at the meetings, unless notice of the matter is provided to the Vice President and Corporate Secretary of PG&E Corporation or Pacific Gas and Electric Company, or both (as may be applicable depending on whether the matter relates to PG&E Corporation or Pacific Gas and Electric Company, or both) no later than January 16, 1999. As stated in the 1998 joint proxy statement, any proposal by a shareholder to be submitted for possible inclusion in proxy soliciting materials (in accordance with the process established by SEC Rule 14a-8) for the 1999 annual meetings of shareholders of PG&E Corporation and Pacific Gas and Electric Company must be received by the Vice President and Corporate Secretary no later than November 2, 1998. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: 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 June 30, 1998 for PG&E Corporation Exhibit 27.2 Financial Data Schedule for the quarter ended June 30, 1998 for Pacific Gas and Electric Company (b) Reports on Form 8-K during the second quarter of 1998 and through the date hereof (1): 1. July 10, 1998 Item 5. Other Events A. Electric Industry Restructuring 1. Voter Initiative 2. Divestiture B. Pacific Gas and Electric Company's General Rate Case Proceeding C. Sale of Australian Assets 2. July 16, 1998 Item 5. Other Events A. Second Quarter 1998 Consolidated Earnings (unaudited) - -------------------- (1) 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 August 14, 1998 By ____________________________ CHRISTOPHER P. JOHNS Vice President and Controller (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company) Exhibit Index Exhibit No. Description of Exhibit 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 June 30, 1998 for PG&E Corporation 27.2 Financial Data Schedule for the quarter ended June 30, 1998 for Pacific Gas and Electric Company EX-11 2 EXHIBIT 11 PG&E CORPORATION COMPUTATION OF EARNINGS PER COMMON SHARE
- ---------------------------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, -------------------- ------------------------ (in millions, except per share amounts) 1998 1997 1998 1997 - ---------------------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Earnings available for common stock $ 174 $ 193 $ 313 $ 365 ========== ========== ========== ========== Average common shares outstanding 382 398 382 403 ========== ========== ========== ========== Basic EPS $ 0.46 $ 0.49 $ 0.82 $ 0.91 ========== ========== ========== ========== DILUTED EPS (1) Earnings available for common stock $ 174 $ 193 $ 313 $ 365 ========== ========== ========== ========== Average common shares outstanding 382 398 382 403 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at average market price) 1 - 1 - ---------- ---------- ---------- ---------- Average common shares outstanding as adjusted 383 398 383 403 ========== ========== ========== ========== Diluted EPS $ 0.46 $ 0.49 $ 0.82 $ 0.91 ========== ========== ========== ========== - ---------------------------------------------------------------------------------------------- (1) This presentation is submitted in accordance with Statement of Financial Accounting Standards No. 128.
EX-12 3 EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- --------------------------------------------------------------------------------------------------- Six Months Year ended December 31, ended ------------------------------------------------------- (dollars in millions) June 30, 1998 1997 1996 1995 1994 1993 - --------------------------------------------------------------------------------------------------- Earnings: Net income $ 349 $ 768 $ 755 $ 1,339 $ 1,007 $1,065 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates - - 3 4 (3) 7 Income tax expense 312 609 555 895 837 902 Net fixed charges 352 628 683 716 729 775 -------- -------- -------- -------- -------- -------- Total Earnings $ 1,013 $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749 ======== ======== ======== ======== ======== ======== Fixed Charges: Interest on long- term debt, net $ 311 $ 485 $ 574 $ 616 $ 639 $ 652 Interest on short- term borrowings 26 101 75 83 77 88 Interest on capital leases 1 2 3 3 2 2 Capitalized Interest - 1 1 - 2 46 AFUDC Debt 8 16 7 11 11 33 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 6 24 24 3 - - -------- -------- -------- -------- -------- -------- Total Fixed Charges $ 352 $ 629 $ 684 $ 716 $ 731 $ 821 ======== ======== ======== ======== ======== ======== Ratios of Earnings to Fixed Charges 2.88 3.19 2.92 4.13 3.52 3.35 - ---------------------------------------------------------------------------------------------------- Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest of subordinated debentures held by trust, interest on capital leases, and earnings required to cover the preferred stock dividend requirements.
EX-12 4 EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- ---------------------------------------------------------------------------------------------------- Six Months Year ended December 31, ended ------------------------------------------------------- (dollars in millions) June 30, 1998 1997 1996 1995 1994 1993 - ---------------------------------------------------------------------------------------------------- Earnings: Net income $ 349 $ 768 $ 755 $ 1,339 $ 1,007 $ 1,065 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates - - 3 4 (3) 7 Income tax expense 312 609 555 895 837 902 Net fixed charges 352 628 683 716 729 775 -------- -------- -------- -------- -------- -------- Total Earnings $ 1,013 $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749 ======== ======== ======== ======== ======== ======== Fixed Charges: Interest on long- term debt, net $ 311 $ 485 $ 574 $ 616 $ 639 $ 652 Interest on short- term borrowings 26 101 75 83 77 88 Interest on capital leases 1 2 3 3 2 2 Capitalized Interest - 1 1 - 2 46 AFUDC Debt 8 16 7 11 11 33 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 6 24 24 3 - - -------- -------- -------- -------- -------- -------- Total Fixed Charges $ 352 $ 629 $ 684 $ 716 $ 731 $ 821 -------- -------- -------- -------- -------- -------- Preferred Stock Dividends: Tax deductible dividends $ 5 $ 10 $ 10 $ 11 $ 5 $ 5 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 17 39 39 100 96 109 -------- -------- -------- -------- -------- -------- Total Preferred Stock Dividends $ 22 $ 49 $ 49 $ 111 $ 101 $ 114 -------- -------- -------- -------- -------- -------- Total Combined Fixed Charges and Preferred Stock Dividends $ 374 $ 678 $ 733 $ 827 $ 832 $ 935 ======== ======== ======== ======== ======== ======== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 2.71 2.96 2.72 3.57 3.09 2.94 - --------------------------------------------------------------------------------------------------- Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, interest of subordinated debentures held by trust, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax earnings which would be required to cover such dividend requirements.
EX-27 5
UT This schedule contains summary financial information extracted from PG&E Corporation and is qualified in its entirety by reference to such financial statements. 1,000,000 6-MOS DEC-31-1998 JAN-01-1998 JUN-30-1998 PER-BOOK 16,287 666 3,822 2,742 5,772 29,289 5,834 0 2,041 7,875 493 329 7,390 576 0 113 508 0 0 0 12,005 29,289 9,140 322 8,114 8,114 1,026 14 1,040 405 313 0 313 237 179 1,250 0.82 0.82
EX-27 6
UT This schedule contains summary financial information extracted from Pacific Gas and Electric Company and is qualified in its entirety by reference to such financial statements. 1 PACIFIC GAS AND ELECTRIC COMPANY 1,000,000 6-MOS DEC-31-1998 JAN-01-1998 JUN-30-1998 PER-BOOK 13,098 0 2,797 2,595 5,128 23,618 4,132 0 2,563 6,695 437 329 5,878 0 0 0 430 0 0 0 9,849 23,618 4,143 312 3,220 3,220 923 71 994 333 349 15 334 100 179 1,182 0.00 0.00
-----END PRIVACY-ENHANCED MESSAGE-----