-----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, Q1eDDyi7o0t+eyOofaUIxk/lCIGVauD1WqBflDh0WTaSJFc+A2iSQDK/qPx6l+Mj 7wPlt6lIMrHNH8DQzgL3tA== 0000075488-96-000008.txt : 19960513 0000075488-96-000008.hdr.sgml : 19960513 ACCESSION NUMBER: 0000075488-96-000008 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19960331 FILED AS OF DATE: 19960510 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: 96558894 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 March 31, 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 April 29, 1996 --------------- -------------------------------- Common Stock, $5 par value 416,718,710 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.............. 12 Note 4: Diablo Canyon............................. 14 Note 5: Contingencies Nuclear Insurance....................... 15 Environmental Remediation............... 15 Helms Pumped Storage Plant.............. 16 Legal Matters........................... 16 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......................... 25 Holding Company Structure.......................... 26 Utility Revenue Matters............................ 26 Results of Operations.............................. 29 Earnings Per Common Share........................ 29 Common Stock Dividend............................ 30 Operating Revenues............................... 30 Operating Expenses............................... 30 Liquidity and Capital Resources Sources of Capital............................... 31 Acquisition...................................... 31 Environmental Remediation........................ 31 Legal Matters.................................... 31 Other Matters New Accounting Standard.......................... 32 Accounting for Decommissioning Expense........... 32 PART II. OTHER INFORMATION - --------------------------- Item 1. Legal Proceedings Diablo Canyon Environmental Litigation............. 33 California Attorney General Litigation............. 34 Norcen Litigation.................................. 34 Table of Contents (continued) Page ---- Item 4. Submission of Matters to a Vote of Security-Holders................................... 35 Item 5. Other Information Pending Electric Reasonableness Issue.............. 36 Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends............ 37 Item 6. Exhibits and Reports on Form 8-K..................... 37 SIGNATURE...................................................... 39 PART 1. FINANCIAL INFORMATION Item 1. Consolidated Financial Statements --------------------------------- PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME (unaudited)
- -------------------------------------------------------------------------------------------- Three months ended March 31, --------------------------- (in thousands, except per share amounts) 1996 1995 - -------------------------------------------------------------------------------------------- OPERATING REVENUES Electric utility $1,648,602 $1,696,786 Gas utility 568,811 544,095 Diversified operations 31,355 67,366 ---------- ---------- Total operating revenues 2,248,768 2,308,247 ---------- ---------- OPERATING EXPENSES Cost of electric energy 466,994 404,723 Cost of gas 188,137 103,563 Maintenance and other operating 456,474 421,954 Depreciation and decommissioning 302,947 352,183 Administrative and general 179,379 261,121 Workforce reduction costs - (18,195) Property and other taxes 81,443 73,869 ---------- ---------- Total operating expenses 1,675,374 1,599,218 ---------- ---------- OPERATING INCOME 573,394 709,029 ---------- ---------- OTHER INCOME AND (INCOME DEDUCTIONS) Interest income 24,343 15,326 Allowance for equity funds used during construction 2,757 5,638 Other--net 5,682 (2,468) ---------- ---------- Total other income and (income deductions) 32,782 18,496 ---------- ---------- INCOME BEFORE INTEREST EXPENSE 606,176 727,525 ---------- ---------- INTEREST EXPENSE Interest on long-term debt 153,167 162,149 Other interest charges 22,318 14,776 Allowance for borrowed funds used during construction (1,557) (2,876) ---------- ---------- Net interest expense 173,928 174,049 ---------- ---------- PRETAX INCOME 432,248 553,476 ---------- ---------- INCOME TAXES 171,544 224,789 ---------- ---------- NET INCOME 260,704 328,687 Preferred dividend requirement and redemption premium 8,278 14,494 ---------- ---------- EARNINGS AVAILABLE FOR COMMON STOCK $ 252,426 $ 314,193 ========== ========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 414,351 430,086 EARNINGS PER COMMON SHARE $.61 $.73 DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49 - -------------------------------------------------------------------------------------------- The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (unaudited)
- -------------------------------------------------------------------------------------------- March 31, December 31, (in thousands) 1996 1995 - -------------------------------------------------------------------------------------------- ASSETS PLANT IN SERVICE Electric Nonnuclear $17,741,094 $17,513,830 Diablo Canyon 6,669,967 6,646,853 Gas 7,788,397 7,732,681 ----------- ----------- Total plant in service (at original cost) 32,199,458 31,893,364 Accumulated depreciation and decommissioning (13,635,412) (13,308,596) ----------- ----------- Net plant in service 18,564,046 18,584,768 ----------- ----------- CONSTRUCTION WORK IN PROGRESS 243,666 333,263 OTHER NONCURRENT ASSETS Nuclear decommissioning funds 799,359 769,829 Investments in nonregulated projects 899,234 869,674 Other assets 129,309 130,128 ----------- ----------- Total other noncurrent assets 1,827,902 1,769,631 ----------- ----------- CURRENT ASSETS Cash and cash equivalents 989,526 734,295 Accounts receivable Customers 929,851 1,238,549 Other 69,027 65,907 Allowance for uncollectible accounts (34,267) (35,520) Regulatory balancing accounts receivable 888,756 746,344 Inventories Materials and supplies 186,957 181,763 Gas stored underground 108,760 146,499 Fuel oil 30,853 40,756 Nuclear fuel 178,507 175,957 Prepayments 32,919 47,025 ----------- ----------- Total current assets 3,380,889 3,341,575 ----------- ----------- DEFERRED CHARGES Income tax-related deferred charges 1,056,118 1,079,673 Diablo Canyon costs 378,003 382,445 Unamortized loss net of gain on reacquired debt 387,575 392,116 Workers' compensation and disability claims recoverable 291,960 297,266 Other 504,179 669,553 ----------- ----------- Total deferred charges 2,617,835 2,821,053 ----------- ----------- TOTAL ASSETS $26,634,338 $26,850,290 =========== =========== - -------------------------------------------------------------------------------------------- (continued on next page)
PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (unaudited)
- -------------------------------------------------------------------------------------------- March 31, December 31, (in thousands) 1996 1995 - -------------------------------------------------------------------------------------------- CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock $ 2,073,473 $ 2,070,128 Additional paid-in capital 3,749,153 3,716,322 Reinvested earnings 2,836,255 2,812,683 ----------- ----------- Total common stock equity 8,658,881 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 7,985,999 8,048,546 ----------- ----------- Total capitalization 17,484,436 17,487,235 ----------- ----------- OTHER NONCURRENT LIABILITIES Customer advances for construction 140,005 146,191 Workers' compensation and disability claims 271,400 271,000 Other 724,704 815,960 ----------- ----------- Total other noncurrent liabilities 1,136,109 1,233,151 ----------- ----------- CURRENT LIABILITIES Short-term borrowings 763,304 829,947 Long-term debt 230,342 304,204 Accounts payable Trade creditors 298,489 413,972 Other 429,959 387,747 Accrued taxes 466,071 274,093 Deferred income taxes 226,106 227,782 Interest payable 158,032 70,179 Dividends payable 211,445 205,467 Other 407,716 504,973 ----------- ----------- Total current liabilities 3,191,464 3,218,364 ----------- ----------- DEFERRED CREDITS Deferred income taxes 3,894,880 3,933,765 Deferred tax credits 391,848 393,255 Noncurrent balancing account liabilities 192,640 185,647 Other 342,961 398,873 ----------- ----------- Total deferred credits 4,822,329 4,911,540 CONTINGENCIES (Notes 2, 3 and 5) ----------- ----------- TOTAL CAPITALIZATION AND LIABILITIES $26,634,338 $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)
- -------------------------------------------------------------------------------------------- Three months ended March 31, --------------------------- (in thousands) 1996 1995 - -------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 260,704 $ 328,687 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and decommissioning 302,947 352,183 Amortization 24,204 33,316 Deferred income taxes and tax credits--net (16,606) (65,603) Allowance for equity funds used during construction (2,757) (5,638) Other deferred charges 88,982 (17,450) Other noncurrent liabilities (23,042) (6,396) Noncurrent balancing account liabilities and other deferred credits (48,919) (37,674) Net effect of changes in operating assets and liabilities Accounts receivable 304,325 218,891 Regulatory balancing accounts receivable (142,412) 253,216 Inventories 42,448 36,611 Accounts payable (73,271) (37,477) Accrued taxes 191,978 246,313 Other working capital 4,702 2,479 Other-net 17,880 45,827 --------- ---------- Net cash provided by operating activities 931,163 1,347,285 --------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (216,880) (197,051) Allowance for borrowed funds used during construction (1,557) (2,876) Investments in nonregulated projects (38,339) (34,640) Other--net (20,189) (54,241) --------- ---------- Net cash used by investing activities (276,965) (288,808) --------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock issued 57,657 66,871 Common stock repurchased (39,364) (110,316) Long-term debt matured, redeemed or repurchased (137,343) (149,250) Short-term debt redeemed--net (66,643) (382,246) Dividends paid (211,576) (225,875) Other--net (1,698) (1,820) --------- ---------- Net cash used by financing activities (398,967) (802,636) --------- ---------- NET CHANGE IN CASH AND CASH EQUIVALENTS 255,231 255,841 CASH AND CASH EQUIVALENTS AT JANUARY 1 734,295 136,900 --------- ---------- CASH AND CASH EQUIVALENTS AT MARCH 31 $ 989,526 $ 392,741 ========= ========== Supplemental disclosures of cash flow information Cash paid for Interest (net of amounts capitalized) $ 73,402 $ 89,689 Income taxes 45,638 43,975 - -------------------------------------------------------------------------------------------- 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 - ---------------------------------------- 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; and (3) provide recovery of utilities' stranded 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. The decision, while effective immediately, provided for a series of implementation filings to be made in order to achieve the January 1998 start date for the restructured industry. Under the restructuring decision, PG&E would continue to provide distribution, generation and procurement functions for those customers choosing to take bundled service, all of which would be regulated under performance-based ratemaking. The decision requires PG&E to file proposals to establish performance-based ratemaking for its generation and distribution functions. The CPUC concluded that market power issues associated with the electric industry restructuring almost certainly mandate that the investor-owned utilities (IOUs) divest themselves of a substantial portion of their fossil fuel generation assets. Accordingly, the decision required PG&E to file a plan to voluntarily divest at least 50 percent of its fossil fuel generation assets. In March 1996, PG&E filed comments with the CPUC on divestiture of fossil fuel generation assets, as discussed below. The decision provides for the collection of transition costs through the imposition of a non-bypassable CTC. Transition cost recovery would not increase rates beyond the rate levels in effect as of January 1, 1996. A transition cost account would be established for each utility. Transition costs associated with regulatory assets would be included in the account as authorized by the CPUC. The account would be adjusted annually for the difference between authorized revenues associated with the generation assets and actual revenues earned in the market as well as after a generation asset receives its market valuation. Valuation of above-market generation assets would be completed by 2003. Utility nonnuclear generation assets would be valued through sale, spin-off or market appraisal. Transition costs resulting from the operation of nuclear generation facilities and electricity purchases under existing wholesale and qualifying facility (QF) contracts would also be recorded in this account. Transition costs for these resources would be calculated annually over the terms of the contracts or until the authorized transition cost recovery has been completed. Except for existing QF generation contracts with contractual payments beyond 2003, all transition costs would be collected by 2005. With respect to recovery of costs associated with PG&E's Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the Diablo Canyon rate case settlement as modified in 1995 (Diablo Settlement), the decision confirms that the CPUC will continue to honor regulatory commitments regarding the recovery of nuclear generation costs. Under the CPUC restructuring decision, Diablo Canyon transition costs would be calculated over the term of the Diablo Settlement. The decision required PG&E to file a proposal for pricing Diablo Canyon generation at market prices by 2003 and for completing recovery of Diablo Canyon CTC by 2005 while assuring no overall rate increase over January 1, 1996, levels. If PG&E retains ownership of Diablo Canyon, decommissioning costs would also be included in the transition cost account. In March 1996, PG&E filed an application with the CPUC to modify the Diablo Settlement and adopt a customer electric rate freeze, as discussed below. Recent Developments in the Electric Industry Restructuring: As directed by the CPUC decision, PG&E has made filings with the CPUC on various aspects of the electric industry restructuring. In March 1996, PG&E filed comments 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. PG&E also filed comments 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. Also 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 electric rate freeze, effective January 1, 1997. The application would reduce the amount of Diablo Canyon transition costs by over $3.7 billion (net present value) 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. The filing would accelerate PG&E's recovery of utility generation- related transition costs caused by industry restructuring without raising customer rates. PG&E's application would result in the termination of the Diablo Settlement by the end of 2001, so that Diablo Canyon generation may be priced at market levels consistent with the goals of the CPUC 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 as of December 31, 1996, depreciated over a five-year period and subject to a reduced return on common equity equal to 6.77 percent. 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, if Diablo Canyon is shut down for nine months or more prior to such time as transition costs are fully recovered, would be subject to CPUC evaluation. After such time as transition costs are fully recovered, there would be no restrictions on Diablo Canyon's operations or 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 modified Diablo Canyon pricing proposal. In the event that the CPUC is unable to adopt the proposed rate freeze, PG&E would withdraw its proposal to price Diablo Canyon generation and instead would propose an alternative modification of Diablo Canyon pricing. In April 1996, PG&E, San Diego Gas and Electric Company and Southern California Edison Company filed joint ISO and Exchange applications with the Federal Energy Regulatory Commission (FERC) and CPUC. These applications request 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. The ISO would manage the dispatch of electric generation, manage access to the transmission system and assure safe, reliable operation of the state's power grid. The Exchange would conduct a daily auction among buyers and sellers to determine the spot market price for power. PG&E and the other utilities also filed a request for a declaratory order from the FERC confirming the utilities' designation of transmission facilities to be transferred to ISO control, and confirming the states' jurisdiction over local distribution facilities for rate and transition cost collection purposes. PG&E intends to file an application with the CPUC in May 1996 seeking funding for costs associated with the establishment of the ISO and Exchange. 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 1998. At that time, amounts paid on an interim basis will be subject to true-up to reflect the CPUC's final CTC methodology and allocation of CTC to customer classes. Pursuant to the CPUC's decision establishing an interim CTC procedure, interested parties engaged in a collaboration in an attempt to set an interim CTC level consistent with the principles set forth in the CPUC decision. Since no consensus was reached among the parties, the unresolved issues will be referred to a CPUC administrative law judge (ALJ) to prepare a recommended decision for CPUC approval. The CPUC is expected to establish the interim CTC in 1996. Also 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 how utilities use their own systems. 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. In the coming months, PG&E will be making additional filings with the CPUC and FERC on other aspects of the electric industry restructuring, as directed by the December 20, 1995, decision. Financial Impact of the Electric Industry Restructuring: In December 1994, in response to one of the proceedings leading to the CPUC electric industry restructuring decision, PG&E estimated the revenue requirements of its owned generation assets and power purchase obligations to be above market by $3 billion and $11 billion (net present value) at assumed market prices of $.040 and $.032 per kWh, respectively. These market prices were used to provide a range of possible transition costs and do not represent a forecast of expected market prices. Market prices could be less than $.032 per kWh. The above-market estimates filed in December 1994 were determined by comparing future revenue requirements of generation assets and power purchase obligations, over a 20-year and 30-year period, respectively, with revenues computed at assumed market prices. Diablo Canyon was included in the revenue requirement calculation using the pricing included in the Diablo Settlement. (See Note 4.) The revenue requirements for Diablo Canyon and all PG&E-owned generation assets included a return on investment. The actual amounts of above-market revenue requirements may differ materially from those indicated above and will depend on the final regulations and the actual market prices of electricity or a definitive market valuation. Based on the pricing included in the Diablo Settlement, the net present values of above-market revenue requirements for Diablo Canyon included in the December 1994 estimates were $4 billion and $6 billion at assumed market prices of $.040 and $.032 per kWh, respectively. Also based on the pricing included in the Diablo Settlement, the net present value of above-market revenue requirements for Diablo Canyon is estimated to be $10 billion at a market price of $.025 per kWh, which reflects PG&E's current estimate of the market price beginning in 1997. The CPUC electric industry restructuring decision establishes an account to track the accumulation of transition costs and their recovery. While the decision provides an opportunity for recovery of all above-market costs, actual recovery of the CTC will be limited to an amount that does not increase the customers' aggregate rates above those in effect on January 1, 1996. 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's ability to recover its transition costs will be dependent on achieving overall reductions in costs such that it can recover its ongoing operating costs, capital costs and transition costs at the 1996 rate level and on continuing to collect CTC for the duration of the recovery period. As a result of applying the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," PG&E has accumulated approximately $2.5 billion of electric regulatory assets, including balancing accounts, at March 31, 1996. The regulatory assets attributable to electric generation, excluding balancing accounts of $173 million which are expected to be recovered in the near term, were approximately $1.4 billion at March 31, 1996. When generation rates are no longer based on cost of service, as ultimately contemplated under the decision, PG&E will discontinue application of SFAS No. 71 for that portion of its business. However, PG&E expects to recover its generation regulatory assets as transition costs through the CTC and does not expect a material loss from the discontinuance of SFAS No. 71. PG&E's transmission and distribution businesses are expected to remain under the provisions of SFAS No. 71. In addition, the adoption of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," in 1996 requires that regulatory assets continue to be probable of recovery in rates. In the event that this criterion can no longer be met, whether due to changing regulation or PG&E's inability to collect these costs, applicable portions of any regulatory assets would be written off. The transition cost account will be a regulatory asset also subject to the criteria of SFAS No. 121. The CPUC restructuring decision provides a structure for full recovery of PG&E's generation assets and costs through market prices and the CTC. The proposed modification to 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. If accepted, the proposed modification will significantly reduce the level of PG&E's CTC and earnings 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 at January 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. As of March 31, 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 $3.0 billion, respectively, and regulatory assets attributable to electric generation (excluding balancing accounts expected to be recovered in the near term) were approximately $1.4 billion. Because of the expected transition cost recovery as provided in the decision, PG&E does not anticipate a material impairment loss on its investment in generation assets due to electric industry restructuring. However, should final implementing regulations differ significantly from the CPUC decision or should full recovery of generation assets and obligations not be achieved due to changing costs or limitations imposed by the market, a material loss could occur. 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 impact on its financial position or results of operations. 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 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 CPUC's Division Ratepayer Advocates (DRA) have signed a settlement agreement to resolve these issues for a $67 million refund by PG&E. As of March 31, 1996, PG&E has accrued approximately $150 million for the CPUC decision and issues covered by the settlement agreement described above. The Company believes the ultimate outcome of these matters will not have a material impact on its financial position or results of operations. Settlement of certain other unresolved gas issues is being negotiated as part of the Gas Accord negotiations discussed below. 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 $223 million disallowance or reallocation of costs among customers. 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. 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. 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. 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 settlement of that rate case with the FERC for approval. Decisions in these proceedings are expected in 1996. Revenues are currently being collected under interim rates approved by the FERC and the CPUC, subject to adjustment. Transportation Commitments: - -------------------------- PG&E has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for 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 as of March 31, 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 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. 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. The modification provides that the difference between PG&E's revenue requirements under the original Diablo Settlement prices and the modified prices be applied to PG&E's energy cost balancing account until the undercollection in that account as of December 31, 1995, is fully amortized. 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 both pricing Diablo Canyon generation at market prices and completing recovery of Diablo Canyon CTC by the end of 2001 while assuring no overall rate increase over January 1, 1996, levels. PG&E proposes to accelerate recovery of the undepreciated portion of Diablo Canyon, at a significantly reduced return of 6.77 percent, and to include performance-based prices for recovery of variable costs and incremental capital additions. In addition to modifying the pricing provisions of the existing Diablo Settlement, PG&E's proposal would eliminate or replace certain payment provisions and change the Diablo Settlement termination date from 2016 to December 31, 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; federal Superfund law) or the California Hazardous Substance Account Act (California Superfund law). 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 March 31, 1996, of $126 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. The costs may be as much as $292 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. 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 $719 million at March 31, 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 in December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of Helms, to be submitted in July 1996. The study will consider changes in rate recovery for the plant which will include, among other things, the option of retirement with recovery of the investment without a return over a four-year period. PG&E is currently unable to predict whether there will be a change in rate recovery resulting from the study. 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. The original complaint has been amended, and additional complaints have been filed to include additional plaintiffs. The plaintiffs contend that PG&E discharged chromium-contaminated wastewater into unlined ponds to avoid costly alternatives, which led to chromium percolating into the groundwater of surrounding property. PG&E has reached an agreement with plaintiffs pursuant to which those plaintiffs' actions will be submitted to binding arbitration for resolution of issues concerning the cause and extent of any damages suffered by plaintiffs as a result of the alleged chromium contamination. Under the terms of the agreement, PG&E will pay an aggregate amount of no more than $400 million in settlement of such plaintiffs' claims. In turn, those plaintiffs, and their attorneys, agree to indemnify PG&E against any additional losses PG&E may incur with respect to related claims pursued by the identified plaintiffs who do not agree to this settlement or by other third parties who may be sued by the plaintiffs in connection with the alleged chromium contamination. As of March 31, 1996, PG&E has paid $50 million to escrow and recorded an additional $150 million reserve against any future potential liability in this case. The Company believes the ultimate outcome of this matter will not have a material adverse impact on its financial position or results of operations. 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 granted PG&E's motions for summary judgment against certain plaintiffs effectively eliminating a major portion of the class action. The Court's rulings do not resolve the case completely. 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 $33 million as of March 31, 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 cities 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). 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% 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 some forward looking information. 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, by a three to two vote, 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; and (3) provide recovery of utilities' stranded costs 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. The decision, while effective immediately, sets out an ambitious schedule for various implementation filings and comments over the period ending in October 1996. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the electric industry restructuring. Recent Developments in the Electric Industry Restructuring: As directed by the CPUC decision, PG&E has made filings with the CPUC on various aspects of the electric industry restructuring. In March 1996, PG&E filed comments 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. Options for divestiture include creation of a new unaffiliated corporate entity to hold the assets, sale on the open market, negotiation with individual potential buyers in special circumstances, leasing facilities and/or sale 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 also filed comments 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. In its comments, PG&E indicated for the time being it sees no obvious benefits from separating its generation, transmission and distribution functions into separate corporate subsidiaries. PG&E believes that the operational and functional separation which exists by virtue of its business unit structure, combined with the self-dealing restraints imposed by the CPUC decision, provide sufficient safeguards to prevent cross-subsidization and self-dealing. However, PG&E believes it may be appropriate in the future to separate out any generation it retains and that such separation would be consistent with the holding company structure it proposed in a filing with the CPUC in October 1995. Also in March 1996, PG&E filed an application with the CPUC seeking approval to modify the existing Diablo Canyon Nuclear Power Plant (Diablo Canyon) rate case settlement (Diablo Settlement) contingent upon the adoption of a five-year electric rate freeze, effective January 1, 1997. The application would reduce the amount of Diablo Canyon transition costs by over $3.7 billion (net present value) 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. The filing would accelerate PG&E's recovery of utility generation- related transition costs caused by industry restructuring without raising customer rates. PG&E's application would result in the termination of the Diablo Settlement by the end of 2001, so that Diablo Canyon generation may be priced at market levels consistent with the goals of the CPUC 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 as of December 31, 1996, depreciated over a five-year period and subject to a reduced return on common equity equal to 6.77 percent. 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. In its filing, the Company estimated such variable costs and incremental capital additions would be $552 million in 1997. 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, if Diablo Canyon is shut down for nine months or more prior to such time as transition costs are fully recovered, would be subject to CPUC evaluation. After such time as transition costs are fully recovered, there would be no restrictions on Diablo Canyon's operations or 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 modified Diablo Canyon pricing proposal. In the event that the CPUC is unable to adopt the proposed rate freeze, PG&E would withdraw its proposal to price Diablo Canyon generation and instead would propose an alternative modification of Diablo Canyon pricing. In April 1996, PG&E, San Diego Gas and Electric Company and Southern California Edison Company filed joint ISO and Exchange applications with the FERC and CPUC. These applications request 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. The ISO would manage the dispatch of electric generation, manage access to the transmission system and assure safe, reliable operation of the state's power grid. The Exchange would conduct a daily auction among buyers and sellers to determine the spot market price for power. PG&E and the other utilities also filed a request for a declaratory order from the FERC confirming the utilities' designation of transmission facilities to be transferred to ISO control and confirming the states' jurisdiction over local distribution facilities for rate and transition cost collection purposes. PG&E intends to file an application with the CPUC in May 1996 seeking funding for costs associated with the establishment of the ISO and Exchange. 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 1998. At that time, amounts paid on an interim basis will be subject to true-up to reflect the CPUC's final CTC methodology and allocation of CTC to customer classes. Pursuant to the CPUC's decision establishing an interim CTC procedure, interested parties engaged in a collaboration in an attempt to set an interim CTC level consistent with the principles set forth in the CPUC decision. Since no consensus was reached among the parties, the unresolved issues will be referred to an administrative law judge to prepare a recommended decision for CPUC approval. The CPUC is expected to establish the interim CTC in 1996. Also in April 1996, the FERC issued Order 888. That order requires all utilities under the FERC's jurisdiction to file a wholesale transmission service tariff intended to provide wholesale open access to utility transmission systems on terms that are comparable to how utilities use their own systems. In the same order, 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. In the coming months, PG&E will be making additional filings with the CPUC and FERC on other aspects of the electric industry restructuring, as directed by the December 20, 1995, decision. Financial Impact of the Electric Industry Restructuring: In December 1994, in response to one of the proceedings leading to the CPUC electric industry restructuring decision, PG&E estimated the revenue requirements of its owned generation assets and power purchase obligations to be above market by $3 billion and $11 billion (net present value) at assumed market prices of $.040 and $.032 per kWh, respectively. These market prices were used to provide a range of possible transition costs and do not represent a forecast of expected market prices. Market prices could be less than $.032 per kWh. The above-market estimates filed in December 1994 were determined by comparing future revenue requirements of generation assets and power purchase obligations, over a 20-year and 30-year period, respectively, with revenues computed at assumed market prices. Diablo Canyon was included in the revenue requirement calculation using the pricing included in the Diablo Settlement. (See Note 4 to Notes to Consolidated Financial Statements.) The revenue requirements for Diablo Canyon and all PG&E-owned generation assets included a return on investment. The actual amounts of above-market revenue requirements may differ materially from those indicated above and will depend on the final regulations and the actual market prices of electricity or a definitive market valuation. Based on the pricing included in the Diablo Settlement, the net present values of above-market revenue requirements for Diablo Canyon included in the December 1994 estimates were $4 billion and $6 billion at assumed market prices of $.040 and $.032 per kWh, respectively. Also based on the pricing included in the Diablo Settlement, the net present value of above-market revenue requirements for Diablo Canyon is estimated to be $10 billion at a market price of $.025 per kWh, which reflects PG&E's current estimate of the market price beginning in 1997. The CPUC electric industry restructuring decision establishes an account to track the accumulation of transition costs and their recovery. While the decision provides an opportunity for recovery of all above-market costs, actual recovery of the CTC will be limited to an amount that does not increase the customers' aggregate rates above those in effect on January 1, 1996. 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 cents per kWh. PG&E's ability to recover its transition costs will be dependent on achieving overall reductions in costs such that it can recover its ongoing operating costs, capital costs and transition costs at the 1996 rate level and on continuing to collect CTC for the duration of the recovery period. As a result of applying the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," PG&E has accumulated approximately $2.5 billion of electric regulatory assets, including balancing accounts, at March 31, 1996. The regulatory assets attributable to electric generation, excluding balancing accounts of $173 million which are expected to be recovered in the near term, were approximately $1.4 billion at March 31, 1996. When generation rates are no longer based on cost of service, as ultimately contemplated under the decision, PG&E will discontinue application of SFAS No. 71 for that portion of its business. However, PG&E expects to recover its generation regulatory assets as transition costs through the CTC and does not expect a material loss from the discontinuance of SFAS No. 71. PG&E's transmission and distribution businesses are expected to remain under the provisions of SFAS No. 71. In addition, the adoption of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," in 1996 requires that regulatory assets continue to be probable of recovery in rates. In the event that this criterion can no longer be met, whether due to changing regulation or PG&E's inability to collect these costs, applicable portions of any regulatory assets would be written off. The transition cost account will be a regulatory asset also subject to the criteria of SFAS No. 121. The CPUC restructuring decision provides a structure for full recovery of PG&E's generation assets and costs through market prices and the CTC. The proposed modification to 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. If accepted, the proposed modification will significantly reduce the level of PG&E's CTC and earnings 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 at January 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 effect 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 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 will be impacted. As of March 31, 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 $3.0 billion, respectively, and regulatory assets attributable to electric generation (excluding balancing accounts expected to be recovered in the near term) were approximately $1.4 billion. Because of the expected transition cost recovery as provided in the decision, PG&E does not anticipate a material impairment loss on its investment in generation assets due to electric industry restructuring. However, should final implementing regulations differ significantly from the CPUC decision or should full recovery of generation assets and obligations not be achieved due to changing costs or limitations imposed by the market, a material loss could occur. 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 impact on its financial position or results of operations. However, the Company believes the end result 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) 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 for full competition. (2) 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. (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 review 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 fully recover its gas costs, receive benefits or be penalized depending on whether its actual core procurement costs are within, below or above the "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 have been scheduled for June 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 impact on its financial position or results of operations. Holding Company Structure: - ------------------------- The PG&E Board of Directors (Board) has authorized, and shareholders 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, the FERC and the NRC. An application for approval by the CPUC was filed by PG&E in October 1995 and PG&E subsequently filed for approvals from the FERC and the NRC. Utility Revenue Matters: - ----------------------- In addition to the CPUC 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 decision for base rates effective January 1, 1996, authorized electric and gas base revenue decreases of approximately $300 million and $270 million, respectively, compared to rates in effect in 1995. The $570 million revenue decrease is attributable to declining capital expenditures, lower cost of capital and reductions in expense levels, principally relating to workforce reductions. PG&E has filed an application for rehearing on a number of issues in the GRC decision, including pension contributions, funding for nonresidential customer service and elimination of the air quality adjustment mechanism. The GRC proceeding was held open to consider, among other things, PG&E's response to outages caused by recent storms and a study to determine the cost effectiveness of the Helms Pumped Storage Facility (Helms). The study will consider changes in rate recovery for the plant which will include, among other things, the option of retirement with recovery of the investment without a return over a four-year period. The net investment in Helms at March 31, 1996, was $719 million comprised of the pumped storage facility (including regulatory assets of $50 million), common plant and dedicated transmission plant. In December 1995, PG&E's service territory experienced severe storms and winds 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 those wind storms. The hearings will also address potential remedies, including reparations to customers for reduced reliability, penalties, disallowances and damages to customers for property loss. Hearings are expected to be held in June 1996. 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 CPUC decision on this phase of the storm proceeding is expected shortly. 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 "Electric Industry Restructuring" above. 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 1997 Diablo Canyon revenue requirement by $372 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. During April 1996, PG&E filed with the CPUC a rate case application to increase 1997 electric base revenue by approximately $156 million, with recovery of approximately $33 million effective January 1, 1997. Recovery of the remaining $123 million would be deferred until January 1, 1998, unless otherwise offset by further decreases in other forecasted electric costs for 1997. The filing requests recovery of expenses for electric distribution operations and maintenance and call center operations. The amounts requested are greater than the levels authorized by the CPUC for these activities in the 1996 GRC. The filing also requests an inflation adjustment from 1996 to 1997. During April 1996, PG&E filed its 1997 Electric Cost Adjustment Clause (ECAC) application with the CPUC to request a revenue requirement decrease of approximately $405 million, composed of an ECAC decrease of approximately $346 million, an Annual Energy Rate decrease of approximately $10 million, an Energy Revenue Adjustment Mechanism decrease of approximately $48 million and a California Alternative Rates for Energy decrease of approximately $1 million. During May 1996, PG&E filed an errata with the CPUC to correct errors in the computation of its 1997 ECAC application. The errata filing requested an additional decrease in revenue requirement of $97 million, from $405 million, as originally requested, to $502 million. The errata also requested a $97 million decrease in the deferral of the proposed 1997 base revenue increase, as discussed above, from $123 million, as originally requested, to $26 million. In May 1996, PG&E filed an application with the CPUC requesting the following cost of capital for 1997: Capital Cost/ Weighted Ratio Return Cost/Return ------- ------ ----------- Common equity 48.00% 11.85% 5.69% Preferred stock and preferred securities 5.80% 7.04% .41% Long-term debt 46.20% 7.50% 3.46% ----- Total requested return on average utility rate base 9.56% ===== If adopted, PG&E's request would result in an 1997 revenue requirement increase of $13 million for electric rates and $4 million for gas rates effective January 1, 1997. PG&E requested an increase in its return on common equity from 11.60 percent, as adopted in the 1996 GRC, to 11.85 percent. The increase reflects higher interest rates and increased regulatory and business risks. During May 1996, PG&E filed its 1996 Annual Earnings Assessment Proceeding application with the CPUC requesting shareholder incentives for its Demand-Side Management programs. The filing requests a $13 million increase in the 1997 electric revenue requirement and a $1 million increase in the 1997 gas revenue requirement. During May 1996, PG&E intends to file an application with the CPUC seeking funding for costs associated with the establishment of the ISO and Exchange. Such costs are currently estimated to range between $200 million and $300 million, with PG&E's share of the cost expected to range from approximately $100 million to $150 million. The remainder of the costs will be shared by the other two major California IOUs. See "Electric Industry Restructuring," above. PG&E's annual recovery in rates of these costs is limited by the CPUC to one percent of annual billed electric revenue. To implement the proposed customer electric rate freeze in 1997, PG&E has requested or intends to request deferral of recovery in rates of a portion of the electric revenue requirement increases proposed in the above applications. 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-month period ended March 31, 1996 and 1995, are reflected in the following table and discussed below.
Diablo Diversified (in millions, except per share amounts) Utility Canyon Operations Total 1996 Operating revenues $ 1,778 $ 440 $ 31 $ 2,249 Operating expenses 1,463 180 33 1,676 ------- ------ ------ ------- Operating income (loss) before income taxes $ 315 $ 260 $ (2) $ 573 ======= ====== ====== ======= Net income $ 128 $ 129 $ 4 $ 261 ======= ====== ====== ======= Earnings per common share $ .29 $ .31 $ .01 $ .61 ======= ====== ====== ======= Total assets at March 31 $19,916 $5,663 $1,055 $26,634 ======= ====== ====== ======= 1995 Operating revenues $ 1,777 $ 464 $ 67 $ 2,308 Operating expenses 1,335 183 81 1,599 ------- ------ ------ ------- Operating income (loss) before income taxes $ 442 $ 281 $ (14) $ 709 ======= ====== ====== ======= Net income (loss) $ 191 $ 140 $ (2) $ 329 ======= ====== ====== ======= Earnings (loss) per common share $ .42 $ .32 $ (.01) $ .73 ======= ====== ====== ======= Total assets at March 31 $19,928 $5,989 $1,423 $27,340 ======= ====== ====== =======
Earnings Per Common Share: - ------------------------- Utility earnings per common share for the three-month period ended March 31, 1996, decreased as compared with the same period 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. Common Stock Dividend: - --------------------- In January 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. In addition to the other factors affecting PG&E's dividend policy, 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: - ------------------ Billed revenues decreased for the three-month period ended March 31, 1996, compared to the same period in 1995 due to decreases in actual energy usage as a result of a mild 1995/1996 winter season and in authorized revenues, as discussed above. This decrease was offset by an increase in balancing account revenues primarily due to lower than forecasted energy demand and higher costs of fuel and transportation. Therefore, there were no significant changes in total electric and gas utility revenues for the three-month period ended March 31, 1996, compared to the same period in 1995. Revenues from diversified operations decreased $36 million for the three-month period ended March 31, 1996, compared to the same period in 1995, primarily due to Enterprises' sale of DALEN Corporation in June 1995. Operating Expenses: - ------------------ Operating expenses for the three-month period ended March 31, 1996, increased $76 million compared to the same period in 1995 primarily due to expenses incurred to terminate certain qualifying facility (QF) contracts, increases in the price of gas and increases in maintenance and other operating expenses for distribution and customer-related services. Partially offsetting these increases were decreases in general and administrative expenses, depreciation and litigation reserves. Operating expenses for the three-month period ended March 31, 1996, were also greater than amounts authorized by the CPUC for setting rates in the 1996 GRC. The greater expense level is primarily attributable to several projects related to distribution system reliability, improved customer service and public information systems. During April 1996, PG&E filed with the CPUC a rate case application to increase 1997 electric base revenues. The filing requests recovery of expenses for electric distribution operations and maintenance and call center operations. (See "Utility Revenue Matters" above.) 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 three-month period ended March 31, 1996, PG&E issued $58 million of common stock, primarily through its Dividend Reinvestment Program and Savings Fund Plan. PG&E purchased approximately $39 million of its common stock on the open market during the three-month period ended March 31, 1996. Acquisition: - ----------- In April 1996, the Company was chosen by the State of Queensland in Australia as the selected bidder for State Gas Pipeline, a 376-mile natural gas transportation system in northeastern Australia. The Company has granted another company a 60-day option which expires in June 1996 to purchase up to 50 percent of State Gas Pipeline. The purchase price is approximately $130 million. State Gas Pipeline provides gas transportation service to the industrial sector in the Australian state of Queensland, primarily supplying gas as a process fuel in industrial applications. 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 activities. The Company has an accrued liability at March 31, 1996, of $126 million for hazardous waste remediation costs at those sites where such costs are probable and quantifiable. The costs may be as much as $292 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. (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 claims for personal injury, and property and punitive damages allegedly suffered as a result of exposure to chromium near PG&E's Hinkley Compressor Station and a claim that PG&E underpaid franchise fees. Other Matters - ------------- New Accounting Standard: - ----------------------- SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective January 1, 1996, prescribes general standards for the recognition and measurement of impairment losses. In addition, it requires that regulatory assets continue to be probable of recovery in rates, rather than only at the time the regulatory asset is recorded. Regulatory assets currently recorded would be written off if recovery is no longer probable. Based on the expected CTC recovery set forth in the CPUC decision on electric industry restructuring discussed in Note 2 of Notes to Consolidated Financial Statements, the Company currently does not anticipate a material impairment of its assets and, specifically, its generation-related regulatory assets and investments in electric generation assets. However, the CPUC decision is subject to legislative review. Should final regulations differ significantly from the CPUC decision or should full recovery of generation assets and obligations not be achieved due to changing costs or limitations imposed by the market, a material loss could occur. 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 January 1, 1997, 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 nuclear 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 --------------------------- 1. Legal Proceedings ----------------- A. Diablo Canyon Environmental Litigation As previously reported, in October 1995, the League for Coastal Protection (Coastal League) filed a lawsuit in San Francisco County Superior Court against Pacific Gas and Electric Company (PG&E) and its consultant, Tenera, Inc., (Tenera) alleging violations of the California Business and Professions Code in connection with a 1988 study of the cooling water intake system (1988 Study) at the Diablo Canyon Nuclear Power Plant (Diablo Canyon). (The 1988 Study is also the subject of an investigation by the California Attorney General, as described in Item B below.) The Coastal League alleges in this lawsuit that PG&E and its consultant violated the law by making misrepresentations in connection with the 1988 Study. The Coastal League seeks an unspecified amount of damages related to restitution or disgorgement of improper or excessive profits, punitive damages, injunctive relief and attorneys' fees. On April 16, 1996, the Coastal League filed another lawsuit in the United States District Court for the Northern District of California against PG&E and Tenera, alleging violations of the federal Clean Water Act in connection with the 1988 Study. The Coastal League alleges that PG&E and Tenera withheld data from the 1988 Study and submitted misleading information to the state and federal agencies. The Coastal League seeks a judgment that PG&E has violated its discharge permit for Diablo Canyon, revocation of the permit, an order requiring restoration of the marine environment, an unspecified amount of civil penalties and recovery of its litigation and attorneys' fees. Also on April 16, 1996, PG&E received a copy of a complaint filed in a third case involving the 1988 study. In this case, John W. Carter (Carter) alleges on behalf of himself and the United States and the State of California that PG&E, Tenera, and certain of their employees violated the federal and state false claims acts by filing an incomplete report in 1988 (i.e., the 1988 Study) and failing to correct it. The United States and the State of California have declined to prosecute this action, and it will be maintained by Carter, who is represented by the same attorneys representing the Coastal League. The plaintiffs seek civil penalties, treble damages, a separate payment to Carter under the false claims acts and attorneys' fees. The Company believes that the ultimate outcome of these matters will not have a material adverse impact on its financial position or results of operations. B. California Attorney General Litigation As previously reported, in February 1995, the California Attorney General (AG) initiated an investigation to determine whether PG&E and its consultant, Tenera, Inc., violated the Federal Clean Water Act and the California Water Code in connection with the 1988 Study, which is also the subject of litigation described in Item A above. The United States Department of Justice (DOJ) has recently joined the AG's investigation. PG&E has been in discussions with the AG and the DOJ concerning the disposition of this matter. In those discussions, the AG and the DOJ have indicated their belief that PG&E violated the Federal Clean Water Act, the California Water Code and other provisions of California law in connection with the 1988 Study. The AG and DOJ have proposed a resolution of this matter which involves the payment by PG&E of civil penalties and mitigation project costs. While PG&E cannot predict the outcome of these discussions, the disposition of the matter is likely to involve the initiation of legal proceedings against PG&E by the AG or the payment of a monetary fine by PG&E. 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. C. Norcen Litigation As previously reported, in March 1994, Norcen Energy Resources Limited and Norcen Marketing Incorporated filed a complaint in the U.S. District Court, Northern District of California, against PG&E and Pacific Gas Transmission Company (PGT), alleging various state law contract claims and a series of federal and state antitrust claims related to the construction of the PGT/PG&E Pipeline Expansion and PG&E's alleged refusals to allow access to the pre-expansion PGT and California transmission systems. Plaintiffs' antitrust claims were dismissed by the District Court in July 1995. The remaining state law contract claims include claims based on fraudulent inducement and breach of contract. The Company believes plaintiffs in this action might seek contract damages of approximately $50 million. The plaintiffs are also seeking punitive damages in connection with such claims. 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. Item 4. Submission of Matters to a Vote of Security-Holders ---------------------------------------------------- On April 17, 1996, PG&E held its regular annual meeting of shareholders. At that meeting, the following matters were voted as indicated: 1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors shall be elected and qualified: For Withheld ---------- ---------- Richard A. Clarke 340,588,268 9,842,499 Harry M. Conger 343,885,360 6,545,407 C. Lee Cox 341,066,532 9,364,235 William S. Davila 343,880,297 6,550,470 Robert D. Glynn, Jr. 341,876,054 8,554,713 David M. Lawrence, MD 341,105,754 9,325,013 Simon Levine 158,884 0 Richard B. Madden 343,726,090 6,704,677 Mary S. Metz 343,581,080 6,849,687 Rebecca Q. Morgan 341,079,589 9,351,178 Samuel T. Reeves 343,651,071 6,779,696 Carl E. Reichardt 343,755,340 6,675,427 John C. Sawhill 343,877,184 6,553,583 Alan Seelenfreund 342,990,320 7,440,447 Stanley T. Skinner 341,218,835 9,211,932 Barry Lawson Williams 343,740,843 6,689,924 2. Approval of a proposal to form a holding company structure for PG&E and approve a related agreement of merger to implement this structure: Common and Preferred Stock Common Stock Alone -------------------------- ------------------ For: 292,100,933 278,365,856 Against: 11,071,318 10,040,910 Abstain: 5,818,552 5,427,877 Broker non-votes*: 41,439,964 38,193,617 3. Approval of a proposal to amend and restate PG&E's Long-Term Incentive Program: For: 267,999,694 Against: 32,062,670 Abstain: 8,863,607 Broker non-votes*: 41,504,796 4. Ratification of the selection of Arthur Andersen LLP as independent public accountants for the year 1996: For: 341,761,225 Against: 4,092,404 Abstain: 4,577,138 Broker non-votes*: 0 5. Approval of a shareholder proposal to limit each director's total annual compensation to 2,000 shares of PG&E's common stock: For: 41,930,355 Against: 251,721,345 Abstain: 15,335,779 Broker non-votes*: 41,443,288 - ---------------------------------- * A non-vote occurs when a nominee holding shares for a beneficiary owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. Item 5. Other Information ----------------- A. Pending Electric Reasonableness Issue In August 1993, the Division of Ratepayer Advocates (DRA) of the California Public Utilities Commission (CPUC) filed a report in PG&E's Electric Cost Adjustment Clause (ECAC) proceeding for the 1991 record period, which questioned PG&E's execution of amendments to three power purchase agreements (PPAs) with Texaco, Inc. (Texaco) for qualifying facilities (QFs). The PPAs were Standard Offer No. 4 contracts providing for relatively high capacity payments, and included the standard provision that the agreements would terminate if construction was not completed and energy deliveries commenced within five years of the execution of the PPAs in 1985. In its report, the DRA asserted that PG&E improperly agreed to extend the construction time under these agreements and recommended that the CPUC find these extensions unreasonable because Texaco could not fulfill its contractual obligation to commence operations by a date certain. Although no payments are at issue in the 1991 record period, the DRA argued that a portion of the capacity payments under the contracts should be disallowed in subsequent year proceedings over the 15-year term of the contracts. In its August 1993 report, the DRA indicated that this disallowance over the 15-year terms of the contracts would approximate $80 million. In its report on the ECAC expenses for the 1992, 1993 and 1994 record periods, the DRA recommended disallowances of approximately $3.5 million, $3.0 million and $6.1 million, respectively, for two of these agreements. On May 8, 1996, the CPUC issued its decision addressing this issue, finding that PG&E's deferral of the deadline by which these QFs were required to come on-line was reasonable. The CPUC agreed with PG&E that the appropriate starting point for review was the spring of 1988, when the contract deferrals were negotiated and agreement in principle was reached, as opposed to December 1988 when the extensions were actually executed. At the earlier date when the extensions were negotiated, the facts and then-existing viability standards indicated that the projects were viable, and the QFs could have come on-line on or before the original contractual deadline. Accordingly, under this analysis PG&E acted reasonably in granting the extensions. B. 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 three months ended March 31, 1996 was 3.35. PG&E's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 1996 was 3.13. 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 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 Exhibit 99 Deferrable Interest Subordinated Debenture Second Supplemental Indenture dated as of March 25, 1996 (b) Reports on Form 8-K during the first quarter of 1996 and through the date hereof: 1. January 17, 1996 Item 5. Other Events A. Performance Incentive Plan - Year-to-Date Financial Results B. Performance Incentive Plan - 1996 Target C. 1995 Consolidated Earnings (unaudited) D. Common Stock Dividend 2. January 18, 1996 (Form 8K/A) Item 5. Other Events A. Performance Incentive Plan - Year-to-Date Financial Results B. Performance Incentive Plan - 1996 Target C. 1995 Consolidated Earnings (unaudited) D. Common Stock Dividend 3. February 21, 1996 Item 7. Financial Statements, Pro Forma Financial Information and Exhibits A. 1995 Financial Statements B. Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 4. April 18, 1996 Item 5. Other Events A. Performance Incentive Plan - Year-to-Date Financial Results B. Interim CTC Procedure 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 May 9, 1996 GORDON R. SMITH By______________________________ GORDON R. SMITH Senior Vice President and Chief Financial Officer EXHIBIT INDEX Exhibit Number Exhibit - ------- --------------------------------------- 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 99 Deferrable Interest Subordinated Debenture Second Supplemental Indenture dated as of March 25, 1996 EX-11 2 EXHIBIT 11 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF EARNINGS PER COMMON SHARE
- -------------------------------------------------------------------------------------------- Three months ended March 31, --------------------------- (in thousands, except per share amounts) 1996 1995 - -------------------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Net income $260,704 $328,687 Less: preferred dividend requirement and redemption premium 8,278 14,494 -------- -------- Net income for calculating EPS for Statement of Consolidated Income $252,426 $314,193 ======== ======== Average common shares outstanding 414,351 430,086 ======== ======== EPS as shown in the Statement of Consolidated Income $ .61 $ .73 ======== ======== PRIMARY EPS (1) Net income $260,704 $328,687 Less: preferred dividend requirement and redemption premium 8,278 14,494 -------- -------- Net income for calculating primary EPS $252,426 $314,193 ======== ======== Average common shares outstanding 414,351 430,086 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) 83 46 -------- -------- Average common shares outstanding as adjusted 414,434 430,132 ======== ======== Primary EPS $ .61 $ .73 ======== ======== FULLY DILUTED EPS (1) Net income $260,704 $328,687 Less: preferred dividend requirement and redemption premium 8,278 14,494 -------- -------- Net income for calculating fully diluted EPS $252,426 $314,193 ======== ======== Average common shares outstanding 414,351 430,086 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) 83 46 -------- -------- Average common shares outstanding as adjusted 414,434 430,132 ======== ======== Fully diluted EPS $ .61 $ .73 ======== ======== - -------------------------------------------------------------------------------------------- (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 3 EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- ---------------------------------------------------------------------------------------------------- Three Months Year ended December 31, Ended ---------------------------------------------------------- (dollars in thousands) 3/31/96 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------- Earnings: Net income $ 260,704 $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 (6,529) 3,820 (2,764) 6,895 (3,349) 26,671 Income tax expense 171,544 895,289 836,767 901,890 895,126 851,534 Net fixed charges 181,194 715,975 730,965 821,166 802,198 776,682 ---------- ---------- ---------- ---------- ---------- ---------- Total Earnings $ 606,913 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279 ========== ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 147,242 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185 Interest on short- term borrowings 26,975 83,024 77,295 87,819 61,182 77,760 Interest on capital leases 895 2,735 1,758 1,737 1,737 1,737 Capitalized interest 109 957 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 6,191 3,306 - - - - ---------- ---------- ---------- ---------- ---------- ---------- Total Fixed Charges $ 181,412 $ 717,397 $ 733,625 $ 867,221 $ 808,709 $ 782,789 ========== ========== ========== ========== ========== ========== Ratios of Earnings to Fixed Charges 3.35 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 4 EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- --------------------------------------------------------------------------------------------------- Three Months Year ended December 31, Ended ---------------------------------------------------------- (dollars in thousands) 3/31/96 1995 1994 1993 1992 1991 - --------------------------------------------------------------------------------------------------- Earnings: Net income $ 260,704 $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 (6,529) 3,820 (2,764) 6,895 (3,349) 26,671 Income tax expense 171,544 895,289 836,767 901,890 895,126 851,534 Net fixed charges 181,194 715,975 730,965 821,166 802,198 776,682 ---------- ---------- ---------- ---------- ---------- ---------- Total Earnings $ 606,913 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279 ========== ========== ========== ========== ========== ========== Fixed Charges: Interest on long- term debt $ 147,242 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185 Interest on short- term borrowings 26,975 83,024 77,295 87,819 61,182 77,760 Interest on capital leases 895 2,735 1,758 1,737 1,737 1,737 Capitalized interest 109 957 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 6,191 3,306 - - - - ---------- ---------- ---------- ---------- ---------- ---------- Total Fixed Charges 181,412 717,397 733,625 867,221 808,709 782,789 ---------- ---------- ---------- ---------- ---------- ---------- Preferred Stock Dividends: Tax deductible dividends 2,514 11,343 4,672 4,814 5,136 5,136 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 9,777 99,984 96,039 108,937 130,147 154,404 ---------- ---------- ---------- ---------- ---------- ---------- Total Preferred Stock Dividends 12,291 111,327 100,711 113,751 135,283 159,540 ---------- ---------- ---------- ---------- ---------- ---------- Total Combined Fixed Charges and Preferred Stock Dividends $ 193,703 $ 828,724 $ 834,336 $ 980,972 $ 943,992 $ 942,329 ========== ========== ========== ========== ========== ========== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 3.13 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 5
UT 1,000 3-MOS DEC-31-1996 MAR-31-1996 PER-BOOK 18,807,712 1,827,902 3,380,889 2,617,835 0 26,634,338 2,073,473 3,749,153 2,836,255 8,658,881 437,500 402,056 7,985,999 0 0 763,304 230,342 0 0 0 8,156,256 26,634,338 2,248,768 171,544 1,675,374 1,675,374 573,394 32,782 606,176 173,928 260,704 8,278 252,426 200,998 0 931,163 .61 .61
EX-99 6 Exhibit 99 PACIFIC GAS AND ELECTRIC COMPANY TO THE FIRST NATIONAL BANK OF CHICAGO Trustee ----------------- SECOND SUPPLEMENTAL INDENTURE Dated as of March 25, 1996 TO Indenture Dated as of November 28, 1995 ----------------- SECOND SUPPLEMENTAL INDENTURE, dated as of March 25, 1996, (the "Second Supplemental Indenture"), between Pacific Gas and Electric Company, a California corporation (the "Company"), and The First National Bank of Chicago, a national banking association organized under the laws of the United States, as trustee (the "Trustee"), under the Indenture dated as of November 28, 1995, between the Company and the Trustee (the "Indenture"), as supplemented by the First Supplemental Indenture between the Company and the Trustee dated as of November 28, 1995 (the "First Supplemental Indenture"). WHEREAS, the Company and the Trustee executed the First Supplemental Indenture providing for the issuance by the Company of its 7.90% Deferrable Interest Subordinated Debentures, Series A (the "Debentures"); WHEREAS, Section 901(10) of the Indenture provides for the issuance of a Supplemental Indenture by the Company and the Trustee without the consent of the holders of the Debentures to, among other things, cure any ambiguity or correct or supplement any provision in the Indenture; and WHEREAS, the Company had intended that it have the right to extend the interest payment period on the Debentures only so long as an Event of Default under the Indenture has not occurred and is continuing at the time of such extension notwithstanding the absence of such restriction in the First Supplemental Indenture. NOW THEREFORE, THIS SECOND SUPPLEMENTAL INDENTURE WITNESSETH: SECTION 101. The following clause shall be added at the beginning of the first sentence of the second paragraph under "Section 101 - Title; Stated Maturity; Interest" in the First Supplemental Indenture: "So long as an Event of Default under the Indenture has not occurred and is continuing," and, accordingly, such paragraph shall read in its entirety as follows: "So long as an Event of Default under the Indenture has not occurred and is continuing, the Company shall have the right, at any time during the term of the Series A Securities, from time to time to extend the interest payment period for up to 20 consecutive quarters (the "Extension Period") during which period interest will compound quarterly, and at the end of which Extension Period the Company shall pay all interest then accrued and unpaid thereon (together with Additional Interest), provided, however, that during any such Extension Period, the Company shall not, and shall not permit any Subsidiary of the Company to, declare or pay any dividend or distribution on, or redeem, purchase, acquire, or make a liquidation or guarantee payment (other than payments under a Guarantee) with respect to, any shares of the Company's capital stock or any other security of the Company (including other Securities) ranking pari passu with or junior in interest to the Series A Securities, except in each case with securities ranking junior in interest to the Series A Securities and except for payments made on any series of Securities upon the Stated Maturity of such Securities. Prior to the termination of any such Extension Period, the Company may further extend the interest payment period, provided that such Extension Period together with all such previous and further extensions thereof shall not exceed 20 consecutive quarters or extend beyond the Maturity of the Series A Securities. Upon the termination of any Extension Period and upon the payment of all accrued and unpaid interest and any Additional Interest then due, the Company may select a new Extension Period, subject to the above requirements. No interest or Additional Interest shall be due and payable during an Extension Period, except at the end thereof. The Company shall give the Series A Trust and the Trustee notice of its selection of such Extension Period subject to the above requirements at least one Business Day prior to the date the Series A Trust is required to give notice to the New York Stock Exchange or other applicable self-regulatory organization or to holders of the Series A Preferred Securities of the record date or the date distributions on the Series A Preferred Securities are payable, but in any event not less than one Business Day prior to such record date. The Trustee shall promptly notify the holders of the Series A Preferred Securities of the Company's selection of such an Extension Period." IN WITNESS WHEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed, and their respective corporate seals to be hereunto affixed and attested, on the date or dates indicated in the acknowledgements and as of the day and year first above written. PACIFIC GAS AND ELECTRIC COMPANY GORDON R. SMITH By: ______________________________ Gordon R. Smith Senior Vice President and Chief Financial Officer Attest: KATHLEEN RUEGER ______________________________ Kathleen Rueger Assistant Corporate Secretary [Continuation of signature page for Second Supplemental Indenture] THE FIRST NATIONAL BANK OF CHICAGO as Trustee JOHN R. PRENDIVILLE By:___________________________ Name: John R. Prendiville Title: Vice President Attest: R. D. MANELLA ____________________ Name: R. D. Manella Secretary -----END PRIVACY-ENHANCED MESSAGE-----