PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1997
TABLE OF CONTENTS

                                                                  PAGE

PART I.  FINANCIAL INFORMATION

ITEM 1.  CONSOLIDATED FINANCIAL STATEMENTS

         PG&E CORPORATION
            STATEMENT OF CONSOLIDATED INCOME........................1
            BALANCE SHEET...........................................2
            STATEMENT OF CASH FLOWS ................................3
         PACIFIC GAS AND ELECTRIC COMPANY
            STATEMENT OF CONSOLIDATED INCOME........................4
            BALANCE SHEET...........................................5
            STATEMENT OF CASH FLOWS.................................6
         NOTE 1:  GENERAL...........................................7
         NOTE 2:  ELECTRIC INDUSTRY RESTRUCTURING...................9
         NOTE 3:  NATURAL GAS MATTERS..............................13
         NOTE 4:  PG&E OBLIGATED MANDATORILY REDEEMABLE
                  PREFERRED SECURITIES OF TRUST HOLDING
                  SOLELY PG&E SUBORDINATED DEBENTURES..............13
         NOTE 5:  COMMITMENTS AND CONTINGENCIES....................14

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS.......................16

         COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........17
         ELECTRIC INDUSTRY RESTRUCTURING...........................18
            Transition Cost Recovery...............................18
            Competitive Market Framework...........................21
            Accounting for the Effects of Regulation...............22
         GAS INDUSTRY RESTRUCTURING................................23
         ACQUISITIONS AND SALES....................................24
         RESULTS OF OPERATIONS.....................................26
            Common Stock Dividend..................................27
            Earnings Per Common Share..............................27
            Utility................................................27
            Other Lines of Business................................27
         LIQUIDITY AND CAPITAL RESOURCES
            Sources of Capital.....................................28
            Cost of Capital Application............................29
            Environmental Matters..................................29
            Legal Matters..........................................29

PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.........................................30
ITEM 5.  OTHER INFORMATION.........................................32
ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K..........................32

SIGNATURE..........................................................34



PART I. FINANCIAL INFORMATION


ITEM 1.  CONSOLIDATED FINANCIAL STATEMENTS


PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in thousands, except per share amounts) 
Three months ended June 30, Six months ended June 30, 1997 1996 1997 1996 ----------- ----------- ----------- ----------- Operating Revenues Electric and gas utility $ 2,278,764 $ 2,059,845 $ 4,552,742 $ 4,224,460 Energy trading 680,576 - 1,663,124 - Other 123,566 78,821 232,534 162,974 ----------- ------------ ------------ ----------- Total operating revenues 3,082,906 2,138,666 6,448,400 4,387,434 Operating Expenses Cost of electric energy 632,544 530,792 1,169,014 997,786 Cost of gas 761,685 67,151 1,967,040 255,288 Maintenance and other operating 571,243 525,058 1,019,723 981,532 Depreciation and decommissioning 465,687 303,382 924,803 606,329 Administrative and general 200,324 346,762 370,282 526,141 Property and other taxes 80,580 77,146 162,941 158,589 ----------- ----------- ----------- ----------- Total operating expenses 2,712,063 1,850,291 5,613,803 3,525,665 ----------- ----------- ----------- ----------- Operating Income 370,843 288,375 834,597 861,769 Interest income 12,190 21,348 25,154 45,691 Interest expense (164,255) (157,458) (322,195) (327,018) Other income 71,658 7,268 84,366 11,339 Preferred dividend requirement and redemption premium (8,278) (8,278) (16,556) (16,556) ----------- ----------- ----------- ----------- Pretax Income 282,158 151,255 605,366 575,225 Income Taxes 89,253 47,753 239,957 219,297 ----------- ----------- ----------- ----------- Earnings Available for Common Stock $ 192,905 $ 103,502 $ 365,409 $ 355,928 =========== =========== =========== =========== Weighted Average Common Shares Outstanding 397,677 415,125 403,072 414,738 Earnings Per Common Share $.49 $.25 $.91 $.86 Dividends Declared Per Common Share $.30 $.49 $.60 $.98 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION BALANCE SHEET (in thousands)
Balance at June 30, December 31, 1997 1996 ------------- ------------- ASSETS Plant in Service Electric $ 25,239,420 $ 24,757,479 Gas 6,765,301 6,558,413 Gas transmission 1,829,002 1,579,693 ------------- ------------- Total plant in service (at original cost) 33,833,723 32,895,585 Accumulated depreciation and decommissioning (15,233,682) (14,301,934) ------------- ------------- Net plant in service 18,600,041 18,593,651 Construction Work in Progress 478,447 414,229 Other Noncurrent Assets Nuclear decommissioning funds 940,061 882,929 Investment in nonregulated projects 773,115 817,259 Other assets 306,496 134,271 ------------ ------------ Total other noncurrent assets 2,019,672 1,834,459 Current Assets Cash and cash equivalents 207,188 143,402 Accounts receivable, net 1,170,130 1,151,844 Commodity contracts accounts receivable 355,974 387,342 Regulatory balancing accounts receivable 625,271 444,156 Inventories 513,130 530,085 Prepayments 67,483 54,116 ------------ ------------ Total current assets 2,939,176 2,710,945 Deferred Charges Income tax-related deferred charges 1,060,061 1,133,043 Other deferred charges 1,577,541 1,550,789 ------------ ------------ Total deferred charges 2,637,602 2,683,832 ------------ ------------ TOTAL ASSETS $ 26,674,938 $ 26,237,116 ============= ============= CAPITALIZATION AND LIABILITIES Capitalization Common stock equity $ 8,248,770 $ 8,363,301 Preferred stock without mandatory redemption provisions 390,591 402,056 Preferred stock with mandatory redemption provisions 137,500 137,500 Company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures 300,000 300,000 Long-term debt 7,661,892 7,770,067 ------------- ------------- Total capitalization 16,738,753 16,972,924 Current Liabilities Short-term borrowings 1,529,002 680,900 Current portion of long-term debt 26,716 209,867 Accounts payable Commodity contracts 372,744 388,369 Trade creditors 436,886 489,527 Other 387,180 361,258 Accrued taxes 425,224 310,271 Amounts due customers 150,465 186,899 Deferred income taxes 208,308 157,064 Interest payable 55,266 63,193 Dividends payable 128,264 123,310 Other 332,844 309,104 ------------- ------------- Total current liabilities 4,052,899 3,279,762 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 3,785,899 3,941,435 Deferred tax credits 360,277 379,563 Noncurrent balancing account liabilities 149,546 120,858 Other 1,587,564 1,542,574 ------------- ------------- Total deferred credits and other noncurrent liabilities 5,883,286 5,984,430 Commitments and Contingencies (Notes 2, 3, and 5) - - ------------- ------------- TOTAL CAPITALIZATION AND LIABILITIES $ 26,674,938 $ 26,237,116 ============= ============= The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION STATEMENT OF CASH FLOWS (in thousands)
For the six months ended June 30, 1997 1996 ----------- ----------- Cash Flows From Operating Activities Net income $ 365,409 $ 355,928 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and decommissioning 924,803 606,329 Amortization 60,383 44,774 Deferred income taxes and tax credits-net (105,997) (18,532) Other deferred charges (77,257) 56,185 Other noncurrent liabilities (48,233) 9,035 Noncurrent balancing account liabilities and other deferred credits 127,752 (42,224) Gain on sale of International Generating Company, Ltd. (110,000) - Net effect of changes in operating assets and liabilities: Accounts receivable 92,452 84,135 Regulatory balancing accounts receivable (41,341) 18,216 Inventories (2,669) 33,191 Accounts payable (128,508) (57,170) Accrued taxes 114,953 129,230 Other working capital (174,726) 119,581 Other-net 140,758 51,865 ----------- ----------- Net cash provided by operating activities 1,137,779 1,390,543 ----------- ----------- Cash Flows From Investing Activities Capital expenditures (769,916) (513,109) Investments in nonregulated projects (96,969) 11,596 Acquisition of Teco Pipeline Company (40,668) - Proceeds from sale of International Generating Company, Ltd. 137,088 - Other-net (32,115) (40,644) ----------- ----------- Net cash used by investing activities (802,580) (542,157) ----------- ----------- Cash Flows From Financing Activities Common stock issued 26,911 113,290 Common stock repurchased (574,862) (135,036) Long-term debt issued 50,006 983,944 Long-term debt matured, redeemed, or repurchased-net (344,521) (1,196,269) Short-term debt issued (redeemed)-net 848,102 (773,874) Dividends paid (261,634) (422,994) Other-net (15,415) (14,285) ----------- ----------- Net cash used by financing activities (271,413) (1,445,224) ----------- ----------- Net Change in Cash and Cash Equivalents 63,786 (596,838) Cash and Cash Equivalents at January 1 143,402 734,295 ----------- ----------- Cash and Cash Equivalents at June 30 $ 207,188 $ 137,457 =========== =========== Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 314,523 $ 306,442 Income taxes 237,245 106,119 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 thousands, except per share amounts)
Three months ended June 30, Six months ended June 30, 1997 1996 1997 1996 ------------ ------------ ------------ ------------ Operating Revenues Electric $ 1,876,388 $ 1,660,867 $ 3,598,394 $ 3,309,469 Gas 402,376 398,978 954,348 914,991 Other - 78,821 - 162,974 ------------ ------------ ------------ ------------ Total operating revenues 2,278,764 2,138,666 4,552,742 4,387,434 Operating Expenses Cost of electric energy 597,058 530,792 1,107,176 997,786 Cost of gas 61,681 67,151 276,136 255,288 Maintenance and other operating 560,642 525,058 1,005,849 981,532 Depreciation and decommissioning 447,954 303,382 890,479 606,329 Administrative and general 163,712 346,762 301,112 526,141 Property and other taxes 77,450 77,146 156,479 158,589 ------------ ------------ ------------ ------------ Total operating expenses 1,908,497 1,850,291 3,737,231 3,525,665 ------------- ------------ ------------ ------------ Operating Income 370,267 288,375 815,511 861,769 Interest income 11,113 21,348 21,517 45,691 Interest expense (146,791) (157,458) (290,833) (327,018) Other income 2,447 7,268 1,379 11,339 ------------ ------------ ------------ ------------ Pretax Income 237,036 159,533 547,574 591,781 Income Taxes 107,148 47,753 245,107 219,297 ------------ ------------ ------------ ------------ Net Income 129,888 111,780 302,467 372,484 Preferred dividend requirement and redemption premium (8,278) (8,278) (16,556) (16,556) ------------- ----------- ------------ ------------ Earnings Available for Common Stock $ 121,610 $ 103,502 $ 285,911 $ 355,928 ============ =========== ============ ============ The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY BALANCE SHEET (in thousands)
Balance at June 30, December 31, 1997 1996 ------------ ------------ ASSETS Plant in Service Electric $ 25,225,536 $ 24,757,479 Gas 6,753,293 8,138,106 ------------- ------------- Total plant in service (at original cost) 31,978,829 32,895,585 Accumulated depreciation and decommissioning (14,786,214) (14,301,934) ------------- ------------- Net plant in service 17,192,615 18,593,651 Construction Work in Progress 454,659 414,229 Other Noncurrent Assets Nuclear decommissioning funds 940,061 882,929 Investment in nonregulated projects - 817,259 Other assets 101,401 134,271 ------------- ------------ Total other noncurrent assets 1,041,462 1,834,459 Current Assets Cash and cash equivalents 70,098 143,402 Accounts receivable, net 1,080,683 1,151,844 Commodity contracts accounts receivable - 387,342 Regulatory balancing accounts receivable 625,271 444,156 Inventories 497,929 530,085 Prepayments 30,759 54,116 ------------- ------------ Total current assets 2,304,740 2,710,945 Deferred Charges Income tax-related deferred charges 1,034,355 1,133,043 Other deferred charges 1,503,589 1,550,789 ------------- ------------ Total deferred charges 2,537,944 2,683,832 ------------- ------------- TOTAL ASSETS $ 23,531,420 $ 26,237,116 ============= ============= CAPITALIZATION AND LIABILITIES Capitalization Common stock equity $ 7,101,171 $ 8,363,301 Preferred stock without mandatory redemption provisions 402,056 402,056 Preferred stock with mandatory redemption provisions 137,500 137,500 Company obligated mandatorily redeemable preferred securities of trust holding solely PG&E subordinated debentures 300,000 300,000 Long-term debt 6,984,006 7,770,067 ------------ ------------ Total capitalization 14,924,733 16,972,924 Current Liabilities Short-term borrowings 1,178,064 680,900 Current portion of long-term debt 23,645 209,867 Accounts payable Commodity contracts - 388,369 Trade creditors 395,769 489,527 Other 581,810 361,258 Accrued taxes 404,882 310,271 Amounts due customers 150,465 186,899 Deferred income taxes 208,308 157,064 Interest payable 49,467 63,193 Dividends payable 8,314 123,310 Other 292,623 309,104 ------------- ------------ Total current liabilities 3,293,347 3,279,762 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 3,346,743 3,941,435 Deferred tax credits 359,943 379,563 Noncurrent balancing account liabilities 149,546 120,858 Other 1,457,108 1,542,574 ------------ ------------ Total deferred credits and other noncurrent liabilities 5,313,340 5,984,430 Commitments and Contingencies (Notes 2, 3, and 5) - - ------------- ------------- TOTAL CAPITALIZATION AND LIABILITIES $ 23,531,420 $ 26,237,116 ============= ============= 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 thousands)
For the six months ended June 30, 1997 1996 ------------ ----------- Cash Flows From Operating Activities Net income $ 302,467 $ 372,484 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and decommissioning 890,479 606,329 Amortization 58,873 44,774 Deferred income taxes and tax credits-net (110,913) (18,532) Other deferred charges (66,769) 56,185 Other noncurrent liabilities (41,637) 9,035 Noncurrent balancing account liabilities and other deferred credits 133,678 (42,224) Net effect of changes in operating assets and liabilities: Accounts receivable 378 84,135 Regulatory balancing accounts receivable (41,341) 18,216 Inventories (673) 33,191 Accounts payable (154,765) (57,170) Accrued taxes 113,164 129,230 Other working capital (168,225) 119,581 Other-net 13,306 35,309 ------------ ------------ Net cash provided by operating activities 928,022 1,390,543 ------------ ------------ Cash Flows From Investing Activities Capital expenditures (742,848) (513,109) Investments in nonregulated projects - 11,596 Other-net (113,701) (40,644) ------------ ------------ Net cash used by investing activities (856,549) (542,157) ------------ ------------ Cash Flows From Financing Activities Long-term debt issued 43,506 983,944 Long-term debt matured, redeemed, or repurchased-net (315,882) (1,196,269) Short-term debt issued (redeemed)-net 497,164 (773,874) Dividends paid (361,489) (422,994) Other-net (8,076) (36,031) ----------- ----------- Net cash used by financing activities (144,777) (1,445,224) ----------- ----------- Net Change in Cash and Cash Equivalents (73,304) (596,838) Cash and Cash Equivalents at January 1 143,402 734,295 ----------- ----------- Cash and Cash Equivalents at June 30 $ 70,098 $ 137,457 =========== =========== Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 277,059 $ 306,442 Income taxes 242,748 106,119 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 Holding Company Formation: - ------------------------- Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a subsidiary of its new parent holding company, PG&E Corporation. PG&E's ownership interest in Pacific Gas Transmission Company (PGT) and PG&E Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's outstanding common stock was converted on a share-for-share basis into PG&E Corporation's outstanding common stock. PG&E's debt securities and preferred stock were unaffected and remain securities of PG&E. Basis of Presentation: - ---------------------- This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and PG&E. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation, PG&E, PG&E Gas Transmission Corporation including PGT, PG&E Energy Trading Corporation, PG&E Energy Services Corporation, and Enterprises, as well as the accounts of their wholly owned and controlled subsidiaries (collectively, the Corporation). PG&E's consolidated financial statements include the accounts of PG&E and its wholly owned and controlled subsidiaries. Because PGT and Enterprises were wholly owned and controlled subsidiaries of PG&E during 1996, they are included in PG&E's 1996 consolidated financial statements. The "Notes to Consolidated Financial Statements" herein pertain to the Corporation and PG&E. Currently, PG&E's financial position and results of operations are the principal factors affecting the Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with the Corporation's and PG&E's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1996 Annual Report on Form 10-K. In the opinion of management, the accompanying statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. Certain amounts in the prior year's consolidated financial statements have been reclassified to conform to the 1997 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. Accounting for Derivative Instruments (Derivatives): - ---------------------------------------------------- Effective June 30, 1997, the Corporation adopted Securities and Exchange Commission (SEC) amended Rule 4-08 of Regulation S-X, General Notes to the Financial Statements, which modifies the disclosure of accounting policies for certain derivative instruments. The Corporation engages in price risk management activities for both trading and non-trading purposes. The Corporation conducts trading activities through its gas and power marketing subsidiaries using a variety of financial instruments. These instruments include forward contracts involving the physical delivery of an energy commodity, swap agreements, futures, options, and other contractual arrangements. Additionally, the Corporation engages in non-trading activities using futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. Any gain or loss on derivatives used in hedging activities is deferred until the gain or loss on the hedged item is recognized. To qualify for hedge treatment, the underlying hedged item must expose the Corporation to risks associated with market fluctuations and the financial instrument used must be designated as a hedge and must reduce the Corporation's exposure to market fluctuations throughout the hedge period. If these criteria are not met, a change in the market value of the financial instrument is recognized as a gain or loss in the period of change. The cash flow resulting from a hedge is classified with the corresponding cash flow of the item being hedged. When there is an early termination of a financial instrument designated as a hedge, the gain or loss will continue to be deferred until the offsetting loss or gain is recognized on the underlying hedged item. Gains and losses associated with trading activities during year-to-date 1997 were immaterial. Acquisitions and Sales: - ---------------------- In December 1996, PGT acquired Energy Source (which was renamed PG&E Energy Trading Corporation) for approximately $23 million. On June 30, 1997, PGT distributed all of the shares of PG&E Energy Trading Corporation to PG&E Corporation. PG&E Energy Trading Corporation, PG&E Corporation's wholesale commodity marketing subsidiary, has averaged $277 million in revenues each month since January 1997. These revenues were primarily offset by a corresponding increase in the cost of gas. In January 1997, the Corporation acquired Teco Pipeline Company (renamed PG&E Gas Transmission Teco, Inc.) for approximately $380 million, consisting of $319 million of PG&E Corporation common stock and the purchase of a $61 million note. On April 2, 1997, Bechtel Enterprises, Inc. (Bechtel) acquired Enterprises' interest in International Generating Company, Ltd., a joint venture between Enterprises and Bechtel. The sale resulted in an after-tax gain of approximately $110 million, which was recorded in April 1997. On June 26, 1997, the Corporation announced its agreement to acquire Bechtel's interests in U.S. Generating Company (USGen), operations and maintenance affiliate U.S. Operating Services Company, and power marketing affiliate USGen Power Services, L.P., by redemption of Bechtel's interests in such partnerships. In addition, the Corporation has agreed to purchase Bechtel's interest in certain independent power projects currently owned by Bechtel and PG&E Corporation (through Enterprises) or by Bechtel, PG&E Corporation, and various third parties. USGen is a joint venture formed by PG&E and Bechtel in 1989 to develop, own, and manage independent power production facilities in North America. The purchase is expected to be completed by December 31, 1997. On July 31, 1997, the Corporation completed its acquisition of Valero Energy Corporation (Valero) (which was renamed PG&E Gas Transmission, Texas Corporation), including its natural gas and natural gas liquids business, but excluding its refining operations. The outstanding shares of Valero common stock were converted into PG&E Corporation common stock for a total issuance of approximately 31,000,000 shares. The purchase price of Valero was approximately $771 million, and approximately $800 million in long-term debt was assumed. The acquisition was accounted for as a purchase. On August 6, 1997, the Corporation announced that USGen (through a special purpose entity wholly owned by PG&E Corporation) had agreed to acquire a portfolio of non-nuclear electric generating assets and power supply contracts from the New England Electric System for approximately $1.59 billion, plus $85 million to cover early retirement and severance costs. Including fuel, other inventories, and transaction costs, financing requirements are expected to total approximately $1.75 billion. The assets to be acquired contain a mix of hydro, coal, oil, and gas generation and represent the second largest non-nuclear electric generation portfolio in New England, comprising approximately 17 percent of New England's total installed generating capacity. The acquisition of these assets, which is subject to approval of the Federal Energy Regulatory Commission and state regulators, among other conditions, is expected to be completed in 1998. NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING In 1995, the California Public Utilities Commission (CPUC) issued a decision that provides a plan to restructure California's electric utility industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called "transition costs." In 1996, California legislation (restructuring legislation) was passed that adopts the basic tenets of the CPUC's restructuring decision, including recovery of transition costs. In addition, the restructuring legislation provides a 10 percent electric rate reduction for residential and small commercial customers by January 1, 1998, freezes electric customer rates for all customers, and requires the accelerated recovery of transition costs associated with owned electric generation facilities. The restructuring legislation also establishes the operating framework for a competitive electric generation market. The rate freeze, mandated by the restructuring legislation, will continue until the earlier of March 31, 2002, or until PG&E has recovered its authorized transition costs (the transition period). To achieve the 10 percent rate reduction, the restructuring legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current weighted-average cost of capital. Once the bonds are issued, PG&E would collect a separate tariff on behalf of the bondholders to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs is expected to lower the amounts paid by these customers each year during the transition period, thereby achieving the 10 percent reduction in rates. In May 1997, PG&E filed an application with the CPUC for the issuance of an estimated $3.1 billion of these bonds by means of a special purpose entity. A CPUC decision is expected in September 1997. If the decision is approved, PG&E expects these bonds would be issued in the fourth quarter of 1997. During 1997, differences between authorized and actual base revenues (revenues to recover PG&E's non-energy costs and return on investment) and differences between the actual electric energy costs and the revenue designated for recovery of such costs are being recorded in balancing accounts. Any residual balance will be available to use for recovery of transition costs. PG&E expects this residual balance to be approximately $340 million at December 31, 1997. Amounts recorded in balancing accounts will be subject to a reasonableness review by the CPUC. Transition Cost Recovery: - ------------------------ The restructuring legislation authorizes the CPUC to determine the costs eligible for recovery as transition costs. The amount of costs will be based on, among other things, the aggregate of above-market and below- market values of utility-owned generation assets and obligations. Costs eligible for transition cost recovery include: (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and currently collected through rates) and future costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from Qualifying Facilities (QF) and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current period and allowed to be included in rates in subsequent periods.) PG&E cannot determine the exact amount of sunk costs that will be above market and recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each generation facility. This process will be completed during the transition period. In compliance with the CPUC's restructuring decision and the restructuring legislation, PG&E has filed numerous regulatory applications and proposals that detail its transition cost recovery plan. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of-service revenues for its electric operations into distribution, transmission, public purpose programs, and generation, (2) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period, and (3) accelerated recovery of transition costs. In applying its recovery plan to Diablo Canyon Nuclear Power Plant (Diablo Canyon), PG&E proposed: (1) recovery of certain ongoing costs and capital additions through a rate based upon Diablo Canyon generation, and (2) fixed recovery of PG&E's investment in Diablo Canyon by the end of 2001. In May 1997, the CPUC issued a decision on PG&E's proposal. The decision was effective January 1, 1997, and generally adopts the overall ratemaking structure proposed by PG&E. This ratemaking structure has caused a significant change in the way Diablo Canyon earns revenues from the previous performance-based ratemaking (PBR) mechanism as follows: 1. Diablo Canyon's sunk costs will be fully recovered during the transition period, at a reduced return on common equity equal to 90 percent of PG&E's embedded cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. Recovery of Diablo Canyon will be accelerated from a twenty-year period ending in 2016 to a five-year period ending in 2001. 2. Revenues for recovery of on-going operating costs and capital additions will be computed through a PBR mechanism. This mechanism establishes a rate per kilowatt-hour (kWh), generated by the facility, called the Incremental Cost Incentive Price (ICIP). Although the CPUC adopted PG&E's overall structure, as described below, the CPUC decision (1) substantially reduces the ICIP from the level proposed by PG&E, (2) excludes certain items from the sunk cost revenue requirement, and (3) imposes a disallowance of about $70 million. In addition, the decision fails to clarify Diablo Canyon's "must take" status during the transition period although language supporting must take status is contained within the CPUC's 1995 restructuring decision. Without must take status, Diablo Canyon generation during the transition period may be significantly reduced, which would reduce recovery of ICIP related costs. The following table summarizes the authorized revenues and ICIP per this decision: 1997 1998 1999 2000 2001 - ---------------------------------------------------------------------------- ICIP (cents per kWh) 3.26 3.31 3.37 3.43 3.49 Estimated Total Authorized Revenues ($ in millions) Sunk Cost Recovery $1,385 $1,322 $1,259 $1,197 $1,135 ICIP Revenues 515 523 532 542 552 - ---------------------------------------------------------------------------- Total Authorized Revenues $1,900 $1,845 $1,791 $1,739 $1,687 The CPUC decision adopts a fixed forecast of ICIP rates for 1997 through 2001, which is substantially lower than those proposed by PG&E. The difference in prices results principally from different assumptions used in forecasts of Diablo Canyon capacity factors, operating and maintenance costs, and escalation factors. The prices in the CPUC decision are based on an assumed capacity factor of 83.6 percent and an escalation factor of 1.5 percent. Further, the CPUC decision finds that PG&E's proposed modified Diablo Canyon ratemaking is a form of traditional ratemaking subject to a state statute requiring a prudence review of the plant's construction costs and requiring a disallowance of any such costs exceeding $50 million which result from an unreasonable construction error or omission. The decision then finds that PG&E admitted to an error in the design and construction of the plant of $100 million and accordingly adopts a prudence disallowance of approximately $70 million for the undepreciated portion of costs attributable to the error. This disallowance reduces the amount of revenues collected over the five year recovery period. However, this reduction in revenue does not result in an impairment. PG&E has requested that the CPUC rehear its decision and eliminate the sunk cost disallowances from the decision. A consumer group also has filed a rehearing request, asking the CPUC to order a full prudence hearing on all the Diablo Canyon sunk costs before permitting any of the costs to be recovered. PG&E expects the CPUC to act on the rehearing requests by the end of the year. Based upon the Diablo Canyon decision, the restructuring legislation, the CPUC's restructuring decision, and existing PG&E applications and proposals which would take effect in 1997, PG&E is depreciating Diablo Canyon over a five-year period ending in 2001. This five-year depreciation is consistent with PG&E's cost recovery plan which provides sunk cost revenues over the same period. The change in depreciable life increased Diablo Canyon's depreciation expense for the first six months of the year by $289 million, for an after-tax reduction to earnings per share of $.43. Under the restructuring legislation, most transition costs must be recovered by March 31, 2002. However, the restructuring legislation authorizes recovery of certain transition costs after that time. These costs include: (1) certain employee-related transition costs, (2) payments under existing QF and power purchase contracts, and (3) unrecovered implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. Excluding these exceptions, any transition costs not recovered during the transition period would be absorbed by PG&E. Nuclear decommissioning costs, which are not considered transition costs, will be recovered through a CPUC authorized charge. During the transition period, this charge will be incorporated into the frozen electric rates. PG&E's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the extent to which the regulatory framework established by the restructuring legislation will continue to be applied, (2) the amount of transition costs approved by the CPUC, (3) the market value of PG&E's generation plants, (4) future sales levels, (5) future fuel and operating costs, and (6) the market price of electricity. Given its current evaluation of these factors, PG&E believes it will recover its transition costs and that its utility-owned generation plants are not impaired. However, a change in one or more these factors could affect the probability of recovery of transition costs and result in a material loss. Accounting for the Effects of Regulation: - ---------------------------------------- PG&E accounts for the financial effect of regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows PG&E to record certain regulatory assets and liabilities which would be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires that regulatory assets be written off when they are no longer probable of recovery and that impairment losses be recorded for long-lived assets when related future cash flows are less than the carrying value of the assets. In applying the provisions of SFAS No. 71, PG&E has accumulated approximately $1.7 billion of regulatory assets attributable to electric generation at June 30, 1997. The net investments in Diablo Canyon and the other generation assets, including allocation of common plant, were $4.1 billion and $2.7 billion, respectively, at June 30, 1997. The net present value of above-market QF power purchase obligations is estimated to be $5.3 billion at January 1, 1998, at an assumed market price of $0.025 per kWh beginning in 1997 and escalating at 3.2 percent per year. PG&E believes that the restructuring legislation establishes a definitive transition to the market-based pricing for electric generation that includes recovery of the transition costs through a nonbypassable charge (the competition transition charge or CTC). At the conclusion of the transition period, PG&E believes it will be at risk to recover its generation costs through market-based revenues. As a result of California's electric industry restructuring and related legislation, in 1996 the staff of the SEC began discussions with PG&E and other California utilities regarding the appropriateness of the continued application of SFAS No. 71 for the generation portion of the electric utilities' businesses as of January 1, 1997. Because of the importance of this issue to the electric utility industry in the United States, the SEC referred the issue to the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB). In its meeting on July 24, 1997, the EITF reached a consensus on EITF Issue No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71" (EITF 97-4). The consensus will require PG&E 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. The discontinuation of application of SFAS No. 71 will not have a material effect on PG&E's financial statements because 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 are derived. Under the terms of PG&E's transition cost recovery plan, approved by the CPUC in 1996, PG&E's generation related regulatory assets and liabilities, including uncollected CTC, will be recovered through a CTC imposed on the distribution customers during the transition period. EITF 97-4 will become final upon approval of the minutes of the July 24 meeting, which is expected in August 1997. Given the current regulatory environment, PG&E's electric transmission business and most areas of the distribution business are expected to remain regulated and, as a result, PG&E will continue to apply the provisions of SFAS No. 71. However, in May 1997, the CPUC issued decisions that allow customers to choose their electricity provider beginning January 1, 1998. The decisions also allow the electricity provider to provide their customers with billing and metering services, and indicate that electricity providers may be allowed to provide other distribution services (such as customer inquiries and uncollectibles) in the future. Any discontinuation of SFAS No. 71 for these portions of PG&E's electric distribution business is not expected to have a material adverse impact on the Corporation's or PG&E's financial position or results of operations. NOTE 3: NATURAL GAS MATTERS On August 1, 1997, the CPUC unanimously adopted a final decision approving the Gas Accord Settlement (Accord), which was submitted in 1996 for CPUC approval. The Accord will restructure PG&E's gas services and its role in the gas market, establish gas transmission rates for the five-year period from implementation of the Accord (expected to be December 1, 1997) through December 2002, establish an incentive mechanism to measure the reasonableness of PG&E's purchases of gas for core customers, and resolve various gas regulatory issues. In addition, the final decision accepts the Accord's proposal to set rates for Line 401 (the California segment of the PG&E/PGT pipeline) based on total capital costs of $736 million. It also adopts a discounting rule, whereby whenever PG&E offers a rate discount Line 401, it must also offer the same discount on pipelines transporting Southwestern and in-state gas production. The final decision approves the Accord's proposal that PG&E forgo recovery of 100 percent and 50 percent of the Interstate Transition Cost Surcharge amounts allocated for collection from its residential and smaller commercial customers and industrial and larger commercial customers, respectively. Finally, the decision states that the CPUC's intention to implement the rates and other provisions of the Accord throughout the Accord period is subject to the CPUC's overreaching policy goals and the CPUC's decisions reached in the CPUC's natural gas industry strategic plan to produce a more competitive gas market. As of June 30, 1997, approximately $490 million had been reserved relating to these gas regulatory issues and capacity commitments. As a result, the Corporation believes that the decision will not have a material adverse impact on its or PG&E's financial position or results of operations. NOTE 4: PG&E OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY PG&E SUBORDINATED DEBENTURES PG&E, through its wholly owned subsidiary, PG&E Capital I (Trust), has outstanding 12 million shares of 7.90% cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to PG&E 371,135 shares of common securities with an aggregate liquidation value of approximately $9 million. The only assets of the Trust are deferrable interest subordinated debentures issued by PG&E with a face value of approximately $309 million, an interest rate of 7.90%, and a maturity date of 2025.
NOTE 5: COMMITMENTS AND CONTINGENCIES Nuclear Insurance: - ----------------- PG&E has insurance coverage for property damage and business interruption losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). Under these policies, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, PG&E may be subject to maximum assessments of $28 million (property damage) and $7 million (business interruption), in each case per policy period, in the event losses exceed the resources of NML or NEIL. PG&E has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $8.7 billion of coverage is provided by secondary financial protection which is mandated by federal legislation and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, PG&E may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: - ------------------------- PG&E may be required to pay for environmental remediation at sites where PG&E 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 PG&E for the storage or disposal of materials which may be determined to present a significant threat to human health or the environment because of an actual or potential release of hazardous substances. Under CERCLA, PG&E's financial responsibilities may include remediation of hazardous substances, even if PG&E did not deposit those substances on the site. PG&E records a liability when site assessments indicate remediation is probable and a range of reasonably likely cleanup costs can be estimated. PG&E reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. Unless there is a better estimate within this range of possible costs, PG&E records the lower end of this range. The cost of the hazardous substance remediation ultimately undertaken by PG&E is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning PG&E's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. PG&E had an accrued liability at June 30, 1997, of $221 million for hazardous waste remediation costs at those sites, including fossil-fuel power plants, where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $489 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which PG&E is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to PG&E, based upon a range of reasonably possible outcomes. Costs may be higher if PG&E is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. PG&E will seek recovery of prudently incurred hazardous substance remediation costs through ratemaking procedures approved by the CPUC. PG&E has recorded regulatory assets at June 30, 1997, of $152 million for recovery of these costs in future rates. Additionally, PG&E will seek recovery of costs from insurance carriers and from other third parties as appropriate. The Corporation believes the ultimate outcome of these matters will not have a material adverse impact on its or PG&E'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, 1997, PG&E's net investment was $700 million. This net investment is comprised of the pumped storage facility (including regulatory assets of $50 million), common plant, and dedicated transmission plant. As part of the 1996 General Rate Case decision in December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of Helms. In July 1996, PG&E submitted its study, which concluded that the continued operation of Helms is cost effective. PG&E recommended that the CPUC take no action and address Helms along with other generating plants in the context of electric industry restructuring. PG&E is currently unable to predict whether there will be a change in rate recovery resulting from the study. As with its other hydroelectric generating plants, PG&E expects to seek recovery of its net investment in Helms through either PBR or cost of service ratemaking and through transition cost recovery. The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or PG&E's financial position or results of operations. Legal Matters: - ------------- Cities Franchise Fees Litigation: In 1994, the City of Santa Cruz filed a class action suit in a California state superior court (Court) against PG&E on behalf of itself and 106 other cities in PG&E's service area. The complaint alleges that PG&E has underpaid electric franchise fees to the cities by calculating those fees at different rates from other cities not included in the complaint. In September 1995, the Court certified the class of 107 cities in this suit and approved the City of Santa Cruz as the class representative. In January and March 1996, the Court made two rulings against certain cities effectively eliminating a major portion of the suit. The Court's rulings do not resolve the suit completely. The cities appealed both rulings. The trial has been postponed pending the cities' appeal. Should the cities prevail on the issue of franchise fee calculation methodology, PG&E's annual systemwide city electric franchise fees could increase by approximately $16 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $147 million (exclusive of interest, estimated to be $44 million at June 30, 1997). If the Court's January and March 1996 rulings become final, PG&E's annual systemwide city electric franchise fees for the remaining class member cities not subject to the Court's rulings could increase by approximately $5 million and damages for alleged underpayments for the years 1987 to 1996 could be as much as $40 million (exclusive of interest, estimated to be $12 million at June 30, 1997). The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or PG&E's financial position or results of operations. Chromium Litigation: In 1994 through 1997, several civil complaints were filed against PG&E on behalf of approximately 3,000 individuals. The complaints seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of PG&E's gas compressor stations at Hinkley, Kettleman, and Topock. PG&E is responding to the complaints and asserting affirmative defenses. PG&E will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defenses including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or PG&E's financial position or results of operations. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The "Management's Discussion And Analysis Of Financial Condition And Results Of Operations" herein pertain to Pacific Gas and Electric Company (PG&E) and its new parent holding company, PG&E Corporation, of which PG&E became a subsidiary effective January 1, 1997. PG&E Corporation's consolidated financial statements include the accounts of the following, as well as the accounts of their wholly owned and controlled subsidiaries (collectively, the Corporation): - - PG&E Corporation - - PG&E - - PG&E Gas Transmission Corporation consisting of Pacific Gas Transmission Company (PGT) including its operations in Australia, and the pipeline and on-system marketing segments of PG&E Gas Transmission Teco, Inc. (formerly PG&E Gas Transmission, Texas Corporation) - - PG&E Energy Trading Corporation (formerly Energy Source), and the off- system marketing segment of PG&E Gas Transmission Teco, Inc. (formerly PG&E Gas Transmission, Texas Corporation) - - PG&E Energy Services Corporation (formerly Vantus Energy Corporation) - - PG&E Enterprises (Enterprises) It should be noted that the discussion and analysis of PG&E's financial condition and results of operations also apply to the Corporation since PG&E's financial condition and results of operations are currently the principal factors affecting the Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with the Corporation's and PG&E's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1996 Annual Report on Form 10-K. The following discussion of consolidated results of operations and financial condition contains forward-looking statements that involve risks and uncertainties. These forward-looking statements include discussion of the financial impacts of gas and electric industry restructuring. Words such as "estimates," "expects," "anticipates," "plans," "believes," and similar expressions also identify forward-looking statements involving risks and uncertainties. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas industries, the outcome of the regulatory proceedings related to that restructuring, PG&E's ability to collect revenues sufficient to recover transition costs in accordance with its cost recovery plan, the impact of the Corporation's recently announced or completed acquisitions, and the ability of the Corporation to successfully compete outside its traditional regulated markets. The ultimate impacts on future results of increased competition, the changing regulatory environment, and the Corporation's expansion into new businesses and markets are uncertain, but all are expected to fundamentally change how the Corporation conducts its business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by the Corporation and PG&E. COMPETITION AND CHANGING REGULATORY ENVIRONMENT: The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and to ensure that these services were provided at fair prices. Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Customers are asking for choice in their energy provider. Other companies are challenging the utilities' exclusive relationship with customers and are seeking to replace certain utility functions with their own. These pressures are causing a move from the existing regulatory framework to a framework under which competition would be allowed in certain segments of the gas and electric industries. For several years, PG&E has been working with its regulators to achieve an orderly transition to competition and to ensure that PG&E has an opportunity to recover investments made under the traditional regulatory policies. In addition, PG&E has proposed alternative forms of regulation for those services for which prices and terms will not be determined by competition. These alternative forms include performance-based ratemaking (PBR) and other incentive-based alternatives. Over the next five years, a significant portion of PG&E's business will be transformed from the current utility monopoly to a competitive operation. This change will impact PG&E's financial results and may result in greater earnings volatility. In addition, during the transition period, PG&E expects the return on Diablo Canyon Nuclear Power Plant (Diablo Canyon) and certain other generation assets to be significantly lower than historical levels. ELECTRIC INDUSTRY RESTRUCTURING: In 1995, the California Public Utilities Commission (CPUC) issued a decision that provides a plan to restructure California's electric utility industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called "transition costs." In 1996, California legislation (restructuring legislation) was passed that adopts the basic tenets of the CPUC's restructuring decision, including recovery of transition costs. In addition, the restructuring legislation provides a 10 percent electric rate reduction for residential and small commercial customers by January 1, 1998, freezes electric customer rates for all customers, and requires the accelerated recovery of transition costs associated with owned electric generation facilities. The restructuring legislation also establishes the operating framework for a competitive electric generation market. The rate freeze, mandated by the restructuring legislation, would continue until the earlier of March 31, 2002, or until PG&E has recovered its authorized transition costs (the transition period). To achieve the 10 percent rate reduction, the restructuring legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend beyond the transition period. Also, the interest cost of the bonds is expected to be lower than PG&E's current weighted-average cost of capital. Once the bonds are issued, PG&E would collect a separate tariff on behalf of the bondholders to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The combination of the longer maturity period and the reduced interest costs is expected to lower the amounts paid by these customers each year during the transition period, thereby achieving the 10 percent reduction in rates. During 1997, differences between authorized and actual base revenues (revenues to recover PG&E's non-energy costs and return on investment) and differences between the actual electric energy costs and the revenue designated for recovery of such costs are being recorded in balancing accounts. Any residual balance will be available to use for recovery of transition costs. PG&E expects this residual balance to be approximately $340 million at December 31, 1997. Amounts recorded in balancing accounts will be subject to a reasonableness review by the CPUC. The most significant factors contributing to the expected residual balance are the declining cost of power committed under certain purchased power contracts, the reduction in the Diablo Canyon price for power under the CPUC-approved settlement (see below), and the decline in uncollected electric balancing accounts. Transition Cost Recovery: - ------------------------ The restructuring legislation authorizes the CPUC to determine the costs eligible for recovery as transition costs. The amount of costs will be based on, among other things, the aggregate of above-market and below-market values of utility-owned generation assets and obligations. Costs eligible for transition cost recovery include: (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and currently collected through rates) and future costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from Qualifying Facilities (QF) and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current period and allowed to be included in rates in subsequent periods.) PG&E cannot determine the exact amount of sunk costs that will be above market and recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each generation facility. This process will be completed during the transition period. In compliance with the CPUC's restructuring decision and the restructuring legislation, PG&E has filed numerous regulatory applications and proposals that detail its transition cost recovery plan. PG&E's recovery plan includes: (1) separation or unbundling of its previously approved cost-of-service revenues for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period, and (3) accelerated recovery of transition costs. The unbundling of PG&E's revenue requirement would enable it to separate revenue provided by frozen rates into transmission, distribution, PPPs, and generation. As proposed, revenues collected under frozen rates would be assigned to transmission, distribution, and PPPs based upon their respective cost of service. Revenue would also be provided for other costs, including nuclear decommissioning, rate-reduction-bond debt service, the on-going cost of generation, and transition cost recovery. In August 1997, the CPUC issued a decision on PG&E's proposed unbundling of its 1998 authorized electric revenues. The decision adopts PG&E's overall revenue allocation methodology with the following exceptions. The decision reallocates approximately $49 million of distribution revenue to the generation and transmission functions subject to adjustment after any divestiture of power plants, discussed below. In addition, the decision requires that the competition transition charge (CTC) imposed on the customers should be determined residually based upon a monthly class average power exchange (PX) price, rather than on an hour by hour price as originally proposed. Further, the decision rejects PG&E's proposal that the distribution authorized revenues should be determined by subtracting transmission revenues, approved by the Federal Energy Regulatory Commission (FERC), from the sum of the CPUC-approved transmission and distribution revenues. Instead, the distribution revenues, authorized by the CPUC, and the transmission revenues, authorized by the FERC, would be determined on a stand-alone basis. PG&E does not believe the decision will have a material impact on its ability to recover transition costs. Under PG&E's recovery plan, PG&E would receive a reduced return on common equity for certain transition costs related to generation facilities for which recovery is accelerated during the transition period. The lower return reflects the reduced risk associated with the shorter amortization period and increased certainty of recovery. The Office of Ratepayers Advocates (ORA) of the CPUC has filed a motion requesting that the reduced rate of return be applied to all generation-related assets in 1997, prior to the transition period. The ORA believes that this reduced rate of return reflects PG&E's reduced risk resulting from the CPUC's authorization of PG&E's cost recovery plan. In July 1997, the CPUC ordered the utilities to establish memorandum accounts to track the differences between the authorized rate of return and the reduced rate of return, pending a final CPUC decision on the issue. In applying its recovery plan to Diablo Canyon, PG&E proposed: (1) recovery of certain ongoing costs and capital additions through a rate based upon Diablo Canyon generation, and (2) fixed recovery of PG&E's investment in Diablo Canyon by the end of 2001. In May 1997, the CPUC issued a decision on PG&E's proposal. The decision was effective January 1, 1997, and generally adopts the overall ratemaking structure proposed by PG&E. This ratemaking structure has caused a significant change in the way Diablo Canyon earns revenues from the previous PBR mechanism as follows: 1. Diablo Canyon's sunk costs will be fully recovered during the transition period at a reduced return on common equity equal to 90 percent of PG&E's embedded cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996. Recovery of Diablo Canyon will be accelerated from a twenty-year period ending in 2016 to a five-year period ending in 2001. 2. Revenues for recovery of on-going operating costs and capital additions will be computed through a PBR mechanism. This mechanism establishes a rate per kilowatt-hour (kWh), generated by the facility, called the Incremental Cost Incentive Price (ICIP). Although the CPUC adopted PG&E's overall structure, as described below, the CPUC decision (1) substantially reduces the ICIP from the level proposed by PG&E, (2) excludes certain items from the sunk cost revenue requirement, and (3) imposes a disallowance of about $70 million. In addition, the decision fails to clarify Diablo Canyon's "must take" status during the transition period although language supporting must take status is contained within the CPUC's 1995 restructuring decision. Without must take status, Diablo Canyon generation during the transition period may be significantly reduced, which would reduce recovery of ICIP related costs. The following table summarizes the authorized revenues and ICIP prices per this decision: 1997 1998 1999 2000 2001 - ---------------------------------------------------------------------------- ICIP (cents per kWh) 3.26 3.31 3.37 3.43 3.49 Estimated Total Authorized Revenues ($ in millions) Sunk Cost Recovery $1,385 $1,322 $1,259 $1,197 $1,135 ICIP Revenues 515 523 532 542 552 - ---------------------------------------------------------------------------- Total Authorized Revenues $1,900 $1,845 $1,791 $1,739 $1,687 The CPUC decision adopts a fixed forecast of ICIP rates for 1997 through 2001, which is substantially lower than those proposed by PG&E. The difference in prices results principally from different assumptions used in forecasts of Diablo Canyon capacity factors, operating and maintenance costs, and escalation factors. The prices in the CPUC decision are based on an assumed capacity factor of 83.6 percent and an escalation factor of 1.5 percent. Further, the CPUC decision finds that PG&E's proposed modified Diablo Canyon ratemaking is a form of traditional ratemaking subject to a state statute requiring a prudence review of the plant's construction costs and requiring a disallowance of any such costs exceeding $50 million which result from an unreasonable construction error or omission. The decision then finds that PG&E admitted to an error in the design and construction of the plant of $100 million and accordingly adopts a prudence disallowance of approximately $70 million for the undepreciated portion of costs attributable to the error. This disallowance reduces the amount of revenues collected over the five year recovery period. However, this reduction in revenue does not result in an impairment. PG&E has requested that the CPUC rehear its decision and eliminate the sunk cost disallowances from the decision. A consumer group also has filed a rehearing request, asking the CPUC to order a full prudence hearing on all the Diablo Canyon sunk costs before permitting any of the costs to be recovered. PG&E expects the CPUC to act on the rehearing requests by the end of the year. Based upon the Diablo Canyon decision, the restructuring legislation, the CPUC's restructuring decision, and existing PG&E applications and proposals which would take effect in 1997, PG&E is depreciating Diablo Canyon over a five-year period ending in 2001. This five-year depreciation is consistent with PG&E's cost recovery plan which would provide sunk cost revenues over the same period. The change in depreciable life increased Diablo Canyon's depreciation expense for the first six months of the year by $289 million, for an after-tax reduction to earnings per share of $.43. Under the restructuring legislation, most transition costs must be recovered by March 31, 2002. However, the restructuring legislation authorizes recovery of certain transition costs after that time. These costs include: (1) certain employee-related transition costs, (2) payments under existing QF and power purchase contracts, and (3) unrecovered implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. Excluding these exceptions, any transition costs not recovered during the transition period would be absorbed by PG&E. Nuclear decommissioning costs, which are not considered transition costs, will be recovered through a CPUC authorized charge. During the transition period, this charge will be incorporated into the frozen electric rates. PG&E's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the extent to which the regulatory framework established by the restructuring legislation will continue to be applied, (2) the amount of transition costs approved by the CPUC, (3) the market value of PG&E's generation plants, (4) future sales levels, (5) future fuel and operating costs, and (6) the market price of electricity. Given its current evaluation of these factors, PG&E believes it will recover its transition costs and that its utility-owned generation plants are not impaired. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material loss. Competitive Market Framework: - ---------------------------- In addition to transition cost recovery, the restructuring legislation establishes the operating framework for the competitive generation market in California. This framework will consist of a PX and an independent system operator (ISO). The PX, open to all electricity providers, will conduct a competitive auction to establish the price of electricity. The ISO is expected to ensure transmission system reliability and provide all electricity generators with open and comparable access to transmission services. Although the PX will be available to all customers through their local utility, the restructuring legislation allows customers to purchase electricity directly from electricity providers. These customers are referred to as direct access customers. In May 1997, the CPUC issued two decisions related to direct access: the direct access decision and the revenue cycle services decision. Under the direct access decision, beginning January 1, 1998, all electric customers may choose their electricity provider. Customers may choose to purchase their electricity (1) from the PX through PG&E, (2) from retail electricity providers (for example, marketers, brokers, and aggregators), or (3) directly from power generators. Regardless of the customer's choice, PG&E will continue to provide electric transmission and distribution services to all customers within its service territory. During the transition period, all customers will be billed for electricity used, for transmission and distribution services, for PPPs, and for recovery of transition costs through the nonbypassable CTC. As a result, during the transition period, the overall electric rates of direct access customers would vary from customers who choose PG&E bundled services primarily to the extent that their direct access electricity price differs from the PX price. Because the CTC is nonbypassable (customers will pay the CTC regardless of whether they select direct access or not), PG&E does not believe that direct access will have a material impact on PG&E's ability to recover transition costs. The revenue cycle services decision allows electricity providers to choose the method of billing their customers and to choose whether to provide their customers with metering. As related to the billing of direct access customers, the customer's electricity provider can choose one of the following three billing options: (1) the electricity provider could bill the customer for the electricity provided and PG&E would separately bill the customer for transmission and distribution services, including CTC and PPP costs; (2) PG&E could provide the customer with one consolidated bill for transmission and distribution services, including CTC and PPP costs, and for the electricity supplied by the electricity provider; or (3) the electricity provider could provide the customer with one consolidated bill for the electricity provided and for transmission and distribution services, including CTC and PPP costs, provided by PG&E. Further, beginning in 1998, electricity providers may choose to provide metering services to their large electricity customers (customers with electricity demand of 20 kilowatts or more). And, beginning in 1999, these providers may choose to provide metering services to all of their customers regardless of size. The revenue cycle decision requires PG&E to separately identify cost savings that would result when billing, metering, and related services within PG&E's service territory are provided by another entity. Once these cost savings, or credits, are approved by the CPUC and the customer's energy supplier is providing billing and metering services, the PG&E portion of the customer's bill would be reduced by the savings and the electricity provider would charge for these services. To the extent that these credits equate to PG&E's actual cost savings from reduced billing, metering, and related services, PG&E does not expect a material adverse impact on its or PG&E Corporation's financial positions or results of operations. Accounting for the Effects of Regulation: - ---------------------------------------- PG&E accounts for the financial effects of regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows PG&E to record certain regulatory assets and liabilities which would be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," requires that regulatory assets be written off when they are no longer probable of recovery and that impairment losses be recorded for long-lived assets when related future cash flows are less than the carrying value of the assets. In applying the provisions of SFAS No. 71, PG&E has accumulated approximately $1.7 billion of regulatory assets attributable to electric generation at June 30, 1997. The net investments in Diablo Canyon and the other generation assets, including allocations of common plant, were $4.1 billion and $2.7 billion, respectively, at June 30, 1997. The net present value of above-market QF power purchase obligations is estimated to be $5.3 billion at January 1, 1998, at an assumed market price of $0.025 per kWh beginning in 1997 and escalating at 3.2 percent per year. PG&E believes that the restructuring legislation establishes a definitive transition to the market-based pricing for electric generation that includes recovery of the transition costs through a nonbypassable charge (the competition transition charge or CTC). At the conclusion of the transition period, PG&E believes it will be at risk to recover its generation costs through market-based revenues. As a result of California's electric industry restructuring and related legislation, in 1996 the staff of the Securities and Exchange Commission (SEC) began discussions with PG&E and other California utilities regarding the appropriateness of the continued application of SFAS No. 71 for the generation portion of the electric utilities' businesses as of January 1, 1997. Because of the importance of this issue to the electric utility industry in the United States, the SEC referred the issue to the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB). In its meeting on July 24, 1997, the EITF reached a consensus on EITF Issue No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71" (EITF 97-4). The consensus will require PG&E 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. The discontinuation of application of SFAS No. 71 will not have a material effect on PG&E's financial statements because 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 are derived. Under the terms of PG&E's transition cost recovery plan, approved by the CPUC in 1996, PG&E's generation related regulatory assets and liabilities, including uncollected CTC, will be recovered through a CTC imposed on the distribution customers during the transition period. EITF 97-4 will become final upon approval of the minutes of the July 24 meeting, which is expected in August 1997. Given the current regulatory environment, PG&E's electric transmission business and most areas of the distribution business are expected to remain regulated and, as a result, PG&E will continue to apply the provisions of SFAS No. 71. However, the CPUC's revenue cycle decision discussed above allows electricity providers to provide their customers with billing and metering services, and indicates that electricity providers may be allowed to provide other distribution services (such as customer inquiries and uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these portions of PG&E's electric distribution business is not expected to have a material adverse impact on the Corporation's or PG&E's financial position or results of operations. GAS INDUSTRY RESTRUCTURING: On August 1, 1997, the CPUC unanimously adopted a final decision approving the Gas Accord Settlement (Accord), which was submitted in 1996 for CPUC approval. The Accord establishes California as a national leader in the move toward restructuring gas distribution services and making them more competitive. The Accord is a collaborative settlement by PG&E and more than 25 gas industry participants and government regulatory agencies. The Accord will increase the opportunity for residential customers to choose the gas supplier of their choice, change the pricing and regulatory structure for transporting natural gas within California, establish an incentive mechanism to set the standard of reasonableness for PG&E's core gas purchases, and offer more transportation services and choices to natural gas customers. The Accord will also resolve numerous major regulatory gas proceedings in which PG&E and many other parties are involved. Specific provisions of the decision include the following: - The decision affirms the CPUC's 1994 finding that the decision to construct Line 401 (the California segment of the PG&E/PGT pipeline that extends from the Canadian border to Kern River Station in Southern California) was reasonable based on PG&E's management's knowledge at the time. The decision accepts the Accord's proposal to set rates for Line 401 based on total capital costs of $736 million. - The decision approves the Rule 1 settlement that PG&E reached with the CPUC Consumer Services Division on July 1, 1997. The issue related to whether or not PG&E had misled the CPUC in violation of Rule 1, the CPUC's Code of Ethics, in connection with responding to certain discovery requests in the CPUC proceeding to determine whether the decision to construct Line 401 was reasonable. - The decision adopts a discounting rule. Under this discounting rule, whenever PG&E offers a rate discount on its in-state pipeline (Line 401) that accesses Canadian suppliers, it must also offer the same discount on pipelines transporting Southwestern and in-state gas production. - The decision approves the core procurement incentive mechanisms (CPIM) proposed in the Accord to replace the traditional reasonableness review proceedings of PG&E's gas procurement costs for the period 1994 through 2002. - The decision approves the Accord's proposal that PG&E forgo recovery of 100 percent and 50 percent of the Interstate Transition Cost Surcharge (ITCS) amounts allocated for collection from its residential and smaller commercial (core) and industrial and larger commercial (noncore) customers, respectively. (ITCS costs are the difference between fixed demand charges PG&E pays under gas transportation contracts with interstate pipeline companies for the reservation of interstate pipeline capacity that PG&E no longer uses to serve noncore customers and the revenues PG&E obtains from brokering that capacity.) - Finally, the decision states that the CPUC's intention to implement the rates and other provisions of the Accord throughout the Accord period is subject to the CPUC's overreaching policy goals and the CPUC's decisions reached in the CPUC's natural gas industry strategic plan to produce a more competitive gas market. As of June 30, 1997, approximately $490 million had been reserved relating to these gas regulatory issues and capacity commitments. As result, the Corporation believes that the decision will not have a material adverse impact on its or PG&E's financial position or results of operations. ACQUISITIONS AND SALES: On April 2, 1997, Bechtel Enterprises, Inc. (Bechtel) acquired Enterprises' interest in International Generating Company, Ltd. (InterGen), a joint venture between Enterprises and Bechtel. The sale resulted in an after-tax gain of approximately $110 million, which was recorded in the second quarter of 1997. On June 26, 1997, the Corporation announced its agreement to acquire Bechtel's interests in U.S. Generating Company (USGen), operations and maintenance affiliate U.S. Operating Services Company, and power marketing affiliate USGen Power Services, L.P., by redemption of Bechtel's interests in such partnerships. In addition, the Corporation has agreed to purchase Bechtel's interest in certain independent power projects currently owned by Bechtel and PG&E Corporation (through Enterprises) or by Bechtel, PG&E Corporation, and various third parties. USGen is a joint venture formed by PG&E and Bechtel in 1989 to develop, own, and manage independent power production facilities in North America. The purchase is expected to be completed by December 31, 1997. In October 1996, PG&E announced it would sell four of its California fossil-fueled power plants. The combined net book value of these plants is approximately $380 million. These plants generate approximately 10 percent of PG&E's total electric sales. PG&E's proposal for the sale of these plants is currently under consideration by the CPUC. In June 1997, PG&E announced its plans, subject to CPUC approval, to sell an additional three of its California fossil-fueled power plants and its geothermal power plant. The four additional plants identified for sale by PG&E generate approximately eight percent of PG&E's total electric sales. The combined net book value for the four plants is approximately $660 million. PG&E intends to file its plan for the sale of these power plants with the CPUC later this year and will seek to sign sales agreements with buyers by the end of 1998. PG&E has proposed that any loss incurred on the sale of the eight plants would be recovered as a transition cost. Likewise, any gain on the sale would offset other transition costs. Accordingly, PG&E does not expect any adverse impact on its results of operations from the sale of these plants. On July 31, 1997, the Corporation completed its acquisition of Valero Energy Corporation (Valero) (which was renamed PG&E Gas Transmission, Texas Corporation), including its natural gas and natural gas liquids business, but excluding its refining operations. The outstanding shares of Valero common stock were converted into PG&E Corporation common stock for a total issuance of approximately 31,000,000 shares. The purchase price of Valero was approximately $771 million, and approximately $800 million in long-term debt was assumed. The acquisition was accounted for as a purchase. On August 6, 1997, the Corporation announced that USGen (through a special purpose entity wholly owned by PG&E Corporation) had agreed to acquire a portfolio of non-nuclear electric generating assets and power supply contracts from the New England Electric System for approximately $1.59 billion, plus $85 million to cover early retirement and severance costs. Including fuel, other inventories, and transaction costs, financing requirements are expected to total approximately $1.75 billion. The assets to be acquired contain a mix of hydro, coal, oil, and gas generation and represent the second largest non-nuclear electric generation portfolio in New England, comprising approximately 17 percent of New England's total installed generating capacity. The acquisition of these assets, which is subject to approval of the FERC and state regulators, among other conditions, is expected to be completed in 1998. RESULTS OF OPERATIONS: The Corporation's results of operations were derived primarily from five business lines: Utility (consisting of PG&E, including Diablo Canyon), PG&E Gas Transmission Corporation including PGT, PG&E Energy Trading Corporation, PG&E Energy Services Corporation, and Enterprises including its interest in USGen. The results of operations for the parent company, PG&E Corporation, alone are not material for separate disclosure as a business line and have been allocated among the business lines based primarily on their percentage of operating revenues. The results of operations for all business lines other than Utility are not material for separate disclosure and have been shown as Other in the table below. The results of operations for the three- and six- months ended June 30, 1997 and 1996, and total assets at June 30, 1997 and 1996, are reflected in the following table and discussed below: PG&E Corporation (in millions, except per share amounts)
Utility Other Total --------- ------- ------- For the three months ended June 30, 1997 Operating revenues $ 2,279 $ 804 $ 3,083 Operating expenses 1,910 802 2,712 -------- -------- -------- Operating income before income taxes 369 2 371 Net income 121 72 193 Earnings per common share 0.30 0.19 0.49 June 30, 1996 Operating revenues 2,060 79 2,139 Operating expenses 1,792 58 1,850 -------- -------- -------- Operating income before income taxes 268 21 289 Net income 90 13 103 Earnings per common share 0.22 0.03 0.25 For the six months ended June 30, 1997 Operating revenues $ 4,553 $ 1,896 $ 6,449 Operating expenses 3,741 1,873 5,614 -------- -------- -------- Operating income before income taxes 812 23 835 Net income 284 81 365 Earnings per common share 0.71 0.20 0.91 Total assets at June 30 $ 23,531 $ 3,144 $ 26,675 June 30, 1996 Operating revenues 4,224 163 4,387 Operating expenses 3,422 103 3,525 -------- -------- ------- Operating income before income taxes 802 60 862 Net income 321 35 356 Earnings per common share 0.78 0.08 0.86 Total assets at June 30 $ 23,807 $ 1,951 $ 25,758
Common Stock Dividend: - --------------------- PG&E Corporation's common stock dividend is based on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. PG&E Corporation's current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. PG&E Corporation has identified a dividend payout ratio objective (dividends declared divided by earnings available for common stock) of between 50 and 65 percent (based on earnings exclusive of nonrecurring adjustments). PG&E's formation of a holding company was approved by the CPUC subject to a number of conditions, including the requirement that, on average, PG&E must maintain its CPUC-authorized capital structure. In the event that PG&E fails to maintain, on average, the CPUC-authorized capital structure, PG&E's ability to pay dividends to PG&E Corporation may be limited. However, if an adverse financial event reduces PG&E's equity ratio by one percent or more, the CPUC requires PG&E to request a waiver of this average capital structure requirement. PG&E shall not be considered in violation of this requirement by the CPUC during the period the waiver is pending resolution. Earnings Per Common Share: - ------------------------- Earnings per common share for the three- and six-month periods ended June 30, 1997, increased as compared to the same periods in 1996. This increase is due to a reduction in the number of common shares outstanding and the activity discussed below. Utility: - -------- Utility operating revenues increased for the three- and six-months ended June 30, 1997, as compared with the same periods in 1996. This increase is due to the revisions to the Diablo Canyon ratemaking structure discussed in Electric Industry Restructuring above. These revisions resulted in fixed sunk cost revenue recovery during the current scheduled outage, while no revenue recovery was provided during the previous scheduled outage. There was also an increase in energy cost revenues to recover energy cost increases in both natural gas prices and sales volume. Under energy cost recovery mechanisms, energy cost revenues generally equal energy cost expense and, thus, energy cost increases do not affect operating income. Utility operating expenses increased overall due to an increase in Diablo Canyon depreciation associated with the new Diablo Canyon ratemaking structure. In comparison to the second quarter 1996, these increases were offset by a decrease in administrative and general expenses due to a litigation reserve which was recorded in the second quarter of 1996. Other Lines of Business: - ------------------------ Other lines of business operating revenues for the three- and six-months ended June 30, 1997, as compared with the same periods in 1996 increased primarily due to the acquisitions of Energy Source (now known as PG&E Energy Trading Corporation) in December 1996 and Teco Pipeline Company (now known as PG&E Gas Transmission Teco, Inc.) in January 1997. Revenues and expenses associated with these acquisitions are approximately $284 million per month. Other lines of business other income and expense increased primarily due to a gain on the sale of Enterprises' interest in InterGen of approximately $110 million, which was offset by write-offs of nonregulated investments of approximately $41 million. LIQUIDITY AND CAPITAL RESOURCES: Sources of Capital: - ------------------ The Corporation's capital requirements are funded from cash provided by operations and, to the extent necessary, external financing. The Corporation's policy is to finance its assets with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to PG&E, complies with regulatory guidelines. Based on cash provided from operations and its capital requirements, the Corporation may repurchase equity and long-term debt in order to manage the overall balance of its capital structure. In June 1997, PG&E entered into a $500 million temporary credit facility which will be used to meet PG&E's cash needs until the placement of the rate reduction bonds, which are described below. In August 1997, PG&E Corporation entered into a $500 million temporary credit facility for general corporate purposes. Both of these credit facilities will expire 364 days from the date they were established. The Corporation's short-term borrowings increased $848 million during the six-month period ended June 30, 1997. During the six-month period ended June 30, 1997, PG&E Corporation issued $344 million of common stock. Of this common stock, $319 million was issued in connection with the acquisition of Teco Pipeline Company and its subsidiaries. The remaining $25 million was issued through the Dividend Reinvestment Plan and the Stock Option Plan. Also during the six-month period ended June 30, 1997, PG&E Corporation repurchased $575 million of its common stock on the open market. Long-term debt matured, redeemed, or repurchased during the six-months ended June 30, 1997, amounted to $345 million. Of this amount, $58 million related to PG&E's redemption of its 12% Eurobond debentures, $167 million related to PG&E's repurchase of its mortgage bonds, and $45 million related to PG&E's refinancing of its fixed-rate pollution control bonds with variable rate debt. The remaining $75 million related to the maturity of long-term debt. As discussed above in "Electric Industry Restructuring," to achieve the 10 percent rate reduction for residential and small commercial customers, the electric industry restructuring legislation authorizes utilities to finance a portion of their transition costs with "rate reduction bonds." In May 1997, PG&E filed an application with the CPUC for the issuance of an estimated $3.1 billion of these bonds by means of a special purpose entity. In August 1997, the CPUC issued a proposed decision (PD) which would authorize PG&E to issue the bonds substantially as proposed. A final decision is expected in September 1997. If the PD is issued as drafted, PG&E expects these bonds would be issued in the fourth quarter of 1997. The special purpose entity will acquire from PG&E the right to be paid the revenues from a separate tariff to recover principal, interest, and issuance costs over the life of the bonds from residential and small commercial customers. The bonds will be secured by the future revenue from the separate tariff and not by PG&E's assets. However, in accordance with a SEC ruling, once issued, the bonds would be reflected on PG&E's balance sheet. Cost of Capital Application: - --------------------------- In May 1997, PG&E filed an application with the CPUC requesting the following cost of capital for 1998: Capital Weighted Ratio Cost/Return Cost/Return -------- ------------ ----------- Long-term debt 46.20% 7.37% 3.40% Preferred stock 5.80 6.65 0.39 Common equity 48.00 12.25 5.88 ----------- Total return on average utility rate base 9.67% =========== The proposed cost of common equity is 0.65 percentage points higher than the 11.6 percent adopted for 1997. This increase reflects the level of business and regulatory risks PG&E now faces. If adopted, the proposed cost of capital would increase PG&E's 1998 gas revenue requirement by $13 million. Consistent with the electric rate freeze, PG&E's proposed cost of capital would not change electric rates. Environmental Matters: - --------------------- PG&E assesses, on an ongoing basis, compliance with laws and regulations related to hazardous substance remediation. At June 30, 1997, PG&E had an accrued liability of $221 million for remediation costs at sites, including fossil-fuel power plants, where such costs are probable and quantifiable. The costs at identified sites may be as much as $489 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or identifiable possible outcomes change. PG&E will seek recovery of prudently incurred compliance costs through ratemaking procedures approved by the CPUC. PG&E had recorded regulatory assets at June 30, 1997, of $152 million for recovery of these costs in future rates. Additionally, PG&E will seek recovery of costs from insurance carriers and from other third parties. (See Note 5 of Notes to Consolidated Financial Statements.) Legal Matters: - -------------- In the normal course of business, both PG&E and the Corporation are named as parties in a number of claims and lawsuits. Substantially all of these have been litigated or settled with no material adverse impact on PG&E's or the Corporation's results of operations or financial position. See Note 5 to the Consolidated Financial Statements for further discussion of significant pending legal matters. PART II. OTHER INFORMATION --------------------------- Item 1. Legal Proceedings ----------------- A. Antitrust Litigation As previously reported in PG&E Corporation's (the Corporation) and Pacific Gas and Electric Company's (PG&E) Annual Report on Form 10-K for the year ended December 31, 1996, in December 1993, the County of Stanislaus and a residential customer of PG&E filed a class action lawsuit in United States District Court, Eastern District of California against PG&E and Pacific Gas Transmission Company (PGT) relating to PGT's Canadian gas purchases. On December 18, 1995, the District Court dismissed the plaintiffs' amended complaint with prejudice. The plaintiffs appealed the District Court's dismissal of their complaint to the Ninth Circuit Court of Appeals. On May 29, 1997, the Ninth Circuit Court of Appeals affirmed the District Court's dismissal of the plaintiffs' complaint. The plaintiffs subsequently filed a motion for reconsideration of the appellate decision. On July 15, 1997, the Ninth Circuit Court of Appeals denied the plaintiffs' motion for reconsideration. The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or PG&E's financial position or results of operation. B. Norcen Litigation On June 27, 1997, PGT and PG&E entered into an agreement with Norcen Energy Resources Limited (Norcen Energy) and Norcen Marketing Incorporated (Norcen Marketing) to settle the litigation filed against PGT and PG&E by Norcen Energy and Norcen Marketing in the United States District Court, Northern District of California, on March 17, 1994. As has been previously reported in PG&E Corporation's and PG&E's Annual Report on Form 10-K for the year ended December 31, 1996, Norcen Energy's and Norcen Marketing's complaint against PGT and PG&E alleged that PGT and PG&E wrongfully induced Norcen Energy and Norcen Marketing to enter into a 30-year contract with PGT for firm transportation service by concealing legal action taken by PG&E before the CPUC two days before Norcen Marketing's contract with PGT became binding. The complaint also alleged certain breaches of representations made to Norcen Marketing and various federal and state antitrust, contractual and other claims, and sought rescission, restitution and recovery of unspecified damages. The settlement of this matter will not have a material adverse impact on the Corporation's or PG&E's financial position or results of operation. C. California Attorney General Investigation and Diablo Canyon Environmental Litigation As previously reported in PG&E Corporation's and PG&E's Annual Report on Form 10-K for the year ended December 31, 1996, in February 1995, the California Attorney General (AG) initiated an investigation to determine whether PG&E and its consultant, Tenera, Inc., (Tenera) violated the Federal Clean Water Act and the California Water Code in connection with a 1988 study (1988 Study) of the cooling water intake system at the Diablo Canyon Power Plant (Diablo Canyon). The United States Department of Justice (DOJ) later joined the AG's investigation. On May 2, 1997, PG&E, the AG, and the DOJ, entered into a settlement agreement, subject to court approval, to resolve this matter. On May 27, 1997, this settlement agreement was filed in United States District Court, Northern District of California, for approval. Further, as previously reported in PG&E Corporation's and PG&E's Annual Report on Form 10-K for the year ended December 31, 1996, the League for Coastal Protection (Coastal League) filed two lawsuits involving the 1988 study. The first lawsuit was filed in San Francisco County Superior Court in October 1995, against PG&E and its consultant, Tenera, and alleged violations of the California Business and Professions Code in connection with the 1988 Study. The Coastal League sought an unspecified amount of damages related to restitution or disgorgement of improper or excessive profits, punitive damages, injunctive relief and attorneys' fees. The Coastal League filed a second lawsuit in the United States District Court for the Northern District of California in April 1996, against PG&E and Tenera, alleging violations of the federal Clean Water Act in connection with the 1988 Study. The Coastal League sought a judgment that PG&E violated its discharge permit for Diablo Canyon, revocation of the permit, an order requiring restoration of the marine environment, an unspecified amount of civil penalties and recovery of its litigation and attorneys' fees. As previously reported in PG&E Corporation's and PG&E's Annual Report on Form 10-K for the year ended December 31, 1996), in April 1996, PG&E also received a copy of a complaint filed in a third case involving the 1988 Study. In this case, John W. Carter (Carter) alleged on behalf of himself and the United States and the State of California that PG&E, Tenera, and certain of their employees violated the federal and state False Claims Acts by filing an incomplete report in 1988 (i.e., the 1988 Study) and failing to correct it. The United States and the State of California declined to prosecute this action. The plaintiffs sought civil penalties, treble damages, a separate payment to Carter under the False Claims Acts and attorneys' fees. On May 2, 1997, PG&E also reached a settlement agreement with the Coastal League and Carter which is contingent on the district court's approval of the settlement agreement with the AG and the DOJ. Under the terms of the two settlement agreements, PG&E admits to no liability but will pay an aggregate of $15.6 million, plus interest, including $7.1 million for civil penalties, and $6.19 million for environmental projects. The settlement of these matters on the terms agreed to will not have a material adverse impact on the Corporation's or PG&E's financial position or results of operation. Item 5. Other Information {truncated for bandwidth} 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 13, 1997 By______________________________ CHRISTOPHER P. JOHNS Vice President and Controller (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company) -----END PRIVACY-ENHANCED MESSAGE-----