-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, C2VWqb5g+ILuybkANe6DIIFWU9+OX76cP6lW7EwMqmxDNXh8SiFIkWnDCxgY10QR 5pULNWCIeXsGUWbxPJ+8GA== 0000075488-96-000017.txt : 19960816 0000075488-96-000017.hdr.sgml : 19960816 ACCESSION NUMBER: 0000075488-96-000017 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19960630 FILED AS OF DATE: 19960814 SROS: AMEX SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFIC GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000075488 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 940742640 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-02348 FILM NUMBER: 96611836 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 MAIL CODE B7C CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4159737000 10-Q 1 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 ---------------------------------- (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ---------- ---------- Commission File No. 1-2348 PACIFIC GAS AND ELECTRIC COMPANY ----------------------------------------- (Exact name of registrant as specified in its charter) California 94-0742640 - ---------------------------- ------------------- (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 77 Beale Street, P.O. Box 770000, San Francisco, California 94177 - ----------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code:(415) 973-7000 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ---------- ----------- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at July 31, 1996 --------------- -------------------------------- Common Stock, $5 par value 415,749,797 shares Form 10-Q TABLE OF CONTENTS ----------------- PART I. FINANCIAL INFORMATION Page - ------------------------------- ---- Item 1. Consolidated Financial Statements and Notes Statement of Consolidated Income................... 1 Consolidated Balance Sheet......................... 2 Statement of Consolidated Cash Flows............... 4 Note 1: General Basis of Presentation................... 5 Note 2: Electric Industry Restructuring........... 5 Note 3: Natural Gas Matters Gas Reasonableness Proceedings.......... 11 PGT/PG&E Pipeline Expansion Project..... 12 Transportation Commitments.............. 13 Note 4: Diablo Canyon............................. 15 Note 5: Contingencies Nuclear Insurance....................... 15 Environmental Remediation............... 16 Helms Pumped Storage Plant.............. 17 Legal Matters........................... 17 Note 6: Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely PG&E Subordinated Debentures.............. 18 Item 2. Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Electric Industry Restructuring.................... 19 Gas Industry Restructuring......................... 23 Holding Company Structure.......................... 24 Utility Revenue Matters............................ 25 Results of Operations.............................. 27 Earnings Per Common Share........................ 28 Common Stock Dividend............................ 28 Operating Revenues............................... 29 Operating Expenses............................... 29 Liquidity and Capital Resources Sources of Capital............................... 29 Acquisition...................................... 30 Environmental Remediation........................ 30 Legal Matters.................................... 30 Accounting for Decommissioning Expense........... 30 PART II. OTHER INFORMATION - --------------------------- Item 1. Legal Proceedings Time-of-Use Meter/Customer Notification Litigation......................... 31 Item 5. Other Information Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends............ 31 Item 6. Exhibits and Reports on Form 8-K..................... 32 SIGNATURE...................................................... 33 PART 1. FINANCIAL INFORMATION Item 1. Consolidated Financial Statements --------------------------------- PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME (unaudited)
- -------------------------------------------------------------------------------------------- Three months ended June 30, Six months ended June 30, (in thousands, --------------------------- -------------------------- except per share amounts) 1996 1995 1996 1995 - -------------------------------------------------------------------------------------------- OPERATING REVENUES Electric utility $1,660,867 $1,894,667 $3,309,469 $3,591,453 Gas utility 451,511 506,550 1,020,322 1,050,645 Diversified operations 26,288 47,424 57,643 114,790 ---------- ---------- ---------- ---------- Total operating revenues 2,138,666 2,448,641 4,387,434 4,756,888 ---------- ---------- ---------- ---------- OPERATING EXPENSES Cost of electric energy 530,792 518,005 997,786 922,728 Cost of gas 67,151 83,349 255,288 186,912 Maintenance and other operating 525,058 391,929 981,532 813,883 Depreciation and decommissioning 303,382 344,293 606,329 696,476 Administrative and general 346,762 214,592 526,141 475,713 Workforce reduction cost - - - (18,195) Property and other taxes 77,146 76,103 158,589 149,972 ---------- ---------- ---------- ---------- Total operating expenses 1,850,291 1,628,271 3,525,665 3,227,489 ---------- ---------- ---------- ---------- OPERATING INCOME 288,375 820,370 861,769 1,529,399 ---------- ---------- ---------- ---------- OTHER INCOME AND (INCOME DEDUCTIONS) Interest income 21,348 17,619 45,691 32,945 Allowance for equity funds used during construction 3,321 6,462 6,078 12,100 Other--net 7,973 19,888 13,655 17,420 ---------- ---------- ---------- ---------- Total other income and (income deductions) 32,642 43,969 65,424 62,465 ---------- ---------- ---------- ---------- INCOME BEFORE INTEREST EXPENSE 321,017 864,339 927,193 1,591,864 ---------- ---------- ---------- ---------- INTEREST EXPENSE Interest on long-term debt 149,324 162,423 302,491 324,572 Other interest charges 14,059 13,561 36,377 28,337 Allowance for borrowed funds used during construction (1,899) (3,207) (3,456) (6,083) ---------- ---------- ---------- ---------- Net interest expense 161,484 172,777 335,412 346,826 ---------- ---------- ---------- ---------- PRETAX INCOME 159,533 691,562 591,781 1,245,038 ---------- ---------- ---------- ---------- INCOME TAXES 47,753 286,042 219,297 510,831 ---------- ---------- ---------- ---------- NET INCOME 111,780 405,520 372,484 734,207 Preferred dividend requirement and redemption premium 8,278 14,494 16,556 28,988 ---------- ---------- ---------- ---------- EARNINGS AVAILABLE FOR COMMON STOCK $ 103,502 $ 391,026 $ 355,928 $ 705,219 ========== ========== ========== ========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 415,125 426,621 414,738 428,344 EARNINGS PER COMMON SHARE $.25 $.92 $ .86 $1.65 DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49 $ .98 $ .98 - -------------------------------------------------------------------------------------------- The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (unaudited)
- -------------------------------------------------------------------------------------------- June 30, December 31, (in thousands) 1996 1995 - -------------------------------------------------------------------------------------------- ASSETS PLANT IN SERVICE Electric Nonnuclear $17,928,412 $17,513,830 Diablo Canyon 6,680,862 6,646,853 Gas 7,900,198 7,732,681 ----------- ----------- Total plant in service (at original cost) 32,509,472 31,893,364 Accumulated depreciation and decommissioning (13,953,587) (13,308,596) ----------- ----------- Net plant in service 18,555,885 18,584,768 ----------- ----------- CONSTRUCTION WORK IN PROGRESS 239,679 333,263 OTHER NONCURRENT ASSETS Nuclear decommissioning funds 816,459 769,829 Investments in nonregulated projects 834,749 869,674 Other assets 128,957 130,128 ----------- ----------- Total other noncurrent assets 1,780,165 1,769,631 ----------- ----------- CURRENT ASSETS Cash and cash equivalents 137,457 734,295 Accounts receivable Customers 1,174,774 1,238,549 Other 33,449 65,907 Allowance for uncollectible accounts (37,552) (35,520) Regulatory balancing accounts receivable 728,128 746,344 Inventories Materials and supplies 178,018 181,763 Gas stored underground 127,609 146,499 Fuel oil 30,200 40,756 Nuclear fuel 173,677 175,957 Prepayments 26,644 47,025 ----------- ----------- Total current assets 2,572,404 3,341,575 ----------- ----------- DEFERRED CHARGES Income tax-related deferred charges 1,051,458 1,079,673 Diablo Canyon costs 375,965 382,445 Unamortized loss net of gain on reacquired debt 384,969 392,116 Workers' compensation and disability claims recoverable 287,812 297,266 Other 509,764 669,553 ----------- ----------- Total deferred charges 2,609,968 2,821,053 ----------- ----------- TOTAL ASSETS $25,758,101 $26,850,290 =========== =========== - -------------------------------------------------------------------------------------------- (continued on next page)
PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (unaudited)
- -------------------------------------------------------------------------------------------- June 30, December 31, (in thousands) 1996 1995 - -------------------------------------------------------------------------------------------- CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock $ 2,064,488 $ 2,070,128 Additional paid-in capital 3,753,964 3,716,322 Reinvested earnings 2,700,704 2,812,683 ----------- ----------- Total common stock equity 8,519,156 8,599,133 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 subsidiary trust holding solely PG&E subordinated debentures 300,000 300,000 Long-term debt 7,923,496 8,048,546 ----------- ----------- Total capitalization 17,282,208 17,487,235 ----------- ----------- OTHER NONCURRENT LIABILITIES Customer advances for construction 133,649 146,191 Workers' compensation and disability claims 271,400 271,000 Other 724,879 815,960 ----------- ----------- Total other noncurrent liabilities 1,129,928 1,233,151 ----------- ----------- CURRENT LIABILITIES Short-term borrowings 56,073 829,947 Long-term debt 221,133 304,204 Accounts payable Trade creditors 360,671 413,972 Other 369,748 387,747 Accrued taxes 403,323 274,093 Deferred income taxes 169,360 227,782 Interest payable 68,889 70,179 Dividends payable 211,445 205,467 Other 605,463 504,973 ----------- ----------- Total current liabilities 2,466,105 3,218,364 ----------- ----------- DEFERRED CREDITS Deferred income taxes 3,950,144 3,933,765 Deferred tax credits 387,420 393,255 Noncurrent balancing account liabilities 211,292 185,647 Other 331,004 398,873 ----------- ----------- Total deferred credits 4,879,860 4,911,540 CONTINGENCIES (Notes 2, 3 and 5) ----------- ----------- TOTAL CAPITALIZATION AND LIABILITIES $25,758,101 $26,850,290 =========== =========== - -------------------------------------------------------------------------------------------- The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED CASH FLOWS (unaudited)
- -------------------------------------------------------------------------------------------- Six months ended June 30, ------------------------ (in thousands) 1996 1995 - -------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 372,484 $ 734,207 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and decommissioning 606,329 696,476 Amortization 44,774 69,189 Gain on sale of DALEN - (13,107) Deferred income taxes and tax credits--net (18,532) (134,184) Allowance for equity funds used during construction (6,078) (12,100) Other deferred charges 75,301 40,427 Other noncurrent liabilities (22,223) (24,495) Noncurrent balancing account liabilities and other deferred credits (42,224) (72,689) Net effect of changes in operating assets and liabilities Accounts receivable 98,265 185,252 Regulatory balancing accounts receivable 18,216 286,443 Inventories 33,191 31,738 Accounts payable (71,300) (85,434) Accrued taxes 129,230 189,768 Other working capital 119,581 (56,774) Other-net 40,987 33,851 ---------- ---------- Net cash provided by operating activities 1,378,001 1,868,568 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (509,653) (399,033) Allowance for borrowed funds used during construction (3,456) (6,083) Nonregulated projects 11,596 (59,767) Proceeds from sale of DALEN - 340,000 Other--net (40,644) (123,177) ---------- ---------- Net cash used by investing activities (542,157) (248,060) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock issued 113,290 92,315 Common stock repurchased (135,036) (267,799) Long-term debt issued 983,944 567,160 Long-term debt matured, redeemed or repurchased (1,196,269) (957,583) Short-term debt redeemed--net (773,874) (314,685) Dividends paid (422,994) (451,082) Other--net (1,743) (9,457) ---------- ---------- Net cash used by financing activities (1,432,682) (1,341,131) ---------- ---------- NET CHANGE IN CASH AND CASH EQUIVALENTS (596,838) 279,377 CASH AND CASH EQUIVALENTS AT JANUARY 1 734,295 136,900 ---------- ---------- CASH AND CASH EQUIVALENTS AT JUNE 30 $ 137,457 $ 416,277 ========== ========== Supplemental disclosures of cash flow information Cash paid for Interest (net of amounts capitalized) $ 318,292 $ 330,640 Income taxes 106,119 459,028 - -------------------------------------------------------------------------------------------- The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) NOTE 1: General - ---------------- Basis of Presentation: - --------------------- The accompanying unaudited consolidated financial statements of Pacific Gas and Electric Company (PG&E) and its wholly owned and controlled subsidiaries (collectively, the Company) have been prepared in accordance with interim period reporting requirements. This information should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in the 1995 Annual Report on Form 10-K. In the opinion of management, the accompanying statements reflect all adjustments which are necessary to present a fair statement of the 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. Prior year's amounts in the consolidated financial statements have been reclassified where necessary to conform to the 1996 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. NOTE 2: Electric Industry Restructuring - ---------------------------------------- On December 20, 1995, the California Public Utilities Commission (CPUC) issued a decision calling for the restructuring of California's electric industry. The CPUC's goal is to provide a structure that will ultimately allow California consumers to choose among competing suppliers of electricity. In summary, the decision would (1) simultaneously create a wholesale power pool, or Exchange, and allow direct access for certain customers to contract directly with electric generation providers beginning in 1998 with all customers phased in within five years; (2) establish an Independent System Operator (ISO) to manage and control the transmission system; (3) provide recovery of utilities' transition costs (costs which are above-market and could not be recovered under market-based pricing) through a surcharge, or competition transition charge (CTC), to be imposed on all customers; (4) allow investor-owned utilities to continue to provide distribution, generation and procurement functions for those customers choosing to take bundled service from the utilities, all of which would be regulated under performance-based ratemaking (PBR); and (5) provide incentives to encourage voluntary divestiture of at least 50 percent of utilities' fossil fuel generation assets. The decision and subsequent CPUC rulings and workshops have set out an ambitious schedule for various implementation filings and comments through mid-1997. To prepare for competition in electric generation resulting from the CPUC's restructuring decision, PG&E has filed regulatory applications and proposals in three key areas: implementation, ratemaking and CTC recovery. In addition, in June 1996, PG&E entered into a Restructuring Rate Settlement with several parties representing consumers, labor and independent electricity producers. This Settlement endorses the Company's proposed modification of the Diablo Canyon Nuclear Power Plant (Diablo Canyon) rate case settlement as modified in 1995 (Diablo Settlement), establishment of a customer electric rate freeze, and certain principles governing restructuring of PG&E's electric business which will be reflected in PG&E's filings as summarized below. In addition, at the California Legislature, a two-house conference committee on Electric Industry Restructuring has been holding hearings and considering legislation which would resolve various issues relating to restructuring of the electric industry. To date, the committee has not adopted any legislative proposals, and the current legislative session ends August 31, 1996. The Company cannot predict whether legislation will in fact be adopted before the end of the legislative session or the substance of any legislation that may be adopted. IMPLEMENTATION: In April 1996, PG&E, San Diego Gas and Electric Company (SDG&E) and Southern California Edison Company (SCE) filed joint ISO and Exchange applications with the Federal Energy Regulatory Commission (FERC) and the CPUC. These applications requested authorization to transfer operational control (but not ownership) of certain jurisdictional transmission facilities to the ISO and to sell electric energy at market-based rates using the Exchange. In August 1996, the CPUC conditionally approved a joint application by PG&E, SDG&E and SCE which establishes two tax-exempt trusts for the purpose of overseeing the costs associated with the development of the ISO and Exchange. These costs are estimated to range between $200 and $300 million and would be financed through bank loans to the trust supported by guarantees by PG&E and the other utilities. PG&E would guarantee a maximum of $112.5 million of such costs. In March 1996, PG&E filed comments with the CPUC indicating that it is willing to proceed with voluntary divestiture of at least 50 percent of its fossil fuel generation assets, as long as CTC recovery is satisfactorily resolved. In its filing, PG&E described various options for divestiture, including spinning assets off to a new unaffiliated corporate entity, selling assets on the open market, negotiating with individual potential buyers in special circumstances, leasing facilities and/or selling assets to employees through an employee stock ownership plan. PG&E will also evaluate the economic feasibility and desirability of divesting additional nonnuclear generating assets. PG&E is currently evaluating the marketplace, including identifying plants that might be divested, and identifying the form divestiture might take and when it might occur. In March 1996, PG&E filed comments with the CPUC on the feasibility, timing and consequences of a corporate restructuring to separate PG&E's operations and assets between the generation, transmission and distribution functions, indicating that, for the time being, it sees no obvious benefits from separating its generation, transmission and distribution functions into separate corporate subsidiaries. However, PG&E believes it may be appropriate in the future to hold any generation it retains in a separate corporate entity and that such segregation of assets would be consistent with the holding company structure it proposed in a filing with the CPUC in October 1995. RATEMAKING: In July 1996, consistent with the CPUC's restructuring decision, PG&E submitted an application proposing to establish a PBR mechanism for a portion of its electric generation services. Key elements of PG&E's proposed generation PBR include the following: 1) PG&E proposes a combined PBR recovery mechanism for its hydroelectric and geothermal generating unit costs. The proposed mechanism consists of a base revenue amount that is indexed to account for inflation less a productivity offset and shared earnings. Adjustments are made to account for fuel costs, performance standards and extraordinary costs or savings. Implementation of the hydroelectric/geothermal PBR would begin on January 1, 1998. If PG&E's proposal to modify Diablo Canyon pricing and implement a customer electric rate freeze is adopted, the PBR will terminate by the end of 2001, at which time all generation will be priced at market levels. 2) For all fossil generation units, PG&E proposes that after January 1, 1998, sunk costs be recovered directly through the CTC component of rates, consistent with the CPUC's restructuring decision. 3) PG&E proposes that all fixed and variable operating costs for its fossil generation units would be recovered either through revenues from sales through the Exchange or through contracts with the ISO for services provided to maintain reliability of the transmission system. Also in July 1996, PG&E submitted a preliminary unbundling proposal to the CPUC relating to the separation of electric base revenues and the costs that underlie them into five basic components: generation, CTC, transmission, distribution, and public purpose programs. PG&E's formal unbundling application will be filed by November 15, 1996, and will incorporate any resolution at the FERC regarding the separation between distribution and transmission functions. COMPETITION TRANSITION CHARGE RECOVERY: In August 1996, PG&E submitted its sunk cost application to the CPUC which identifies and values, to the extent possible at this time, nonnuclear generation-related sunk costs that will be eligible for recovery through the CTC to be implemented on January 1, 1998. Sunk costs, defined in the filing as costs that are fixed and unavoidable, are just one component of the transition costs eligible for recovery through the CTC. Other such components will be identified in a separate application to be made on August 30, 1996. Sunk costs include costs incurred in the past that are currently included in rates, such as the original costs of generation facilities, net of accumulated depreciation, and regulatory assets. PG&E indicated that the value of these sunk costs as of December 31, 1995, was $4.4 billion. Sunk costs also include costs that will be incurred in the future, such as fossil decommissioning costs. These costs are estimated to be $1.8 billion, resulting in total estimated sunk costs of $6.2 billion. The amounts in the sunk cost application may change to reflect changes and modifications made in other restructuring-related CPUC and FERC filings. PG&E's sunk cost application notes that certain future sunk costs have been excluded from these estimates consistent with PG&E's Restructuring Rate Settlement. If these costs were included in PG&E's sunk cost estimates, PG&E's aggregate sunk costs would increase to $6.8 billion. In April 1996, the CPUC granted PG&E's emergency motion to establish an interim CTC procedure applicable to certain departing electric retail customers. This rate procedure will remain in effect until the CPUC adopts and implements a final CTC mechanism, which is expected to be effective January 1, 1998. At that time, amounts paid on an interim basis will be subject to true up to reflect the CPUC's final CTC methodology. MODIFICATION OF DIABLO SETTLEMENT AND RATE FREEZE: In March 1996, PG&E filed an application with the CPUC seeking approval to modify the Diablo Settlement, as discussed in Note 4, contingent upon the adoption of a five-year customer electric rate freeze, effective January 1, 1997. The application would reduce the amount of Diablo Canyon transition costs by $4 billion (net present value), at an assumed marked price of $.025, compared to transition costs that would arise under existing Diablo Canyon prices, while recovering remaining Diablo Canyon and other uneconomic utility generation assets by no later than the end of 2001. PG&E's application would result in the termination of the Diablo Settlement by the end of 2001, at which time Diablo Canyon's generation may be priced at market levels consistent with the goals of the CPUC's restructuring decision. PG&E proposes that the current pricing of Diablo Canyon generation, as set forth in the Diablo Settlement, be replaced by a new pricing arrangement. Under this approach, the current Diablo Canyon fixed price would be replaced by a sunk cost revenue requirement consisting of PG&E's remaining sunk costs in Diablo Canyon at December 31, 1996, depreciated over a five-year period and subject to a reduced return on common equity equal to 6.77 percent. Diablo Canyon sunk costs include net plant, working capital and regulatory assets, all net of deferred taxes. The sunk cost revenue requirement would be recovered without reference to Diablo Canyon's performance, unless the plant were shut down for nine months or more. The escalating component of current Diablo Canyon prices would be replaced by a performance-based Incremental Cost Incentive Price (ICIP) for recovery of Diablo Canyon's variable costs and future capital additions. Under the ICIP, the variable costs and incremental capital additions are recovered under a pre-set price per kilowatt-hour (kWh) of plant output based on an initial forecast of such costs and output. The 2016 termination date in the Diablo Settlement would be changed to December 31, 2001, and related abandonment payment provisions in the Diablo Settlement would be replaced with closure cost recovery provisions, under which PG&E would be entitled to recover a percentage of its annual operating and maintenance and administrative and general costs for a limited period of years following permanent plant closure. PG&E's continued recovery of the sunk cost revenue requirement would be subject to CPUC evaluation if Diablo Canyon is shut down for nine months or more prior to such time as transition costs are fully recovered. After such time as transition costs are fully recovered, there would be no restrictions on Diablo Canyon's operations, to which customers it could sell and at what prices, terms and conditions, but 50 percent of any after-tax earnings available for common equity after such time would be allocated to ratepayers. Certain fixed or safety-related costs, such as decommissioning costs, would continue to be recovered in PG&E's base rates without reference to Diablo Canyon's performance. At PG&E's option, recovery of estimated decommissioning costs could be accelerated under the customer electric rate freeze over the same depreciation period as Diablo Canyon's sunk costs. In conjunction with these modifications to the Diablo Settlement, PG&E's application proposes that the CPUC adopt a customer electric rate freeze at 1996 levels through the end of 2001, in order to permit PG&E to accelerate capital recovery of its other utility generation and associated regulatory assets through 2001. PG&E would be at risk for completing recovery of PG&E's above-market utility generation-related investments, including Diablo Canyon, and related regulatory assets by the end of 2001. PG&E indicated that adoption of its customer electric rate freeze proposal is linked inextricably with the proposal to modify Diablo Canyon pricing. In the event that the CPUC is unable to adopt the proposed customer electric rate freeze, PG&E would withdraw its proposal to modify Diablo Canyon pricing and instead would propose an alternative modification of Diablo Canyon pricing. In June 1996, a CPUC administrative law judge (ALJ) issued a ruling establishing a procedural schedule for PG&E's Diablo Canyon/rate freeze proposal. The ruling calls for a Division of Ratepayer Advocates (DRA) report in August and public hearings in October 1996. A proposed decision is scheduled for February 1997, with a final decision expected in late March 1997. Financial Impact of the Electric Industry Restructuring: In response to a request from the California Legislative Conference Committee on Electric Industry Restructuring, PG&E estimated its transition costs expected to be recovered through the CTC under the restructuring decision. The estimates of transition costs were based on Diablo Canyon revenue requirements, cost recovery of power purchase obligations and generation related regulatory assets, and net cash flows for nonnuclear generation plants. To provide a range of possible transition costs, the estimates used market price assumptions of $.035 and $.025 per kWh at January 1, 1996, and an annual escalation rate of 3.2 percent. These market prices do not represent a forecast of expected market prices. Factors that could impact market prices include changes in gas prices, changes in inflation rates, levels of new technology costs and the potential oversupply of generation within the market. Based on PG&E's proposal to modify the Diablo Settlement and implement a customer electric rate freeze, the transition costs of PG&E's owned generation assets and power purchase obligations were estimated to be $10.5 billion to $14.0 billion (net present value at January 1998) at assumed market prices of $.035 and $.025 per kWh. PG&E's proposal to modify the Diablo Settlement and implement a customer electric rate freeze accelerates the transition cost recovery period to January 1997 through December 2001 and reduces Diablo Canyon's estimated transition costs by $3.0 billion to $4.0 billion (net present value) at the assumed market prices noted above, as compared to transition costs that would arise under the existing Diablo Settlement. Based on the existing Diablo Settlement, the net present value at January 1998 of transition costs for Diablo Canyon were estimated to be $8.1 billion to $9.6 billion at the assumed market prices noted above. Any forecast of transition costs is inextricably tied to the assumptions made at the time of the analysis. The actual amounts of transition costs may differ materially from those indicated above and will depend on the costs authorized for recovery, the actual market prices of electricity in the future and any market valuations of PG&E's generation assets. On August 30, 1996, PG&E will file its CTC application with the CPUC, which application will identify all transition costs eligible for recovery through the CTC. The CPUC's restructuring decision limits recovery of CTC to an amount that does not increase customers' aggregate rates above those in effect on January 1, 1996. The proposal to modify the Diablo Settlement offers substantial reductions in post-2001 performance-based revenues in exchange for a commitment to freeze customer electric rates through 2001 to allow accelerated collection of utility generation-related CTC. Recent CPUC decisions effective on January 1, 1996, including PG&E's 1996 General Rate Case (GRC), have resulted in an average electric system rate of $.099 per kWh. PG&E believes that the revenues generated under its proposed customer electric rate freeze would be adequate to recover its above-market generation assets by the end of 2001. However, PG&E's ability to recover its transition costs will be dependent on several factors, including: (1) the aggregate amount of PG&E's transition costs, which in turn depends on a number of factors, including the expected market value of a portion of its generation plants, future sales levels, fuel and operating costs and the market price of electricity; (2) maintaining electric rates at 1996 levels; and (3) PG&E's ability to continue to collect CTC for the duration of the recovery period. The proposal to modify the Diablo Settlement would significantly reduce the level of PG&E's CTC by reducing the common equity returns on the Diablo Canyon plant investment to 6.77 percent and accelerating the capital recovery of the plant and other utility generation-related assets. In addition, the proposal would also limit recovery of most utility generation-related CTC to amounts collected through 2001. The Company currently accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," which allows the Company to capitalize certain costs, that would otherwise have been expensed, as regulatory assets. 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 portions of long- lived assets that are no longer probable of recovery. When electric generation rates are no longer based on cost of service, as ultimately contemplated under the CPUC's restructuring decision, PG&E would discontinue application of SFAS No. 71 for the electric generation portion of its business. As a result, all applicable electric generation-related regulatory assets and other transition costs determined to be probable of CTC recovery would be a regulatory asset collected through cost-of-service based customer rates and subject to the provisions to SFAS No. 71. In addition, the CTC account and electric generation assets will be subject to the criteria of SFAS No. 121. As a result of applying the provisions of SFAS No. 71, PG&E had accumulated approximately $1.5 billion of regulatory assets attributable to electric generation at June 30, 1996. The net investment in Diablo Canyon and the remaining PG&E-owned generation assets, including an allocation of common plant, was approximately $4.8 billion and $2.8 billion, respectively, at June 30, 1996. (The above amounts could vary depending on allocation methods used.) PG&E's transmission and distribution businesses are expected to remain under the provisions of SFAS No. 71. Due to the expected transition cost recovery as provided in the CPUC's restructuring decision and in PG&E's Diablo Canyon pricing/customer electric rate freeze proposal, PG&E does not anticipate a material loss from the discontinuance of SFAS No. 71 or an impairment loss on its investment in generation assets due to electric industry restructuring. However, the Company cannot predict the ultimate outcome of the ongoing changes that are taking place in the electric utility industry or predict whether such outcome will have a material adverse impact on its financial position or results of operations. Should final implementing regulations or any legislation that may be adopted differ significantly from the CPUC's restructuring decision or PG&E's Diablo Canyon pricing/customer electric rate freeze proposal, or should full recovery of generation assets and obligations not be achieved due to changing costs or limitations imposed by the market or should a CPUC ordered customer electric rate reduction occur, a material loss could occur. NOTE 3: Natural Gas Matters - ---------------------------- Gas Reasonableness Proceedings: - ------------------------------ Recovery of gas costs through PG&E's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were reasonable. Under the current regulatory framework, annual reasonableness proceedings are conducted by the CPUC on a historic calendar year basis. In 1994, the CPUC issued a decision which ordered a disallowance of approximately $90 million of gas costs plus accrued interest of approximately $25 million through 1993 for PG&E's Canadian gas procurement activities from 1988 through 1990. In March 1996, PG&E refunded $53 million of the ordered disallowance to ratepayers pursuant to a CPUC decision in December 1995 on PG&E's Biennial Cost Allocation Proceeding. PG&E has filed a lawsuit in a federal district court challenging the CPUC's decision on Canadian gas costs. In 1995, the federal court denied a motion filed by the CPUC to dismiss the lawsuit. A number of other reasonableness issues related to PG&E's gas procurement practices, transportation capacity commitments and supply operations for periods dating from 1988 to 1994 are still under review by the CPUC. The DRA had recommended disallowances of approximately $79 million and a penalty of $50 million and indicated that it was considering additional recommendations for pending issues. PG&E and the DRA have signed a settlement agreement to resolve these issues for a $67 million refund by PG&E. In August 1996, the CPUC issued a decision approving the settlement, contingent upon the DRA and PG&E agreeing to amend the settlement to include an additional $6.5 million, which represents interest from the date the DRA and PG&E filed the settlement agreement with the CPUC. The DRA and PG&E must inform the CPUC of their position in September 1996. If the parties do not agree to the amendment, the settled issues would be set for hearings. At June 30, 1996, PG&E had accrued approximately $150 million for the CPUC's 1988 through 1990 gas reasonableness decision and issues covered by the settlement agreement described above. The Company believes the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. PGT/PG&E Pipeline Expansion Project (Pipeline Expansion): - -------------------------------------------------------- In November 1993, the Company placed in service an expansion of its natural gas transmission system from the Canadian border into California. The Pipeline Expansion provides additional firm transportation capacity to Northern and Southern California and the Pacific Northwest. The total cost of construction is estimated to be approximately $1.7 billion; $810 million for the PG&E or California portion (PG&E Pipeline Expansion) and $852 million for the Pacific Gas Transmission Company (PGT) or interstate portion. PG&E has filed an application with the CPUC requesting that capital and operating costs for the PG&E Pipeline Expansion be found reasonable. In that CPUC proceeding, the DRA recommended that a minimum of $100 million in capital costs be disallowed for recovery in rates while two intervenors jointly recommended a $237 million disallowance or reallocation of costs among customers. Evidentiary hearings will be held in late 1996. Revenues are currently being collected under interim rates approved by the CPUC, subject to adjustment. At June 30, 1996, PG&E had collected approximately $190 million under such rates. In January 1996, an ALJ ordered consolidation of the market impact phase of the PG&E Pipeline Expansion reasonableness proceeding and the Interstate Transition Cost Surcharge (ITCS) proceeding discussed below. Evidentiary hearings in this phase of the proceeding were held in April and May 1996. An order issued by an ALJ has also reopened the 1993 PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding the decision to construct the PG&E Pipeline Expansion. Evidentiary hearings in the reopened proceeding were conducted in June 1996. If the CPUC were to reverse its previous decision finding PG&E was reasonable in constructing the PG&E Pipeline Expansion, the ultimate outcome could have an impact on PG&E's ability to recover its cost for unused capacity on other pipelines as well as on its own intrastate facilities. For the interstate portion of the Pipeline Expansion, PGT included $832 million of capital costs, representing such costs incurred through July 1994, in its 1994 GRC filing with the FERC. No parties contested these costs and the parties have since filed a proposed settlement of that rate case with the FERC for approval. Decisions in these proceedings are expected in 1996 and 1997. The Company believes the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. Transportation Commitments: - -------------------------- PG&E has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that PG&E will pay each year may change due to changes in tariff rates and may be offset to the extent PG&E can broker or permanently assign any unused capacity. The following table summarizes the approximate capacity held by PG&E on various pipelines (excluding PGT) and the related annual demand charges at June 30, 1996: Total Firm Capacity Annual Demand Pipeline Held Charges Contract Company (MMcf/d) (in millions) Expiration - ---------------------- ------------- ------------- ---------- El Paso 1,140 $163 Dec. 1997 Transwestern 200 $ 28 Mar. 2007 NOVA 600 $ 20 Oct. 2001 ANG 600 $ 13 Oct. 2005 As a result of regulatory changes, PG&E no longer procures gas for its industrial and large commercial (noncore) customers, resulting in a decrease in PG&E's need for firm transportation capacity for its gas purchases. PG&E continues to procure gas for its residential and smaller commercial (core) customers and noncore customers who choose bundled service (core subscription customers). In order to service these customers, PG&E holds approximately 600 million cubic feet per day (MMcf/d) of firm capacity for its core and core subscription customers on each of the pipelines owned by El Paso Natural Gas Company (El Paso), NOVA Corporation of Alberta (NOVA) and Alberta Natural Gas Company Ltd (ANG). PG&E is continuing its efforts to broker or assign any remaining unused capacity including that held for its core and core subscription customers when such capacity is not being used. Due to relatively low demand for Southwest pipeline capacity, PG&E cannot predict the volume or price of the capacity on El Paso and Transwestern Pipeline Company (Transwestern) that will be brokered or assigned. Substantially all demand charges incurred by PG&E for pipeline capacity, including charges for capacity formerly used to service noncore customers which cannot be brokered or which is brokered at a discount, are eligible for rate recovery, subject to a reasonableness review. However, certain groups, including the DRA and intervenors, have challenged the recovery of certain demand charges. In December 1995, the CPUC issued a decision on the reasonableness of PG&E's 1992 operations concluding that it was unreasonable for PG&E to subscribe for transportation capacity with Transwestern. The decision concluded that PG&E was unable to prove the benefits of such capacity during 1992 and denied recovery of the $18 million of Transwestern charges for that year. The decision further orders that costs for the capacity in subsequent years of the contract, which expires in 2007, be disallowed unless PG&E can demonstrate that the benefits of the commitment outweigh the costs. PG&E is seeking rehearing of this decision. The recovery of demand charges associated with capacity which was formerly used to serve PG&E's noncore customers will be decided by the CPUC in the ITCS proceeding. Pending a final decision in the ITCS proceeding, the CPUC has approved collection in rates of approximately one-half of the demand charges for unbrokered or discounted El Paso and PGT capacity which was formerly used to serve PG&E's noncore customers, subject to refund. In October 1995, PG&E presented a proposal, called the Gas Accord, to numerous parties active in the California gas marketplace, in an effort to restructure the California gas market. As part of the Gas Accord negotiations, PG&E is pursuing the resolution of existing regulatory issues pending in separate CPUC proceedings. Regulatory issues being negotiated as part of the Gas Accord include PG&E's capacity commitments with Transwestern, recovery of the costs for unbrokered capacity commitments under the ITCS mechanism and the reasonableness proceedings for the PG&E Pipeline Expansion. In addition to the Gas Accord negotiations, PG&E is proposing to replace traditional reasonableness proceedings relating to its gas procurement costs with a core procurement incentive mechanism (CPIM). The CPIM would allow PG&E to recover its gas costs under a mechanism through which PG&E would receive benefits or be penalized depending on whether its actual core procurement costs were within, below or above a "tolerance band" constructed around a market benchmark. Based on the current status of the Gas Accord negotiations and regulatory proceedings, the Company believes the ultimate resolution of past and future Transwestern costs, the ITCS proceeding and the PG&E Pipeline Expansion proceedings, either through settlement negotiations or ongoing proceedings, will not have a material adverse impact on its financial position or results of operations. NOTE 4: Diablo Canyon - ---------------------- In May 1995, the CPUC approved a modification to the pricing provisions of the Diablo Settlement. Under the modification, the prices for power produced by Diablo Canyon for 1996 through 1999 are 10.5 cents, 10.0 cents, 9.5 cents and 9.0 cents per kWh, respectively, effective January 1. PG&E has the right to reduce the price below the amount specified. All other terms and conditions of the Diablo Settlement remain unchanged. Under the modified pricing, at full operating power each Diablo Canyon unit would contribute approximately $2.7 million in revenues per day in 1996. As discussed in Note 2, in connection with the CPUC's electric industry restructuring decision, PG&E filed in March 1996, a proposal for pricing Diablo Canyon generation at market prices and completing recovery of the investment in Diablo Canyon and terminating the Diablo Settlement by the end of 2001. NOTE 5: Contingencies - ---------------------- Nuclear Insurance: - ----------------- PG&E is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). Under these policies, if the nuclear generating facility of a member utility suffers a property damage loss or a business interruption loss due to a prolonged accidental outage, PG&E may be subject to maximum assessments of $26 million (property damage) and $8 million (business interruption), in each case per policy period, in the event losses exceed the resources of NML or NEIL. Federal law requires all utilities with nuclear generating facilities to share in payment for claims resulting from a nuclear incident and limits industry liability for third-party claims to $8.9 billion per incident. Coverage of the first $200 million is provided by a pool of commercial insurers. If a nuclear incident results in claims in excess of $200 million, PG&E may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: - ------------------------- The Company records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company 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 probable amount, the Company records the lower end of this reasonably likely range of costs (classified as other noncurrent liabilities). The Company may be required to pay for remedial action at sites where the Company has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or the California Hazardous Substance Account Act. These sites include former manufactured gas 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, the Company's financial responsibilities may include remediation of hazardous wastes, even if the Company did not deposit those wastes on the site. The overall costs of the hazardous materials and hazardous waste compliance and remediation activities ultimately undertaken by the Company are difficult to estimate, and it is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Company's responsibility, changing environmental laws and regulations, evolving technologies, the nature and extent of required remediation, the selection of compliance alternatives and the ultimate outcome of factual investigations. The Company has an accrued liability at June 30, 1996, of $152 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. The costs may be as much as $364 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions less favorable to the Company, among a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. The Company will seek recovery of prudently incurred hazardous waste compliance and remediation costs through ratemaking procedures approved by the CPUC, through insurance and through other recoveries from third parties. The Company has recorded a regulatory asset at June 30, 1996, of $132 million for recovery of these costs in future rates. While the Company has numerous insurance policies that it believes may provide coverage for some of these liabilities, it does not recognize insurance or third-party recoveries in its financial statements until they are realized. The Company believes the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. Helms Pumped Storage Plant (Helms): - ---------------------------------- Helms is a three-unit hydroelectric combined generating and pumped storage plant with a net investment of $713 million at June 30, 1996. The 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 GRC decision issued 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 as a result of the study, but 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, the Company expects to seek recovery of its net investment in Helms through the hydroelectric/geothermal PBR and CTC mechanisms (see Note 2). The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. Legal Matters: - ------------- Hinkley Litigation: In 1993, a complaint was filed in a state superior court on behalf of individuals seeking recovery of an unspecified amount of damages for personal injuries and property damage allegedly suffered as a result of exposure to chromium near PG&E's Hinkley Compressor Station, as well as punitive damages. In June 1996, PG&E agreed to settle the plaintiffs' claims for the aggregate sum of $333 million, of which $50 million had already been paid. Accordingly, at June 30, 1996, $283 million was included in other current liabilities. The settlement resulted in a charge of $133 million in the second quarter of 1996. Cities Franchise Fees Litigation: In 1994, the City of Santa Cruz filed a class action suit in a state superior court (Court) against PG&E on behalf of itself and 106 other cities in PG&E's service area. The complaint alleges that PG&E has underpaid electric franchise fees to the cities by calculating fees at different rates from other cities. In September 1995, the Court certified the class of 107 cities in this action and approved the City of Santa Cruz as the class representative. In January and March 1996, the Court made two rulings against certain plaintiffs effectively eliminating a major portion of the class action. The Court's rulings do not resolve the case completely. The plaintiffs appealed both rulings. The trial has been postponed pending the plaintiffs' 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 $17 million and damages for alleged underpayments for the years 1987 to 1995 could be as much as $131 million (exclusive of interest, estimated to be $35 million at June 30, 1996). 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 plaintiffs not subject to the Court's rulings could increase by approximately $5 million and damages for alleged underpayments for the years 1987 to 1995 could be as much as $35 million (exclusive of interest, estimated to be $9 million at June 30, 1996). The Company believes that the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. NOTE 6: Company Obligated Mandatorily Redeemable Preferred Securities - ---------------------------------------------------------------------- of Subsidiary 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 percent and a maturity date of 2025. Item 2. Management's Discussion and Analysis of Consolidated ---------------------------------------------------- Results of Operations and Financial Condition --------------------------------------------- Pacific Gas and Electric Company (PG&E) and its wholly owned and controlled subsidiaries (collectively, the Company) are engaged principally in the business of supplying electric and natural gas services. PG&E is a regulated public utility which provides generation, procurement, transmission and distribution of electricity and natural gas to customers throughout most of Northern and Central California. Pacific Gas Transmission Company (PGT), a wholly owned subsidiary, transports gas from the Canadian border to the California border and the Pacific Northwest. The Company's operations are regulated by the California Public Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC), among others. Building on its expertise in the energy industry, the Company is also expanding its diversified operations, principally through its wholly owned subsidiary, PG&E Enterprises (Enterprises). Enterprises, through its subsidiaries and affiliates, develops, owns and operates electric and gas projects around the world. The following discussion includes forward-looking statements that involve a number of risks and uncertainties including but not limited to the electric and gas industry restructurings and related filings. Importantly, the ultimate impact of increased competition and the changing regulatory environment on future results is uncertain but is expected to cause fundamental changes in the way PG&E conducts its business and to make earnings more volatile. This outcome 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 Company. Electric Industry Restructuring: - ------------------------------- On December 20, 1995, the CPUC issued a decision calling for the restructuring of California's electric industry. The restructuring contemplated in the decision would (1) simultaneously create a wholesale power pool, or Exchange, and allow direct access for certain customers to contract directly with electric generation providers beginning, at the latest, on January 1, 1998, with all customers phased into direct access within five years; (2) establish an Independent System Operator (ISO) to manage and control the transmission system; (3) provide recovery of utilities' stranded costs (costs which are above-market and could not be recovered under market-based pricing) through a non-bypassable surcharge, or competition transition charge (CTC), to be imposed on all customers taking retail electric service as of or after December 20, 1995; and (4) allow investor-owned utilities to continue to provide distribution, generation and procurement functions for those customers choosing to take bundled service from the utilities, all of which would be regulated under performance-based ratemaking (PBR); and (5) provide incentives to encourage voluntary divestiture of at least 50 percent of utilities' fossil fuel generation assets. The decision and subsequent CPUC rulings and workshops have set out an ambitious schedule for various implementation filings and comments through mid-1997. At the federal level, in April 1996, the FERC issued Order 888 which requires utilities to provide wholesale open access to utility transmission systems on terms that are comparable to the way utilities use their own systems. PG&E filed a tariff in compliance with Order 888 in July 1996. PG&E's tariff, which is almost identical to the final tariff issued by the FERC as part of Order 888, is now available for service to any party interested in wholesale transmission service over PG&E's transmission system. In Order 888, the FERC reaffirmed its intention to permit utilities to recover any legitimate, verifiable and prudently incurred generation-related costs stranded as a result of customers taking advantage of wholesale open access orders to meet their power needs from other sources. The FERC also asserted that it has jurisdiction over the transmission aspects of retail direct access, although it reaffirmed its inability to compel retail wheeling. To prepare for competition in electric generation resulting from the CPUC's restructuring decision, PG&E has filed regulatory applications and proposals in three key areas: implementation, ratemaking and CTC recovery. In addition, in June 1996, PG&E entered into a Restructuring Rate Settlement with several parties representing consumers, labor and independent electricity producers. This Settlement endorses the Company's proposed modification of the existing Diablo Canyon Nuclear Power Plant (Diablo Canyon) rate case settlement as modified in 1995 (Diablo Settlement), establishment of a customer electric rate freeze and certain principles governing restructuring of PG&E's electric business which will be reflected in PG&E's filings. In addition, at the California Legislature, a two-house conference committee on Electric Industry Restructuring has been holding hearings and considering legislation which would resolve various issues relating to restructuring of the electric industry. To date, the committee has not adopted any legislative proposals, and the current legislative session ends August 31, 1996. The Company cannot predict whether legislation will in fact be adopted before the end of the legislative session or the substance of any legislation that may be adopted. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the electric industry restructuring and significant filings, proposals and responses to the CPUC's decision. Financial Impact of the Electric Industry Restructuring: In response to a request from the California Legislative Conference Committee on Electric Industry Restructuring, PG&E estimated its transition costs expected to be recovered through the CTC under the restructuring decision. The estimates of transition costs were based on Diablo Canyon revenue requirements, cost recovery of power purchase obligations and generation related regulatory assets, and net cash flows for nonnuclear generation plants. To provide a range of possible transition costs, the estimates used market price assumptions of $.035 and $.025 per kilowatt-hour (kWh) at January 1, 1996, and an annual escalation rate of 3.2 percent. These market prices do not represent a forecast of expected market prices. Factors that could impact market prices include changes in gas prices, changes in inflation rates, levels of new technology costs and the potential oversupply of generation within the market. Based on PG&E's proposal to modify the Diablo Settlement and implement a customer electric rate freeze, the transition costs of PG&E's owned generation assets and power purchase obligations were estimated to be $10.5 billion to $14.0 billion (net present value at January 1998) at assumed market prices of $.035 and $.025 per kWh. PG&E's proposal to modify the Diablo Settlement and implement a customer electric rate freeze accelerates the transition cost recovery period to January 1997 through December 2001 and reduces Diablo Canyon's estimated transition costs by $3.0 billion to $4.0 billion (net present value) at the assumed market prices noted above, as compared to transition costs that would arise under the existing Diablo Settlement. Based on the existing Diablo Settlement, the net present value at January 1998 of transition costs for Diablo Canyon were estimated to be $8.1 billion to $9.6 billion at the assumed market prices noted above. Any forecast of transition costs is inextricably tied to the assumptions made at the time of the analysis. The actual amounts of transition costs may differ materially from those indicated above and will depend on the costs authorized for recovery, the actual market prices of electricity in the future and any market valuations of PG&E's generation assets. On August 30, 1996, PG&E will file its CTC application with the CPUC, which application will identify all transition costs eligible for recovery through the CTC. The CPUC's restructuring decision limits recovery of CTC to an amount that does not increase customers' aggregate rates above those in effect on January 1, 1996. The proposal to modify the Diablo Settlement offers substantial reductions in post-2001 performance-based revenues in exchange for a commitment to freeze customer electric rates through 2001 to allow accelerated collection of utility generation-related CTC. Recent CPUC decisions effective on January 1, 1996, including PG&E's 1996 General Rate Case (GRC), have resulted in an average electric system rate of $.099 per kWh. PG&E believes that the revenues generated under its proposed customer electric rate freeze would be adequate to recover its above-market generation assets by the end of 2001. However, see Utility Revenue Matters below for a description of several pending proceedings relating to 1997 revenues. In addition, PG&E's ability to recover its transition costs will be dependent on several factors, including: (1) the aggregate amount of PG&E's transition costs, which in turn depends on a number of factors, including the expected market value of a portion of its generation plants, future sales levels, fuel and operating costs and the market price of electricity; (2) maintaining electric rates at 1996 levels; and (3) PG&E's ability to continue to collect CTC for the duration of the recovery period. The proposal to modify the Diablo Settlement would significantly reduce the level of PG&E's CTC by reducing the common equity returns on the Diablo Canyon plant investment to 6.77 percent and accelerating the capital recovery of the plant and other utility generation-related assets. If the proposal to freeze customer electric rates is adopted, PG&E will depreciate and recover the Diablo Canyon plant balance beginning January 1, 1997, over five years rather than the current recovery period through 2016. In addition, the proposal would also limit recovery of most utility generation-related CTC to amounts collected through 2001. While it would not adversely affect PG&E's cash flow, PG&E's proposal to modify Diablo Canyon pricing and implement a customer electric rate freeze and to accelerate recovery of utility generation-related investments (including Diablo Canyon) and regulatory assets, would result in a significant reduction in annual earnings beginning in 1997. If the revised return currently contemplated for Diablo Canyon had been adopted for 1995 and PG&E recovered no more than its actual variable costs under the performance-based Incremental Cost Incentive Price (ICIP), Diablo Canyon's earnings available for common stock would have been $115 million, as compared to $492 million. In addition, PG&E's recovery of revenue based on the performance-based ICIP will depend on the capacity factor and variable cost assumptions adopted by the CPUC in implementing PG&E's Diablo Canyon pricing proposal. To the extent that the actual capacity factor or variable expenses are different than those adopted by the CPUC in setting the ICIP price, the Company's earnings would be impacted. The Company currently accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," which allows the Company to capitalize certain costs, that would otherwise have been expensed, as regulatory assets. 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 portions of long- lived assets that are no longer probable of recovery. When electric generation rates are no longer based on cost of service, as ultimately contemplated under the CPUC's restructuring decision, PG&E would discontinue application of SFAS No. 71 for the electric generation portion of its business. As a result, all applicable electric generation-related regulatory assets and other transition costs determined to be probable of CTC recovery would be a regulatory asset collected through cost-of-service based customer rates and subject to the provisions to SFAS No. 71. In addition, the CTC account and electric generation assets will be subject to the criteria of SFAS No. 121. As a result of applying the provisions of SFAS No. 71, PG&E had accumulated approximately $1.5 billion of regulatory assets attributable to electric generation at June 30, 1996. The net investment in Diablo Canyon and the remaining PG&E-owned generation assets, including an allocation of common plant, was approximately $4.8 billion and $2.8 billion, respectively, at June 30, 1996. (The above amounts could vary depending on allocation methods used.) PG&E's transmission and distribution businesses are expected to remain under the provisions of SFAS No. 71. Due to the expected transition cost recovery as provided in the CPUC's restructuring decision and in PG&E's Diablo Canyon pricing/customer electric rate freeze proposal, PG&E does not anticipate a material loss from the discontinuance of SFAS No. 71 or an impairment loss on its investment in generation assets due to electric industry restructuring. However, the Company cannot predict the ultimate outcome of the ongoing changes that are taking place in the electric utility industry or predict whether such outcome will have a material adverse impact on its financial position or results of operations. Should final implementing regulations or any legislation that may be adopted differ significantly from the CPUC's restructuring decision or PG&E's Diablo Canyon pricing/customer electric rate freeze proposal, or should full recovery of generation assets and obligations not be achieved due to changing costs or limitations imposed by the market or should a CPUC ordered customer electric rate reduction occur, a material loss could occur. The Company believes electric industry restructuring will involve a fundamental change in the way it conducts business. These changes will impact financial operating trends, resulting in greater earnings volatility. Gas Industry Restructuring: - -------------------------- In an effort to promote competition and increase options for all customers, as well as to position itself for success in the competitive marketplace, PG&E is actively pursuing changes in the California gas industry. In October 1995, PG&E presented a proposal, called the "Gas Accord," to numerous parties active in the California gas marketplace, including consumer groups, industrial customers, shippers and marketers. PG&E has invited these parties to join it in a collaborative effort to develop a restructuring of the California gas marketplace. The Gas Accord proposes three broad initiatives: (1) Separation of Transmission and Distribution Service and Rates - PG&E proposes to charge separately for, or unbundle, its gas transmission and distribution services. This would give industrial and large commercial (noncore) customers and gas suppliers more flexibility with respect to the purchase of gas transportation services. (2) Increased Customer Choice - Under the Gas Accord, PG&E proposes to give all customers greater ability to choose their gas suppliers in the future. PG&E has formed an advisory group to help it design a program that will facilitate opening of the residential and smaller commercial (core) market to full competition. (3) Resolution of Existing Regulatory Issues - PG&E also proposes to settle several outstanding gas regulatory issues that are currently pending at the CPUC in separate proceedings. These issues include recovery of costs related to PG&E's capacity commitments with Transwestern Pipeline Company (Transwestern), PG&E's capacity commitments with El Paso Natural Gas Company and PGT related to its noncore customers and the PG&E portion of the PGT/PG&E Pipeline Expansion Project. (See Note 3 of Notes to Consolidated Financial Statements.) Negotiations on the Gas Accord began in October 1995. The Gas Accord, if adopted, will result in a change in the way PG&E charges for its transportation services. Any agreement reached by PG&E and other parties must be approved by the CPUC before it may be implemented. PG&E has also proposed a significant change to the current gas ratemaking mechanisms. In December 1994, PG&E filed an application for approval of a core procurement incentive mechanism (CPIM). If approved by the CPUC, the CPIM would replace traditional reasonableness reviews of PG&E's core gas costs with a market benchmark against which PG&E's actual gas costs would be compared. PG&E would be able to recover its gas costs under a mechanism through which PG&E would receive benefits or be penalized depending on whether its actual core procurement costs were within, below or above a "tolerance band" constructed around the benchmark. The CPIM proposal requests authorization to use derivative financial instruments to reduce the risk of gas price and foreign currency fluctuations. Gains, losses and transaction costs associated with the use of derivative financial instruments would be included in the purchased gas account and the measurement against the benchmark. In April 1996, PG&E filed revised CPIM testimony. In the revised CPIM, PG&E has agreed to forgo its right to seek recovery of the core reservation Transwestern costs for the period from 1992 through the end of 1997, provided the revised CPIM is approved by the CPUC in a manner satisfactory to PG&E. Hearings on the revised CPIM were held in June and July 1996. A decision is expected in 1996. Based on the current status of the Gas Accord and CPIM negotiations, the Company believes the ultimate outcome of such negotiations, including resolution of gas regulatory issues, will not have a material adverse impact on its financial position or results of operations. Holding Company Structure: - ------------------------- The PG&E Board of Directors (Board) has authorized, and shareholders and the FERC have approved, a plan to restructure the corporate organization of PG&E and its subsidiaries. The result of the change in corporate structure will be to have PG&E become a separate subsidiary of a parent holding company (ParentCo) with the present holders of PG&E common stock becoming holders of ParentCo common stock. As part of the change in structure, it is contemplated that PG&E will transfer its ownership interests in its two principal subsidiaries, PGT and Enterprises, to ParentCo, so that PGT and Enterprises will become subsidiaries of ParentCo. The debt and preferred stock of PG&E would remain outstanding at the PG&E level and would not become obligations or securities of ParentCo. It is contemplated that these structural changes will be effected as soon as practicable following receipt of all required regulatory approvals, including approval by the CPUC and the NRC. An application for approval by the CPUC was filed by PG&E in October 1995 and PG&E subsequently filed for approval from the NRC. Utility Revenue Matters: - ----------------------- In addition to the CPUC's decision on electric industry restructuring (discussed above and in Note 2 of Notes to Consolidated Financial Statements) and various gas proceedings (see Note 3 of Notes to Consolidated Financial Statements), there are other regulatory matters with respect to revenues and costs which will affect PG&E's rates in 1996 and beyond. In December 1995, the CPUC issued its decision in PG&E's 1996 GRC. Based on the GRC decision and the consolidation of the electric rate cases that became effective January 1, 1996, including the energy cost, cost of capital and various other proceedings, PG&E's electric revenue decreased by $443 million from rates in effect in 1995. The GRC decision and various gas proceedings also resulted in an overall gas revenue decrease of $211 million. The 1996 GRC proceeding was held open to consider, among other things, a study to determine the cost effectiveness of the Helms Pumped Storage Facility (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 as a result of the study, but 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, the Company expects to seek recovery of its net investment in Helms through the hydroelectric/geothermal PBR and CTC mechanisms. The net investment at June 30, 1996, was $713 million comprised of the pumped storage facility (including regulatory assets of $50 million), common plant and dedicated transmission plant. Hearings on PG&E's compliance with call center improvements ordered by the CPUC following severe storms in January and March 1995 have been completed. A proposed decision was issued by a CPUC administrative law judge in July 1996. The proposed decision finds that PG&E complied with all but one of the CPUC performance requirements and recommends a $1.1 million penalty. The proposed decision suspends the penalty since performance targets have been met in 1996. PG&E's service territory experienced additional severe storms and winds in December 1995, which caused approximately 1.7 million electric service interruptions. The assigned commissioner in the 1996 GRC subsequently issued a ruling which ordered hearings on various issues arising from PG&E's response to the December 1995 wind storms. The hearings were also called to address potential remedies, including reparations to customers for reduced reliability, penalties, disallowances and damages to customers for property loss. Hearings were held in June 1996, with a CPUC decision expected in the third quarter of 1996. During March 1996, PG&E filed an application with the CPUC seeking approval to modify Diablo Canyon pricing and adopt a customer electric rate freeze, effective January 1, 1997, which would result in customer electric rates in the years 1997 through 2001 being the same as those in effect on January 1, 1996 (see Note 2 of Notes to Consolidated Financial Statements). The filing seeks to accelerate PG&E's recovery of utility generation-related transition costs caused by electric industry restructuring. This accelerated recovery would increase the 1997 Diablo Canyon revenue requirement by $401 million. To achieve the customer electric rate freeze, PG&E proposes to consolidate the revenue requirement changes resulting from the proposed modification of Diablo Canyon pricing and various other applications PG&E has filed, or will be filing, at the CPUC in 1996. The more significant of these pending applications are discussed below. In July 1996, the CPUC released a draft decision dismissing PG&E's application to increase 1997 base revenues by approximately $156 million. The application requests recovery of expenses for electric distribution operations and maintenance and call center operations and provides for an inflation adjustment. At current levels, these expenses will exceed the amounts authorized in the 1996 GRC. The draft decision concludes that PG&E failed to demonstrate that extraordinary circumstances exist to support an exception to the normal rate case plan, under which base revenues are set only once every three years. The draft decision has been held by the CPUC for future consideration. A final decision has not been issued. If PG&E's application to increase 1997 base revenue is dismissed, PG&E would not receive explicit recovery in rates for expenses, in excess of those authorized in the 1996 GRC, it continues to incur. During April 1996, PG&E filed its 1997 Electric Cost Adjustment Clause (ECAC) application with the CPUC. The filing was corrected by an errata filed in May 1996 and updated in June 1996. The updated filing requests a revenue requirement decrease of approximately $572 million, composed of an ECAC decrease of approximately $533 million, an Annual Energy Rate decrease of approximately $10 million, an Energy Revenue Adjustment Mechanism decrease of approximately $27 million and a California Alternative Rates for Energy decrease of approximately $2 million. In July 1996, the Division of Ratepayer Advocates (DRA) filed its report in PG&E's ECAC proceedings. The DRA recommends a revenue requirement decrease of $684 million which is $112 million greater than the revenue requirement decrease proposed by PG&E. However, in light of PG&E's Diablo Canyon/rate freeze proposal, the DRA recommends that the CPUC suspend implementation of ECAC rate reductions related to 1997 operations until March 31, 1997, on the assumption that this will allow the CPUC to complete its analysis of PG&E's Diablo Canyon/Rate Freeze Proposal. The DRA also recommends that all ECAC revenues accrued from January 1, 1997, until the CPUC issues a decision on the Diablo Canyon/rate freeze proposal be refunded to ratepayers at that time. The DRA recommends that any ECAC overcollection on December 31, 1996, which the DRA estimates will be $88 million, be returned to ratepayers as a one-time refund. The DRA's refund recommendations are inconsistent with PG&E's Diablo Canyon/rate freeze proposal. In August 1996, PG&E filed a motion requesting that the CPUC adopt an interim customer electric rate freeze beginning January 1, 1997, and continuing until the CPUC issues a decision on the Diablo Canyon/rate freeze proposal. This interim customer electric rate freeze will hold PG&E's electric revenue requirement at current authorized levels. PG&E proposes to refund with interest any difference between the interim customer electric rate freeze and rates authorized by the CPUC in its final decision on the Diablo Canyon/rate freeze proposal. In August 1996, the CPUC conditionally approved a joint application by PG&E, SDG&E and SCE which establishes two tax-exempt trusts for the purpose of overseeing the costs associated with the development of the ISO and Exchange. Such costs are estimated to range between $200 and $300 million and would be financed through bank loans to the trust supported by guarantees by PG&E and the other utilities. PG&E's maximum share of the guarantees is $112.5 million. In July 1996, the CPUC approved, with modifications related to labor and development costs, PG&E's request to establish a separate memorandum account to record ISO and Exchange costs incurred by PG&E prior to the establishment of the funding mechanism described above. CPUC approval of the memorandum account does not authorize recovery of the related costs, but instead allows PG&E to seek such recovery at a later date. In July 1996, PG&E submitted an application proposing to establish a PBR mechanism for a portion of its electric generation services and a preliminary unbundling proposal relating to the separation of its electric rates into various components. See Note 2 of Notes to Consolidated Financial Statements for further discussion of these filings. Results of Operations - --------------------- The Company's revenues are derived from three types of operations: utility (excluding Diablo Canyon and including PGT), Diablo Canyon and diversified operations (principally Enterprises). The results of operations for these areas for the three- and six-month periods ended June 30, 1996, and 1995, are reflected in the following table and discussed below.
THREE MONTHS ENDED June 30 Diablo Diversified (in millions, except per share amounts) Utility Canyon Operations Total 1996 Operating revenues $ 1,741 $ 372 $ 26 $ 2,139 Operating expenses 1,579 236 36 1,851 ------- ------ ------ ------- Operating income (loss) before income taxes $ 162 $ 136 $ (10) $ 288 ======= ====== ====== ======= Net income $ 53 $ 58 $ 1 $ 112 ======= ====== ====== ======= Earnings per common share $ .12 $ .13 $ .00 $ .25 ======= ====== ====== ======= 1995 Operating revenues $ 1,857 $ 545 $ 47 $ 2,449 Operating expenses 1,378 190 61 1,629 ------- ------ ------ ------- Operating income (loss) before income taxes $ 479 $ 355 $ (14) $ 820 ======= ====== ====== ======= Net income $ 212 $ 183 $ 11 $ 406 ======= ====== ====== ======= Earnings per common share $ .48 $ .42 $ .02 $ .92 ======= ====== ====== ======= SIX MONTHS ENDED June 30 Diablo Diversified (in millions, except per share amounts) Utility Canyon Operations Total 1996 Operating revenues $ 3,517 $ 812 $ 58 $ 4,387 Operating expenses 3,040 416 69 3,525 ------- ------ ------ ------- Operating income (loss) before income taxes $ 477 $ 396 $ (11) $ 862 ======= ====== ====== ======= Net income $ 179 $ 187 $ 6 $ 372 ======= ====== ====== ======= Earnings per common share $ .41 $ .44 $ .01 $ .86 ======= ====== ====== ======= Total assets at June 30 $19,173 $5,580 $1,005 $25,758 ======= ====== ====== ======= 1995 Operating revenues $ 3,633 $1,009 $ 115 $ 4,757 Operating expenses 2,712 374 142 3,228 ------- ------ ------ ------- Operating income (loss) before income taxes $ 921 $ 635 $ (27) $ 1,529 ======= ====== ====== ======= Net income $ 404 $ 322 $ 8 $ 734 ======= ====== ====== ======= Earnings per common share $ .89 $ .74 $ .02 $ 1.65 ======= ====== ====== ======= Total assets at June 30 $20,012 $5,854 $ 938 $26,804 ======= ====== ====== =======
Earnings Per Common Share: - ------------------------- Utility earnings per common share for the three- and six-month periods ended June 30, 1996, were lower than for the comparable periods in 1995, reflecting revenue reductions authorized in the 1996 GRC and other related rate proceedings. These reductions resulted from lower cost of capital, declining capital expenditures and reductions in authorized expense levels. Actual maintenance and other operating expenses for distribution and customer-related services increased in 1996 and exceeded levels authorized in the 1996 GRC. Also, in July 1996, PG&E settled litigation regarding groundwater contamination near PG&E's Hinkley Compressor Station, resulting in a charge of $.19 per common share. Diablo Canyon earnings per common share for the three- and six-month periods ended June 30, 1996, were lower than for the comparable periods in 1995, due to a greater number of scheduled refueling days and unscheduled outages in 1996. In addition, Diablo Canyon earnings per common share for the current periods were reduced by a decline in the price per kWh as provided in the pricing provisions of the Diablo Settlement. In June 1995, Enterprises completed the sale of DALEN Corporation resulting in a gain of $.03 per common share in the three- and six- month periods ended June 30, 1995. Common Stock Dividend: - --------------------- In July 1996, the Board declared a quarterly dividend of $.49 per common share which corresponds to an annualized dividend of $1.96 per common share. PG&E'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 plans to evaluate the level of its common stock dividend as key issues related to electric industry restructuring are more clearly resolved. Operating Revenues: - ------------------ Operating revenues for the three- and six-month periods ended June 30, 1996, decreased $289 million and $313 million, respectively, compared to the same periods in 1995. The decrease in both electric and gas revenues was due to a decrease in authorized revenues as discussed above. Additionally, Diablo Canyon operating revenues decreased as a result of a decline in the price per kWh generated and a greater number of scheduled refueling days and unscheduled outages in 1996 compared to 1995. Revenues from diversified operations decreased $21 million and $57 million for the three- and six-month periods ended June 30, 1996, respectively, compared to the same periods in 1995, primarily due to Enterprises' sale of DALEN Corporation in June 1995. Operating Expenses: - ------------------ Operating expenses for the three- and six-month periods ended June 30, 1996, increased $222 million and $298 million, respectively, compared to the same periods in 1995, primarily due to increases in maintenance and other operating expenses for distribution and customer-related services and a charge of $133 million for the settlement of a litigation claim regarding groundwater contamination near the Hinkley Compressor Station. Liquidity and Capital Resources - ------------------------------- Sources of Capital: - ------------------ The Company's capital requirements are funded from cash provided by operations and, to the extent necessary, external financing. The Company's policy is to finance its assets with a capital structure that minimizes financing costs, maintains financial flexibility and complies with regulatory guidelines. This policy ensures that the Company can raise capital to meet its utility obligation to serve and its other investment objectives. During the six-month period ended June 30, 1996, PG&E issued $113 million of common stock, primarily through its Dividend Reinvestment Program and Savings Fund Plan. PG&E purchased $135 million of its common stock on the open market during the six-month period ended June 30, 1996. In May 1996, PG&E refinanced $988 million of variable and fixed interest rate pollution control revenue bonds with variable interest rate pollution control revenue bonds. In addition, the Company's short-term borrowings decreased $774 million during the six-month period ended June 30, 1996, as the Company used its cash balances to pay down debt. Acquisition: - ----------- In July 1996, the Company completed its acquisition of State Gas Pipeline, a 376-mile natural gas transportation system in the Australian state of Queensland. The final purchase price was approximately $133 million. Environmental Remediation: - ------------------------- The Company assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation. The Company had accrued a liability at June 30, 1996, of $152 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. The costs may be as much as $364 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions less favorable to the Company, among a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. The Company had recorded a regulatory asset at June 30, 1996, of $132 million for recovery of these costs in future rates. (See Note 5 of Notes to Consolidated Financial Statements.) Legal Matters: - ------------- In the normal course of business, the Company is named as a party in a number of claims and lawsuits. Substantially all of these have been litigated or settled with no material impact on either the Company's results of operations or financial position. Significant litigation cases are discussed in Note 5 of Notes to Consolidated Financial Statements. These cases involve a claim, which was recently settled, relating to groundwater contamination near PG&E's Hinkley Compressor Station and a claim that PG&E underpaid franchise fees. Accounting for Decommissioning Expense: - -------------------------------------- The staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board (FASB) has issued an Exposure Draft of a proposed new accounting standard, "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." The Company would be required to adopt the new standard beginning, at the earliest, January 1, 1998, but may elect to adopt it earlier. If issued by the FASB as proposed, the new standard would require, among other things, that a liability be recognized for decommissioning costs rather than accruing these costs over time as accumulated depreciation, with recognition of an increase in the cost of the related power plant. It would also require, upon initial application, a cumulative-effect adjustment for the effect on retained earnings had the provisions of this proposed Statement been applied when those obligations were incurred. The Company does not believe that such changes, if required, would have an adverse effect on its results of operations due to its current and future ability to recover decommissioning costs through rates. PART II. OTHER INFORMATION --------------------------- Item 1. Legal Proceedings ----------------- Time-of-Use Meter/Customer Notification Litigation As previously reported in PG&E's Form 10-K for the fiscal year ended December 31, 1995, in July 1994, Milton L. Grinstead, Michael Davis, Joan A. Williamson, Frank H. Lacy and Matthew Doerksen filed a complaint in the Stanislaus County Superior Court against PG&E on behalf of themselves and purportedly as a class action on behalf of all of PG&E's customers, for "refund of unlawfully charged fees." The claims of two of the individual plaintiffs were dismissed by the Court in April 1995. The remaining plaintiffs filed an amended complaint in June 1995 which alleged that (a) under certain circumstances, PG&E has a duty to notify a particular customer of the most favorable rate for that customer, and (b) PG&E has systematically failed to reasonably advise new and existing customers of available advantageous rate structures, including the time-of-use billing option. The amended complaint sought classwide damages in excess of $26 billion and exemplary damages of $100 billion. In October 1995, the Court granted PG&E's motion to strike the class and granted summary judgment against one of the remaining plaintiffs. The Court also held that PG&E does not have an obligation to advise customers of their best available rates and is only obligated to give customers notice of rate options. Although the Court's order gave the remaining plaintiffs an opportunity to amend their complaint to state a claim based upon an alleged failure to give them notice of available rate options, an amended complaint was not filed. On March 5, 1996, the Court entered judgment in favor of PG&E. Plaintiffs have not appealed that judgment within the time allowed, and as a result the case has terminated. Item 5. Other Information ----------------- Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends PG&E's earnings to fixed charges ratio for the six months ended June 30, 1996 was 2.68. PG&E's earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 1996 was 2.50. Statements setting forth the computation of the foregoing ratios are filed herewith as Exhibits 12.1 and 12.2 to Registration Statement Nos. 33-62488, 33-64136 and 33-50707. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: Exhibit 3.1 Bylaws effective as of May 15, 1996 Exhibit 3.2 Bylaws effective as of June 19, 1996 Exhibit 11 Computation of Earnings Per Common Share Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends Exhibit 27 Financial Data Schedule (b) Reports on Form 8-K during the second quarter of 1996 and through the date hereof: 1. April 18, 1996 Item 5. Other Events A. Performance Incentive Plan - Year-to-Date Financial Results B. Interim CTC 2. July 19, 1996 Item 5. Other Events A. Performance Incentive Plan - Year-to-Date Financial Results B. Electric Industry Restructuring 1) Performance Based Ratemaking Proposal 2) Unbundling Proposal 3) Market Power Filing C. Hinkley Compressor Station Litigation 3. August 2, 1996 Item 5. Other Events A. Electric Industry Restructuring - Sunk Cost Filing B. California Legislative Conference Committee on Electric Industry Restructuring - Response to Data Request Regarding Stranded Costs SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. PACIFIC GAS AND ELECTRIC COMPANY August 13, 1996 GORDON R. SMITH By______________________________ GORDON R. SMITH Senior Vice President and Chief Financial Officer EXHIBIT INDEX Exhibit Number Exhibit - ------- --------------------------------------- 3.1 Bylaws effective as of May 15, 1996 3.2 Bylaws effective as of June 19, 1996 11 Computation of Earnings Per Common Share 12.1 Computation of Ratios of Earnings to Fixed Charges 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 27 Financial Data Schedule EX-3.1 2 Exhibit 3.1 Bylaws of Pacific Gas and Electric Company as amended as of May 15, 1996 -------------------------------- Article I. SHAREHOLDERS. 1. Place of Meeting. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place within the State of California as may be designated by the Board of Directors. 2. Annual Meetings. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. 3. Special Meetings. Special meetings of the shareholders shall be called by the Secretary or an Assistant Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Secretary or an Assistant Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President or the Secretary. A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. 4. Attendance at Meetings. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Secretary of the Corporation prior to the commencement of the meeting. 5. No Cumulative Voting. No shareholder of the Corporation shall be entitled to cumulate his or her voting power. Article II. DIRECTORS. 1. Number. The Board of Directors shall consist of sixteen (16) directors. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Executive Committee. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. Quorum. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. 7. Action by Consent. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. Meetings by Conference Telephone. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. Article III. OFFICERS. 1. Officers. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, one or more Vice Presidents, a Secretary and one or more Assistant Secretaries, a Treasurer and one or more Assistant Treasurers, a General Counsel, a General Attorney (whenever the Board of Directors in its discretion fills this office), and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. Chairman of the Board. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the President, shall exercise his duties and responsibilities. 3. Vice Chairman of the Board. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. Chairman of the Executive Committee. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. President. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. Vice Presidents. Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 7. Secretary. The Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Secretary. In the absence or disability of the Secretary, his duties shall be performed by an Assistant Secretary. 8. Treasurer. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 9. General Counsel. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 10. Controller. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Article IV. MISCELLANEOUS. 1. Record Date. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. Transfers of Stock. Upon surrender to the Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. Lost Certificates. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. 4. Employee's Stock Purchase Plan. Subject to any limitation contained in the Articles of Incorporation, the Board of Directors may in it discretion, from time to time, authorize the issue and sale of shares of capital stock of this Corporation to employees, pursuant to an employee's stock purchase plan, for such consideration as the Board shall determine to be reasonable. Such plan may provide for payment for such shares by installments over a period of time fixed by the Board. In any such plan, the Board may provide for interest on any installment payments, and that an employee may cancel his agreement to purchase all or part of the shares thereunder. The Board may fix such other terms and conditions for any such plan as it shall deem, in its discretion, to be in the best interests of this Corporation. Any such plan may include employees of: This Corporation's subsidiaries and affiliates; Pacific Service Employees Association; Pacific Service Federal Credit Union; and such other associated organizations as may be approved by the Board. Article V. AMENDMENTS. 1. Amendment by Shareholders. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. Amendment by Directors. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. EX-3.2 3 Exhibit 3.2 Bylaws of Pacific Gas and Electric Company as amended as of June 19, 1996 Article I. SHAREHOLDERS. 1. Place of Meeting. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place within the State of California as may be designated by the Board of Directors. 2. Annual Meetings. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. 3. Special Meetings. Special meetings of the shareholders shall be called by the Secretary or an Assistant Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Secretary or an Assistant Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President or the Secretary. A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. 4. Attendance at Meetings. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Secretary of the Corporation prior to the commencement of the meeting. 5. No Cumulative Voting. No shareholder of the Corporation shall be entitled to cumulate his or her voting power. Article II. DIRECTORS. 1. Number. The Board of Directors shall consist of sixteen (16) directors. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Executive Committee. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. Quorum. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. 7. Action by Consent. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. Meetings by Conference Telephone. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. Article III. OFFICERS. 1. Officers. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, one or more Vice Presidents, a Secretary and one or more Assistant Secretaries, a Treasurer and one or more Assistant Treasurers, a General Counsel, a General Attorney (whenever the Board of Directors in its discretion fills this office), and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. Chairman of the Board. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the President, shall exercise his duties and responsibilities. 3. Vice Chairman of the Board. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. Chairman of the Executive Committee. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. President. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. Vice Presidents. Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 7. Secretary. The Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Secretary. In the absence or disability of the Secretary, his duties shall be performed by an Assistant Secretary. 8. Treasurer. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 9. General Counsel. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 10. Controller. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. He shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors. Article IV. MISCELLANEOUS. 1. Record Date. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. Transfers of Stock. Upon surrender to the Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. Lost Certificates. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. 4. Employee's Stock Purchase Plan. Subject to any limitation contained in the Articles of Incorporation, the Board of Directors may in it discretion, from time to time, authorize the issue and sale of shares of capital stock of this Corporation to employees, pursuant to an employee's stock purchase plan, for such consideration as the Board shall determine to be reasonable. Such plan may provide for payment for such shares by installments over a period of time fixed by the Board. In any such plan, the Board may provide for interest on any installment payments, and that an employee may cancel his agreement to purchase all or part of the shares thereunder. The Board may fix such other terms and conditions for any such plan as it shall deem, in its discretion, to be in the best interests of this Corporation. Any such plan may include employees of: This Corporation's subsidiaries and affiliates; Pacific Service Employees Association; Pacific Service Federal Credit Union; and such other associated organizations as may be approved by the Board. Article V. AMENDMENTS. 1. Amendment by Shareholders. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. Amendment by Directors. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. EX-11 4 EXHIBIT 11 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF EARNINGS PER COMMON SHARE (unaudited)
- -------------------------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, -------------------- -------------------- (in thousands, except per share amounts) 1996 1995 1996 1995 - -------------------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Net income $111,780 $405,520 $372,484 $734,207 Less: preferred dividend requirement and redemption premium 8,278 14,494 16,556 28,988 -------- -------- -------- -------- Net income for calculating EPS for Statement of Consolidated Income $103,502 $391,026 $355,928 $705,219 ======== ======== ======== ======== Average common shares outstanding 415,125 426,621 414,738 428,344 ======== ======== ======== ======== EPS as shown in the Statement of Consolidated Income $ .25 $ .92 $ .86 $ 1.65 ======== ======== ======== ======== PRIMARY EPS (1) Net income $111,780 $405,520 $372,484 $734,207 Less: preferred dividend requirement and redemption premium 8,278 14,494 16,556 28,988 -------- -------- -------- -------- Net income for calculating primary EPS $103,502 $391,026 $355,928 $705,219 ======== ======== ======== ======== Average common shares outstanding 415,125 426,621 414,738 428,344 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at average market price) 8 133 20 88 -------- -------- -------- -------- Average common shares outstanding as adjusted 415,133 426,754 414,758 428,432 ======== ======== ======== ======== Primary EPS $ .25 $ .92 $ .86 $ 1.65 ======== ======== ======== ======== FULLY DILUTED EPS (1) Net income $111,780 $405,520 $372,484 $734,207 Less: preferred dividend requirement and redemption premium 8,278 14,494 16,556 28,988 -------- -------- -------- -------- Net income for calculating fully diluted EPS $103,502 $391,026 $355,928 $705,219 ======== ======== ======== ======== Average common shares outstanding 415,125 426,621 414,738 428,344 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at the greater of average or ending market price) 9 184 20 184 -------- -------- -------- -------- Average common shares outstanding as adjusted 415,134 426,805 414,758 428,528 ======== ======== ======== ======== Fully diluted EPS $ .25 $ .92 $ .86 $ 1.65 ======== ======== ======== ======== - -------------------------------------------------------------------------------------------- (1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K. This presentation is not required by APB Opinion No. 15, because it results in dilution of less than 3%.
EX-12.1 5 EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- ---------------------------------------------------------------------------------------------------- Six Months Year ended December 31, Ended ---------------------------------------------------------- (dollars in thousands) 6/30/96 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------- Earnings: Net income $ 372,484 $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392 Adjustments for minority interests in losses of less than 100% owned affiliates and the undistributed losses (income) of less than 50% owned affiliates (4,430) 3,820 (2,764) 6,895 (3,349) 26,671 Income tax expense 219,297 895,289 836,767 901,890 895,126 851,534 Net fixed charges 349,457 715,975 730,965 821,166 802,198 776,682 ---------- ---------- ---------- ---------- ---------- ---------- Total Earnings $ 936,808 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279 ========== ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 290,641 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185 Interest on short- term borrowings 44,874 83,024 77,295 87,819 61,182 77,760 Interest on capital leases 1,781 2,735 1,758 1,737 1,737 1,737 Capitalized interest 192 957 2,660 46,055 6,511 6,107 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned subsidiaries 12,378 3,306 - - - - ---------- ---------- ---------- ---------- ---------- ---------- Total Fixed Charges $ 349,866 $ 717,397 $ 733,625 $ 867,221 $ 808,709 $ 782,789 ========== ========== ========== ========== ========== ========== Ratios of Earnings to Fixed Charges 2.68 4.12 3.51 3.22 3.54 3.43 - --------------------------------------------------------------------------------------------------- Note: For the purpose of computing the Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, the Company's equity in undistributed income or loss of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term and short-term borrowings (including a representative portion of rental expense); amortization of bond premium, discount and expense; interest on capital leases; pretax earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries; and after-tax earnings required to cover the preferred security distribution requirements of majority owned subsidiaries.
EX-12.2 6 EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- --------------------------------------------------------------------------------------------------- Six Months Year ended December 31, Ended ---------------------------------------------------------- (dollars in thousands) 6/30/96 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------- Earnings: Net income $ 372,484 $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates (4,430) 3,820 (2,764) 6,895 (3,349) 26,671 Income tax expense 219,297 895,289 836,767 901,890 895,126 851,534 Net fixed charges 349,457 715,975 730,965 821,166 802,198 776,682 ---------- ---------- ---------- ---------- ---------- ---------- Total Earnings $ 936,808 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279 ========== ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 290,641 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185 Interest on short- term borrowings 44,874 83,024 77,295 87,819 61,182 77,760 Interest on capital leases 1,781 2,735 1,758 1,737 1,737 1,737 Capitalized interest 192 957 2,660 46,055 6,511 6,107 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned subsidiaries 12,378 3,306 - - - - ---------- ---------- ---------- ---------- ---------- ---------- Total Fixed Charges 349,866 717,397 733,625 867,221 808,709 782,789 ---------- ---------- ---------- ---------- ---------- ---------- Preferred Stock Dividends: Tax deductible dividends 5,029 11,343 4,672 4,814 5,136 5,136 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 19,552 99,984 96,039 108,937 130,147 154,404 ---------- ---------- ---------- ---------- ---------- ---------- Total Preferred Stock Dividends 24,581 111,327 100,711 113,751 135,283 159,540 ---------- ---------- ---------- ---------- ---------- ---------- Total Combined Fixed Charges and Preferred Stock Dividends $ 374,447 $ 828,724 $ 834,336 $ 980,972 $ 943,992 $ 942,329 ========== ========== ========== ========== ========== ========== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 2.50 3.56 3.08 2.85 3.03 2.85 - --------------------------------------------------------------------------------------------------- Note: For the purpose of computing the Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, the Company's equity in undistributed income or loss of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense); amortization of bond premium, discount and expense; interest on capital leases; pretax earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries; and the after-tax earnings required to cover the preferred security distribution requirements of majority owned subsidiaries. "Preferred stock dividends" represent the sum of requirements for preferred stock dividends that are deductible for federal income tax purposes increased to an amount representing pretax earnings which would be required to cover such dividend requirements.
EX-27 7
UT 1,000 6-MOS DEC-31-1996 JUN-30-1996 PER-BOOK 18,795,564 1,780,165 2,572,404 2,609,968 0 25,758,101 2,064,488 3,753,964 2,700,704 8,519,156 437,500 402,056 7,923,496 0 0 56,073 221,133 0 0 0 8,198,687 25,758,101 4,387,434 219,297 3,525,665 3,525,665 861,769 65,424 927,193 335,412 372,484 16,556 355,928 404,138 0 1,378,001 0.86 0.86
-----END PRIVACY-ENHANCED MESSAGE-----