-----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, HyVNaR2JhfwaWFGFUBRY6Z7OXDNZ1ToGGBLFdBJbms3fYD8VCrAY/mBCGpSlJ/04 q1/8ISdMgLCKtBDxYpYfBw== 0000827052-97-000025.txt : 19970520 0000827052-97-000025.hdr.sgml : 19970520 ACCESSION NUMBER: 0000827052-97-000025 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19970331 FILED AS OF DATE: 19970515 SROS: AMEX SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: EDISON INTERNATIONAL CENTRAL INDEX KEY: 0000827052 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 954137452 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-09936 FILM NUMBER: 97606230 BUSINESS ADDRESS: STREET 1: 2244 WALNUT GROVE AVE, STE 374 STREET 2: P O BOX 999 CITY: ROSEMEAD STATE: CA ZIP: 91770 BUSINESS PHONE: 8183022222 FORMER COMPANY: FORMER CONFORMED NAME: SCECORP DATE OF NAME CHANGE: 19920703 10-Q 1 EIX FORM 10-Q DATED 3/31/97 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (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, 1997 --------------------------------------- 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 Number 1-9936 EDISON INTERNATIONAL (Exact name of registrant as specified in its charter) CALIFORNIA 95-4137452 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2244 Walnut Grove Avenue (P.O. Box 999) Rosemead, California (Address of principal 91770 executive offices) (Zip Code) 818-302-2222 (Registrant's telephone number, including area code) 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 12 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 May 13, 1997 - -------------------------- --------------------------- Common Stock, no par value 410,126,374 PAGE EDISON INTERNATIONAL INDEX Page No. ---- Part I. Financial Information: Item 1. Consolidated Financial Statements: Consolidated Statements of Income--Three Months Ended March 31, 1997, and 1996 2 Consolidated Balance Sheets--March 31, 1997 and December 31, 1996 3 Consolidated Statements of Cash Flows--Three Months Ended March 31, 1997, and 1996 5 Notes to Consolidated Financial Statements 6 Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition 14 Part II. Other Information: Item 1. Legal Proceedings 27 Item 4. Submission of Matters to a Vote of Security Holders 32 Item 6. Exhibits and Reports on Form 8-K 32 page 1 EDISON INTERNATIONAL PART I--FINANCIAL INFORMATION Item 1. Consolidated Financial Statements CONSOLIDATED STATEMENTS OF INCOME In thousands, except per-share amounts 3 Months Ended March 31, ------------------------- 1997 1996 ---------- ---------- (Unaudited) Electric utility revenue $1,695,401 $1,760,134 Diversified operations 305,324 207,520 ---------- ---------- Total operating revenue 2,000,725 1,967,654 ---------- ---------- Fuel 200,233 143,178 Purchased power 628,674 527,433 Provisions for regulatory adjustment clauses -- net (88,173) 97,823 Other operating expenses 330,270 329,860 Maintenance 96,155 84,113 Depreciation and decommissioning 340,121 264,527 Income taxes 96,076 111,477 Property and other taxes 40,309 59,686 ---------- ---------- Total operating expenses 1,643,665 1,618,097 ---------- ---------- Operating income 357,060 349,557 ---------- ---------- Provision for rate phase-in plan (11,309) (29,078) Allowance for equity funds used during construction 2,003 4,402 Interest and dividend income 15,842 15,327 Minority interest (27,965) (13,724) Other nonoperating income -- net (2,862) 8,465 ---------- ---------- Total other income (deductions) -- net (24,291) (14,608) ---------- ---------- Income before interest and other expenses 332,769 334,949 ---------- ---------- Interest on long-term debt 152,425 150,986 Other interest expense 31,259 23,761 Allowance for borrowed funds used during construction (2,412) (2,767) Capitalized interest (5,177) (15,998) Dividends on subsidiary preferred securities 11,862 11,878 ---------- ---------- Total interest and other expenses -- net 187,957 167,860 ---------- ---------- Net income $ 144,812 $ 167,089 ========== ========== Weighted-average shares of common stock outstanding 419,665 443,626 Earnings per share $0.35 $0.38 Dividends declared per common share $0.25 $0.25 The accompanying notes are an integral part of these financial statements. page 2 EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands March 31, December 31, 1997 1996 ------------- ----------- (Unaudited) ASSETS Utility plant, at original cost $20,537,877 $20,400,387 Less -- accumulated provision for depreciation and decommissioning 9,687,121 9,431,071 ----------- ----------- 10,850,756 10,969,316 Construction work in progress 525,265 556,645 Nuclear fuel, at amortized cost 185,411 176,827 ----------- ----------- Total utility plant 11,561,432 11,702,788 ----------- ----------- Nonutility property -- less accumulated provision for depreciation of $217,825 and $203,256 at respective dates 3,492,640 3,570,237 Nuclear decommissioning trusts 1,499,836 1,485,525 Investments in partnerships and unconsolidated subsidiaries 1,483,991 1,371,824 Investments in leveraged leases 587,654 584,515 Other investments 115,470 103,973 ----------- ----------- Total other property and investments 7,179,591 7,116,074 ----------- ----------- Cash and equivalents 733,392 896,594 Receivables, including unbilled revenue, less allowances of $24,677 and $26,230 for uncollectible accounts at respective dates 945,942 1,094,498 Fuel inventory 58,626 72,480 Materials and supplies, at average cost 153,458 154,266 Accumulated deferred income taxes -- net 167,699 240,429 Prepayments and other current assets 66,757 113,654 ----------- ----------- Total current assets 2,125,874 2,571,921 ----------- ----------- Unamortized debt issuance and reacquisition expense 339,654 346,834 Rate phase-in plan 40,013 50,703 Income tax-related deferred charges 1,691,963 1,741,091 Other deferred charges 1,007,911 1,029,203 ----------- ----------- Total deferred charges 3,079,541 3,167,831 ----------- ----------- Total assets $23,946,438 $24,558,614 =========== =========== The accompanying notes are an integral part of these financial statements. page 3 EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands, except share amounts March 31, December 31, 1997 1996 ------------- ----------- (Unaudited) CAPITALIZATION AND LIABILITIES Common shareholders' equity: Common stock (414,681,238 and 424,524,178 shares outstanding at respective dates) $ 2,491,241 $ 2,547,403 Cumulative translation adjustments -- net 36,997 63,898 Unrealized gain in equity investments -- net 40,625 33,382 Retained earnings 3,639,305 3,752,549 ----------- ----------- 6,208,168 6,397,232 Preferred securities of subsidiaries: Not subject to mandatory redemption 283,755 283,755 Subject to mandatory redemption 425,000 425,000 Long-term debt 7,246,771 7,474,679 ----------- ----------- Total capitalization 14,163,694 14,580,666 ----------- ----------- Other long-term liabilities 452,048 423,925 ----------- ----------- Current portion of long-term debt 505,047 592,143 Short-term debt 438,192 397,098 Accounts payable 372,431 437,657 Accrued taxes 580,532 530,365 Accrued interest 134,488 131,079 Dividends payable 106,102 108,563 Regulatory balancing accounts -- net 106,505 181,488 Deferred unbilled revenue and other current liabilities 1,069,931 1,059,240 ----------- ----------- Total current liabilities 3,313,228 3,437,633 ----------- ----------- Accumulated deferred income taxes -- net 4,204,855 4,283,219 Accumulated deferred investment tax credits 366,976 372,377 Customer advances and other deferred credits 752,946 753,755 ----------- ----------- Total deferred credits 5,324,777 5,409,351 ----------- ----------- Minority interest 692,691 707,039 ----------- ----------- Commitments and contingencies (Notes 1 and 2) Total capitalization and liabilities $23,946,438 $24,558,614 =========== =========== The accompanying notes are an integral part of these financial statements. page 4 EDISON INTERNATIONAL CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands 3 Months Ended March 31, ------------------------ 1997 1996 --------- ----------- (Unaudited) Cash flows from operating activities: Net income $ 144,812 $ 167,089 Adjustments for non-cash items: Depreciation and decommissioning 340,121 264,527 Amortization 13,580 28,969 Rate phase-in plan 10,690 28,345 Deferred income taxes and investment tax credits 54,117 (17,494) Equity in income from partnerships and unconsolidated subsidiaries (40,113) (24,907) Other long-term liabilities 28,123 29,610 Other -- net (23,775) (6,432) Changes in working capital: Receivables 103,643 105,325 Regulatory balancing accounts (74,983) 101,487 Fuel inventory, materials and supplies 14,662 3,948 Prepayments and other current assets 46,897 49,084 Accrued interest and taxes 53,882 142,053 Accounts payable and other current liabilities (89,060) (120,681) Distributions from partnerships and unconsolidated subsidiaries 20,672 15,302 ---------- ---------- Net cash provided by operating activities 603,268 766,225 ---------- ---------- Cash flows from financing activities: Long-term debt issued 5,677 1,048,518 Long-term debt repayments (271,567) (1,027,633) Common stock issued 3,943 653 Common stock repurchases (214,492) - Nuclear fuel financing -- net 6,031 (8,437) Short-term debt financing -- net 31,415 (100,973) Dividends paid (112,018) (110,911) Other -- net 3,324 - ---------- ---------- Net cash used by financing activities (547,687) (198,783) ---------- ---------- Cash flows from investing activities: Additions to property and plant (158,008) (232,402) Funding of nuclear decommissioning trusts (27,889) (35,975) Investments in partnerships and unconsolidated subsidiaries (14,234) (96,266) Unrealized gain in equity investments--net 7,243 3,632 Other -- net (25,895) 9,115 ---------- ---------- Net cash used by investing activities (218,783) (351,896) ---------- ---------- Net increase (decrease) in cash and equivalents (163,202) 215,546 Cash and equivalents, beginning of period 896,594 507,151 ---------- ---------- Cash and equivalents, end of period $ 733,392 $ 722,697 ========== ========== The accompanying notes are an integral part of these financial statements. page 5 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Management's Statement In the opinion of management, all adjustments have been made that are necessary to present a fair statement of the financial position and results of operations for the periods covered by this report. Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements" included in its 1996 Annual Report on Form 10-K filed with the Securities and Exchange Commission. Edison International follows the same accounting policies for interim reporting purposes. This quarterly report should be read in conjunction with Edison International's 1996 Annual Report. A new accounting pronouncement establishes standards for computing and presenting earnings per share. The standard must be implemented for year- end 1997 financial reports and, in some instances, will require restatement of prior-period earnings per share data; earlier application of the standard is not permitted. The standard will not have any effect on reported earnings per share. Certain prior-period amounts were reclassified to conform to the March 31, 1997, financial statement presentation. Note 1. Regulatory Matters California Electric Utility Industry Restructuring The California Public Utilities Commission's (CPUC) December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which is expected to provide competition and customer choice and is scheduled to begin January 1, 1998. Key elements of the CPUC's restructuring decision include: creation of an independent power exchange (PX) and independent system operator (ISO); availability of direct customer access and customer choice; performance- based ratemaking (PBR) for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas- fueled generation, and implementation of a non-bypassable charge to all customers called the competition transition charge (CTC). In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopts the CPUC's December 1995 restructuring decision by addressing stranded-cost recovery for utilities, and providing a certain cost-recovery time period for the transition costs associated with utility-owned generation-related assets. Transition costs related to power-purchase contracts would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also includes provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow Southern California Edison Company (SCE), a subsidiary of Edison International, to reduce rates by at least 10% to these customers, beginning January 1, 1998. The financing would occur with securities issued by the California Infrastructure and Economic Development Bank, or an entity approved by the Bank. The legislation includes a rate freeze for all other customers, including large commercial and industrial customers, as well as provisions for continued funding for energy conservation, low-income programs and renewable resources. Despite the rate freeze, SCE expects to be able to recover its revenue requirement based on cost-of-service regulation during the 1998-2001 transition period. In addition, the legislation mandates the implementation of a non-bypassable CTC that provides utilities the opportunity to recover page 6 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS costs made uneconomic by electric utility restructuring. Finally, the legislation contains provisions for the recovery (through 2006) of reasonable employee-related transition costs incurred and projected for retraining, severance, early retirement, outplacement and related expenses for utility workers. On May 6, 1997, SCE filed an application with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billion of rate reduction bonds in one or more series or classes and a 10% rate reduction for the period from January 1, 1998, through May 31, 2002. On the same day, SCE filed an application with the California Infrastructure and Economic Development Bank for approval to issue the bonds. Residential and small commercial customers will repay the bonds over the expected 10- year term through non-bypassable charges based on electricity consumption. With the CPUC's decision expected in September 1997, and subject to the prior approval of the Infrastructure Bank, it is anticipated that the rate reduction bonds will be issued in the fourth quarter of 1997. In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the Federal Energy Regulatory Commission (FERC) regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities to file more specific information which was filed on March 31, 1997. In July 1996, the three utilities jointly filed an application with the CPUC requesting approval to establish a restructuring trust which would obtain loans up to $250 million for the development of the ISO and PX through January 1, 1998. The loans would be backed by utility guarantees; SCE's share would be 45%. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million which will be used to build the hardware and software systems for the ISO and PX. On May 6, 1997, the CPUC issued a decision describing how all California investor-owned utility customers will be able to choose who will provide them with electric generation service. Beginning January 1, 1998, customers will be able to choose to purchase power from the PX through SCE, or choose direct access, which means the customer can contract directly with either independent power producers or retail electric service providers such as power brokers, marketers and aggregators. Additionally, all investor-owned utility customers must pay the CTC whether or not they choose to buy power through SCE. Electric utilities will continue to provide the core distribution service of delivering energy through its distribution system regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could implement a contingency plan. However, the CPUC believes it is likely that interest in and migration to direct access will be gradual. A second decision issued by the CPUC on May 6, 1997, introduces customer choice to metering, billing and related services (referred to as revenue cycle services) that are now provided by California's investor-owned utilities. Under this revenue cycle services "unbundling" decision, beginning in January 1998, customers may choose to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this option beginning in January 1999. In determining whether any credit should be provided by the utility page 7 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS to firms providing customers with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to "net" the cost incurred by the utility and the cost avoided by the utility as a result of such services being provided by the other firm rather than by the utility. The unbundling of revenue cycle services is likely to expose SCE to the loss of revenue, higher stranded costs and a reduction in revenue security. SCE is reviewing the potential effect of these decisions on its results of operations and financial condition. In July 1996, SCE filed a PBR proposal for its hydroelectric plants and a proposed structure for performance-based local reliability contracts for certain fossil-fueled plants. If approved, the hydro PBR would be in effect for three years and the initial terms of the local reliability contracts, which are subject to FERC approval, would be in effect for up to three years, both beginning January 1, 1998. A final CPUC decision on hydro PBR is expected by year-end 1997. In September 1996, the CPUC adopted a non-generation transmission and distribution (T&D) PBR mechanism for SCE which began on January 1, 1997. According to the CPUC decision, beginning in 1998, the transmission portion is to be separated from non- generation PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001. Key elements of the non-generation PBR include: T&D rates indexed for inflation based on the Consumer Price Index less a productivity factor; elimination of the kilowatt-hour sales adjustment; adjustments for cost changes that are not within SCE's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will share gains and losses from T&D operations. In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all of its oil- and gas-fueled generation assets. This application builds on SCE's March 1996 plan which outlined how SCE proposed to divest 50% of these assets. Under the new proposal, SCE would continue to operate and maintain the divested power plants for at least two years following their sale, as mandated by the recent restructuring legislation. In addition, SCE would offer workforce transition programs to those employees who may be impacted by divestiture-related job reductions. SCE's proposal is contingent on the overall electric industry restructuring implementation process continuing on a satisfactory path. CPUC approval of the oil- and gas-fueled generation divestiture was requested for late 1997. In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996 filing related to the conceptual aspects of separating costs as requested by CPUC and FERC directives) for the functional unbundling of its rates for electric service, beginning on January 1, 1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates in separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning. Hearings on SCE's rate unbundling plan were concluded in April 1997. A final decision on this matter is expected in the third quarter of 1997. Recovery of costs to transition to a competitive market would be implemented through a non-bypassable CTC. This charge would apply to all customers who were using or began using utility services on or after the December 20, 1995, decision date. In August 1996, in compliance with the CPUC's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September PAGE 8 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1996. Under the rate freeze codified in the legislation, the CTC will be determined residually (i.e., after subtracting other cost components for the PX, T&D, nuclear decommissioning and public benefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately $13.1 billion (1998 net present value), assuming the fossil plants have a market value equal to their net book value, and $13.8 billion (1998 net present value), assuming the fossil plants have no market value. These estimates are based on incurred costs, and forecasts of future costs and assumed market prices. However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of: $7.5 billion from SCE's qualifying facility contracts, which are the direct result of legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUC) to provide service to customers. Such commitments include the recovery of income tax benefits previously flowed-through to customers, postretirement benefit transition costs, accelerated recovery of San Onofre and Palo Verde and certain other costs. On February 14, 1997, SCE submitted an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included. Hearings on various phases of this issue began in December 1996 and will continue throughout 1997. A decision is expected before January 1, 1998. If the CPUC's restructuring is implemented as outlined, SCE would be allowed to recover its CTC (subject to a lower return on equity) and believes it should be allowed to continue to apply accounting standards that recognize the economic effects of rate regulation for its generation- related assets during the 1998-2001 transition period. However, in response to a request by the staff of the Securities and Exchange Commission (SEC), in December 1996, SCE submitted its views on the continued applicability of regulatory accounting standards for its generation-related assets. In its submittal, SCE and its independent accountants jointly concluded that, based on their current analysis, SCE will continue to meet the criteria for applying these accounting standards through the 1998-2001 transition period. In its February 1997 response, the SEC staff expressed continuing concern with SCE's conclusion and indicated that they wanted to meet further with SCE and the other major California electric utilities to resolve this matter. SCE and the other major California electric utilities met with the SEC in March 1997. Subsequently, the SEC asked a series of questions to be answered by each of California's major electric utilities. SCE responded to the SEC's questions in early April 1997. The authority to require SCE to discontinue applying regulatory accounting standards rests with the SEC, although matters such as this can be referred to the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) for resolution. On April 28, 1997, this regulatory accounting matter was added to the EITF's agenda for discussion at its May 21-22, 1997 meeting. If the EITF is able to reach a consensus on this matter, SCE will be required to follow the EITF's guidance. If SCE is required to discontinue the application of these regulatory accounting standards for its generation-related assets, and the EITF does not change the current requirements of these standards, SCE would have to write off generation-related regulatory assets, which at March 31, 1997, totaled approximately $500 million on an after-tax basis, primarily for the recovery of income tax benefits previously flowed- through to customers, purchased-power agreement termination payments, unamortized loss on reacquired debt and the Palo Verde phase-in plan. page 9 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SCE believes that a proper application of regulatory accounting standards will result in it no longer meeting the criteria to apply these accounting standards to all of its non-hydroelectric generation-related assets after the end of the 1998-2001 transition period. If SCE continues the application of these accounting standards during the transition period, but during the transition period events occur that result in SCE no longer meeting the criteria for applying such standards, SCE may be required to write off the remaining balance of its recorded generation-related regulatory assets existing at that time. If a non-cash write-off is required, SCE believes that it should not affect the stranded-cost recovery plans set forth in the CPUC's December 1995 restructuring decision and legislation enacted by the State of California in September 1996. Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been applied absent the regulatory process, SCE believes that the depreciable lives of its generation-related assets would not vary significantly from that of an unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets. SCE also believes that any depreciation-related differences would be recovered through the CTC. If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not recovered through another regulatory mechanism. At this time, SCE cannot predict what other revisions will ultimately be made during the restructuring process in subsequent proceedings or implementation phases, or the effect, after the transition period, that competition will have on its results of operations or financial position. FERC Restructuring Decision In April 1996, the FERC issued its decision on stranded cost recovery and open access transmission, effective July 1996. The decision, reaffirmed in a March 1997 FERC order, requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also provides utilities with the recovery of stranded costs, which are prior-service costs incurred under the current regulatory framework. In addition to providing recovery of stranded costs associated with existing wholesale customers, the FERC directed that it would have primary jurisdiction over the recovery of stranded costs associated with retail-turned-wholesale customers, such as the formation of a new municipal electric system. Retail stranded costs resulting from a state-authorized retail direct-access program are the responsibility of the states and the FERC would only address recovery of these costs if the state has no authority to do so. In compliance with the April 1996 FERC decision, SCE filed a revised open access tariff with the FERC in July 1996. The tariff became effective on an interim basis, subject to refund, as of its filing date. The FERC accepted SCE's compliance filing in February 1997. SCE will revise its tariff to reflect the few revisions set forth in the FERC's March 1997 order. page 10 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Canadian Gas Contracts In May 1994, SCE filed its testimony in the non-Qualifying Facilities phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995, the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the reasonableness of SCE's gas supply costs for both the 1993 and 1994 record periods. The report recommends a disallowance of $13 million for excessive costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas purchase and supply contracts. The report requests that the CPUC defer finding SCE's Canadian supply and transportation agreements reasonable for the duration of their terms and that the costs under these contracts be reviewed on a yearly basis. In October 1996, the ORA issued its report for the 1995 record period recommending a $38 million disallowance for excessive costs incurred from April 1994 through March 1995. Both proposed disallowances have been consolidated into one proceeding. SCE and the ORA have filed several rounds of testimony on this issue. Hearings began in January 1997 and concluded in February 1997. A decision is expected in late 1997. Note 2. Contingencies In addition to the matters disclosed in these notes, Edison International is involved in legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these proceedings will not materially affect its results of operations or liquidity. Brooklyn Navy Yard Project Edison Mission Energy (EME), a subsidiary of Edison International, owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard project; however, it is initially funding all of the required equity and debt ($492 million) for the project and has provided a guarantee as a condition of obtaining financing for the project. In February 1997, the contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY) and has served a Complaint filed in California State Court for damages in the amount of $137 million against BNY. In addition to defending this action, BNY has filed an action against the contractor in New York State Court asserting general monetary claims in excess of $13 million under the turnkey agreement. EME believes that the outcome of this litigation will not materially affect its results of operations or financial position. Environmental Protection Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Edison International records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International 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. page 11 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENT Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (classified as other long- term liabilities at undiscounted amounts). While Edison International has numerous insurance policies that it believes may provide coverage for some of these liabilities, it does not recognize recoveries in its financial statements until they are realized. Edison International's recorded estimated minimum liability to remediate its 55 identified sites (54 at SCE and 1 at EME) was $112 million at March 31, 1997. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $211 million. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. The CPUC allows SCE to recover environmental-cleanup costs at 35 of its sites, representing $96 million of Edison International's recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $101 million for its estimated minimum environmental- cleanup costs expected to be recovered through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can now be made for these sites. Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $4 million to $10 million. Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup costs, Edison International believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates. Nuclear Insurance Federal law limits public liability claims from a nuclear incident to $8.9 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident page 12 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $79 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of $158 million per nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million has also been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. These policies are issued primarily by mutual insurance companies owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $34 million per year. Insurance premiums are charged to operating expense. page 13 EDISON INTERNATIONAL Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition In the following Management's Discussion and Analysis of Results of Operations and Financial Condition and elsewhere in this quarterly report, the words "estimates," "expects," "anticipates," "believes," and other similar expressions, are intended to identify forward-looking information that involves risks and uncertainties. Actual results or outcomes could differ materially as a result of such important factors as the outcome of state and federal regulatory proceedings affecting the restructuring of the electric utility industry, the impacts of new laws and regulations relating to restructuring and other matters, the effects of increased competition in the electric utility business, and changes in prices of electricity and costs for fuel. RESULTS OF OPERATIONS First Quarter 1997 vs. First Quarter 1996 Earnings Edison International's earnings per share were 35 cents for the first quarter of 1997, compared to 38 cents for the first quarter of 1996. Southern California Edison Company's (SCE) earnings were 27 cents per share, compared to 31 cents for the first quarter of 1996. The decline of SCE's earnings is primarily due to a revised ratemaking plan for SCE's nuclear units (see Regulatory Matters) and a scheduled refueling outage at San Onofre Nuclear Generating Station Unit 2 during the entire first quarter (see San Onofre Steam Generator Tubes). This decrease was partially offset by improved overall operating performance, including a strong performance at San Onofre Unit 3. Edison Mission Energy's (EME), Edison Capital's and Mission Land Company's earnings per share were 10 cents, up 3 cents from the same period in 1996. The increase is primarily due to higher earnings from EME's foreign projects, particularly First Hydro, which benefited from higher energy prices and increased utilization. The parent company and new subsidiaries had expenses of 2 cents per share, up 2 cents from the same period last year, due to start-up costs at the new subsidiaries. Edison International's earnings per share decline was partially offset by a 2 cents increase from the effects of the ongoing share repurchase program. Operating Revenue Electric utility revenue decreased 4%, as increased sales volume was more than offset by lower average rates. Average retail rates were approximately 5% lower during the first quarter of 1997, compared with same period for the prior year. The lower rates are attributable to the continuing effects of the California Public Utilities Commission's (CPUC) decision effective April 1996 which lowered SCE's 1996 authorized revenue by $338 million, or 4.4%. Rates in 1997 are unchanged from April 1996. Over 98% of SCE's electric utility revenue is from retail sales. Retail rates are regulated by the CPUC and wholesale rates are regulated by the Federal Energy Regulatory Commission (FERC). In March 1995, SCE announced a five-year goal to reduce system average rates by 25% on an inflation-adjusted basis (from 10.7 cents per kilowatt-hour to below 10 cents per kilowatt-hour). In February 1996, the CPUC approved a system-wide rate reduction which lowered the average price per kilowatt- hour from 10.7 cents to 10.1 cents, effective June 1996. Legislation enacted in September 1996 provides, among other things, at least a 10% rate reduction for residential and small commercial customers beginning in 1998 (see Competitive Environment). page 14 Revenue from diversified operations increased substantially due to additional revenue associated with the start-up of EME's Loy Yang B Unit 2 and Kwinana projects. These projects began commercial operations during the fourth quarter of 1996. There was no comparable revenue from these projects in the first quarter of 1996. In addition, higher pool prices and increased utilization contributed to increased revenue at EME's First Hydro project. On March 31, 1997, EME announced that it has entered into agreements with the State Electricity Commission of Victoria to acquire the remaining 49% interest of the Loy Yang B power plant near Melbourne, Australia. This acquisition was completed in May 1997. EME is now the sole owner of Loy Yang B which consists of two coal-fired 500 megawatt units and generates approximately 18% of the State of Victoria's electricity. Operating Expenses Fuel expense increased 40% due to higher gas prices and changes in the fuel mix. A scheduled refueling outage at San Onofre Unit 2 resulted in higher gas-powered generation. There was no comparable outage in 1996. Fuel expense also increased at EME due to the start-up of the Loy Yang B Unit 2 and Kwinana projects in the fourth quarter 1996 and higher costs for pumping fuel due to increased generation at the First Hydro project during the first quarter. Purchased-power expense increased 19%, due to an increase in power purchased under federally mandated contracts. SCE is required under federal law to purchase power from certain nonutility generators even though energy prices under these contracts are generally higher than other sources. For the twelve months ended March 31, 1997, SCE paid about $1.7 billion (including energy and capacity payments) more for these power purchases than the cost of power available from other sources. The CPUC has mandated the prices for these contracts. Provisions for regulatory adjustment clauses decreased substantially due to actual energy costs exceeding CPUC-authorized fuel and purchased-power cost estimates and undercollections resulting from the accelerated recovery of SCE's remaining investment in San Onofre Units 2 and 3. These undercollections were partially offset by overcollections associated with actual base-rate revenue from kilowatt-hour sales exceeding CPUC- authorized amounts and incentive pricing associated with operating efficiencies at San Onofre Units 2 and 3. Maintenance expense increased 14%, primarily due to the San Onofre Unit 2 scheduled refueling outage for the entire first quarter. There was no comparable outage for the same period in 1996. Maintenance expense also increased at EME due to the commercial start-up of the Loy Yang B Unit 2 and Kwinana projects during the fourth quarter of 1996. There were no comparable maintenance costs associated with these projects during the same period in 1996. Depreciation and decommissioning expense increased 29% due to higher depreciation rates and the accelerated recovery of San Onofre Units 2 and 3 effective April 1996 and of the Palo Verde Nuclear Generating Station units effective January 1997. Depreciation and decommissioning expense increased at EME due to the start-up of Loy Yang B Unit 2, which began commercial operation in October 1996. Income taxes decreased 14% due to a decrease in pre-tax income. Property and other taxes decreased 32% due to lower property taxes and lower payroll taxes related to workforce reductions after SCE's voluntary retirement programs in 1996. The provision for rate phase-in plan reflects a CPUC-authorized, 10-year rate phase-in plan, which deferred the collection of revenue during the first four years of operation for the Palo Verde units. The deferred page 15 revenue (including interest) is being collected evenly over the final six years of each unit's plan. The plan ended in February 1996 and September 1996 for Units 1 and 2, respectively. The plan ends in January 1998 for Unit 3. The provision is a non-cash offset to the collection of deferred revenue. Minority interest increased substantially, primarily from EME's Loy Yang B Unit 2 project, which began commercial operation in the fourth quarter of 1996. Other nonoperating income decreased, primarily due to increased costs resulting from the effect of a rise in Edison International's stock price on SCE's stock option plan and additional accruals at SCE for regulatory matters. Interest and Other Expenses Other interest expense increased substantially, due to an increase in interest related to balancing account overcollections. Capitalized interest decreased, primarily due to the completion of EME's Loy Yang B Unit 2 and other projects in the fourth quarter of 1996. FINANCIAL CONDITION Edison International's liquidity is primarily affected by debt maturities, dividend payments, capital expenditures and investments in partnerships and unconsolidated subsidiaries. Capital resources include cash from operations and external financings. Edison International's board of directors has authorized the repurchase of up to $800 million of its common stock. Edison International has repurchased 38.6 million shares ($739 million) through May 5, 1997, funded by dividends from its subsidiaries and its lines of credit. For the first quarter of 1997, Edison International's cash flow coverage of dividends decreased to 5.4 times from 6.9 times for the same period in 1996, as a result of the ongoing share repurchase program. Edison International's dividend payout ratio for the twelve-month period ended March 31, 1997, was 62%. Cash Flows from Operating Activities Net cash provided by operating activities totaled $603 million in the first quarter of 1997, compared to $766 million in the first quarter of 1996. Cash from operations exceeded capital requirements for both periods presented. Cash Flows from Financing Activities At March 31, 1997, Edison International and its subsidiaries had $1.9 billion of borrowing capacity available under lines of credit totaling $2.2 billion. SCE had available lines of credit of $1.1 billion, with $600 million for short-term debt and $500 million for the long-term refinancing of its variable-rate pollution-control bonds. The parent company had a $450 million line of credit with $165 million of borrowing capacity available. The nonutility companies had available lines of credit of $700 million, with $600 million of borrowing capacity available to finance general cash requirements. Edison International's unsecured lines of credit are at negotiated or bank index rates with various expiration dates; the majority have five-year terms. SCE's short-term debt is used to finance fuel inventories, balancing account undercollections and general cash requirements. EME uses short- term debt and available credit lines mainly for construction projects until long-term construction or project loans are secured. Long-term debt page 16 is used mainly to finance capital expenditures. SCE's external financings are influenced by market conditions and other factors, including limitations imposed by its articles of incorporation and trust indenture. As of March 31, 1997, SCE could issue approximately $7.9 billion of additional first and refunding mortgage bonds and $4.5 billion of preferred stock at current interest and dividend rates. EME owns, through a wholly-owned subsidiary, 50% of the Brooklyn Navy Yard project; but funded all of the required equity during construction and will be required to fund the remaining costs of the project facility until the close of nonrecourse financing. The estimated total cost is $492 million, of which $450 million had been spent through March 31, 1997. In December 1995, a tax-exempt bond financing for the project in the amount of $254 million was obtained through the New York City Industrial Development Agency (NYCIDA). EME has guaranteed the obligations of the project pursuant to the financing, as well as an indemnity agreement on behalf of NYCIDA in the amount of $40 million. In February 1997, the contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY) and has served a Complaint filed in California State Court for damages in the amount of $137 million against BNY. In addition to defending this action, BNY has filed an action against the contractor in New York State Court asserting general monetary claims in excess of $13 million under the turnkey agreement. EME believes that the outcome of this litigation will not materially affect its results of operations or financial position. EME has firm commitments to make equity and other contributions to its projects of $353 million, primarily for the Paiton project in Indonesia and the ISAB project in Italy. EME also has contingent obligations to make additional contributions of $463 million, primarily for the guarantee to secure payment of the bonds issued pursuant to the $254 million tax- exempt financing for the Brooklyn Navy Yard project and equity support guarantees related to Paiton. In April 1997, EME completed financing and commenced construction of the Doga Enerji Cogeneration Project, a 180 megawatt gas-powered power plant near Istanbul, Turkey. EME will own 80% of this project. In connection with the financing, EME has guaranteed equity contributions and subordinated debt totaling $58 million. Commercial operation is scheduled for late 1998. EME may incur additional obligations to make equity and other contributions to projects in the future. EME believes it will have sufficient liquidity to meet these equity requirements from cash provided by operating activities, proceeds from the repayment of loans to energy projects, funds available from EME's revolving line of credit and additional corporate borrowings. California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At March 31, 1997, SCE had the capacity to pay $285 million in additional dividends and continue to maintain its authorized capital structure. These restrictions are not expected to affect Edison International's ability to meet its cash obligations. Cash Flows from Investing Activities The primary uses of cash for investing activities are additions to property and plant, the nonutilities' investments in partnerships and unconsolidated subsidiaries, and funding of nuclear decommissioning trusts. Decommissioning costs are accrued and recovered in rates over the term of each nuclear generating facility's operating license through page 17 charges to depreciation expense. SCE estimates that it will spend approximately $12.7 billion between 2013-2070 to decommission its nuclear facilities. This estimate is based on SCE's current-dollar decommissioning costs ($2.0 billion), escalated using a 6.65% annual rate. These costs are expected to be funded from independent decommissioning trusts which receive SCE contributions of approximately $100 million per year until decommissioning begins. Cash used for the nonutility subsidiaries' investing activities was $30 million for the three-month period ended March 31, 1997, compared to $128 million for the same period in 1996. Edison International's risk management policy allows the use of derivative financial instruments to mitigate risk. Changes in interest rates, electricity pool pricing in the United Kingdom and fluctuations in foreign currency exchange rates can have a significant impact on EME's results of operations. EME attempts to mitigate the risk of interest rate fluctuations by arranging for fixed rate or variable rate financing with interest rate swaps or other hedging mechanisms for the majority of its project financings. As a result of interest rate hedging mechanisms, interest expense increased $3 million in the first quarter of 1997 and $2 million in the first quarter of 1996. The maturity dates of several of EME's interest rate swap agreements do not correspond to the term of the underlying debt. EME does not believe that interest rate fluctuations will have a material adverse effect on its results of operations or financial position. Projects in the United Kingdom sell their electrical energy and capacity through a centralized electricity pool, which establishes a half-hourly clearing price for electric energy and capacity. The pool price is extremely volatile, and can vary by a factor of ten or more over the course of a few hours due to large differentials in demand according to the time of day. First Hydro mitigates a portion of the market risk of the pool by entering into contracts for differences (electricity rate swap agreements), related to either the selling or purchase price of power, whereby a contract specifies a price at which the electricity will be traded, and the parties to the agreements make payments, calculated based on the difference between the price in the contract and the half hourly clearing price for the element of power under contract. These contracts act as a means of stabilizing production revenue or purchasing costs by removing an element of First Hydro's net exposure to pool price volatility. First Hydro's electric revenue increased by $15 million in the first quarter of 1997, compared to a decrease of $4 million in the corresponding period of the prior year, as a result of electricity rate swap agreements. As EME continues to expand into foreign markets, fluctuations in foreign currency exchange rates will continue to affect the amount of its equity contributions to, distributions from, and results of operations for, its foreign projects. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates where it deems appropriate through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. Various statistical forecasting techniques are used to help assess foreign exchange risk and the probabilities of various outcomes. There can be no assurance, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or forecasted relationships. Projected Capital Requirements Edison International's projected capital requirements for the next five twelve-month periods following March 31, 1997, are: 1997--$861 million; page 18 1998--$881 million; 1999--$756 million; 2000--$730 million; and 2001--$711 million. Long-term debt maturities and sinking fund requirements for the five twelve-month period following March 31, 1997, are: 1998--$573 million; 1999--$544 million; 2000--$664 million; 2001--$279 million; and 2002--$401 million. REGULATORY MATTERS SCE's 1997 CPUC-authorized rates are unchanged from 1996 levels due to recently enacted legislation which requires that system average rates remain frozen at the June 10, 1996, level of 10.1 cents per kilowatt-hour (see discussion in Competitive Environment). The CPUC's 1997 cost-of-capital decision authorized SCE's common equity ratio to remain at 48%. SCE's return on common equity also remains at 11.6%. SCE's return on rate base was lowered from 9.55% to 9.49%. This decision, excluding the effects of other rate actions, would reduce 1997 earnings by approximately 1 cent per share. The CPUC has authorized revised rate-making plans for SCE's nuclear facilities, which calls for the accelerated recovery of its nuclear investments in exchange for a lower authorized rate of return. SCE's nuclear assets are now earning an annual rate of return of 7.35%, compared to the current 9.49% for other assets. In addition, the San Onofre plan authorizes a fixed rate of approximately 4 cents per kilowatt-hour generated for incremental operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel financing costs. The San Onofre plan commenced in April 1996, and ends in December 2001 for accelerated recovery portion and in December 2003 for the incremental pricing portion. Palo Verde's incremental operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel financing costs, are subject to balancing account treatment. The Palo Verde plan commenced in January 1997 and ends in December 2001. In May 1994, SCE filed its testimony in the non-Qualifying Facilities phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995, the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the reasonableness of SCE's gas supply costs for both the 1993 and 1994 record periods. The report recommends a disallowance of $13 million for excessive costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas purchase and supply contracts. The report requests that the CPUC defer finding SCE's Canadian supply and transportation agreements reasonable for the duration of their terms and that the costs under these contracts be reviewed on a yearly basis. In October 1996, the ORA issued its report for the 1995 record period recommending a $38 million disallowance for excessive costs incurred from April 1994 through March 1995. Both proposed disallowances have been consolidated into one proceeding. SCE and the ORA have filed several rounds of testimony on this issue. Hearings concluded in February 1997. A decision is expected in late 1997. COMPETITIVE ENVIRONMENT SCE currently operates in a highly regulated environment in which it has an obligation to provide electric service to customers in return for an exclusive franchise within its service territory. This regulatory environment is changing. The generation sector has experienced competition from nonutility power producers and regulators are restructuring California's electric utility industry. California Electric Utility Industry Restructuring The CPUC's December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which page 19 is expected to provide competition and customer choice and is scheduled to begin January 1, 1998. Key elements of the CPUC's restructuring decision include: creation of an independent power exchange (PX) and independent system operator (ISO); availability of direct customer access and customer choice; performance-based ratemaking (PBR) for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation, and implementation of a non-bypassable charge to all customers called the competition transition charge (CTC). In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopts the CPUC's December 1995 restructuring decision by addressing stranded-cost recovery for utilities, and providing a certain cost-recovery time period for the transition costs associated with utility-owned generation-related assets. Transition costs related to power-purchase contracts would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also includes provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow Southern California Edison Company (SCE), a subsidiary of Edison International, to reduce rates by at least 10% to these customers, beginning January 1, 1998. The financing would occur with securities issued by the California Infrastructure and Economic Development Bank, or an entity approved by the Bank. The legislation includes a rate freeze for all other customers, including large commercial and industrial customers, as well as provisions for continued funding for energy conservation, low-income programs and renewable resources. Despite the rate freeze, SCE expects to be able to recover its revenue requirement based on cost-of-service regulation during the 1998-2001 transition period. In addition, the legislation mandates the implementation of a non-bypassable CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation contains provisions for the recovery (through 2006) of reasonable employee-related transition costs incurred and projected for retraining, severance, early retirement, outplacement and related expenses for utility workers. On May 6, 1997, SCE filed an application with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billion of rate reduction bonds in one or more series or classes and a 10% rate reduction for the period from January 1, 1998, through May 31, 2002. On the same day, SCE filed an application with the California Infrastructure and Economic Development Bank for approval to issue the bonds. Residential and small commercial customers will repay the bonds over the expected 10- year term through non-bypassable charges based on electricity consumption. With the CPUC's decision expected in September 1997, and subject to the prior approval of the Infrastructure Bank, it is anticipated that the rate reduction bonds will be issued in the fourth quarter of 1997. In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the Federal Energy Regulatory Commission (FERC) regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities to file more specific information which was filed on March 31, 1997. In July 1996, the three utilities jointly filed an application with the CPUC requesting approval to establish a restructuring trust which would obtain loans up to $250 million for the development of the ISO and PX through January 1, 1998. The loans would be backed by utility guarantees; SCE's share would be 45%. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million which will be used to build the hardware and software systems for the ISO and PX. page 20 On May 6, 1997, the CPUC issued a decision describing how all California investor-owned utility customers will be able to choose who will provide them with electric generation service. Beginning January 1, 1998, customers will be able to choose to purchase power from the PX through SCE, or choose direct access, which means the customer can contract directly with either independent power producers or retail electric service providers such as power brokers, marketers and aggregators. Additionally, all investor-owned utility customers must pay the CTC whether or not they choose to buy power through SCE. Electric utilities will continue to provide the core distribution service of delivering energy through its distribution system regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could implement a contingency plan. However, the CPUC believes it is likely that interest in and migration to direct access will be gradual. A second decision issued by the CPUC on May 6, 1997, introduces customer choice to metering, billing and related services (referred to as revenue cycle services) that are now provided by California's investor-owned utilities. Under this revenue cycle services "unbundling" decision, beginning in January 1998, customers may choose to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this option beginning in January 1999. In determining whether any credit should be provided by the utility to firms providing customers with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to "net" the cost incurred by the utility and the cost avoided by the utility as a result of such services being provided by the other firm rather than by the utility. The unbundling of revenue cycle services is likely to expose SCE to the loss of revenue, higher stranded costs and a reduction in revenue security. SCE is reviewing the potential effect of these decisions on its results of operations and financial condition. In July 1996, SCE filed a PBR proposal for its hydroelectric plants and a proposed structure for performance-based local reliability contracts for certain fossil-fueled plants. If approved, the hydro PBR would be in effect for three years and the initial terms of the local reliability contracts, which are subject to FERC approval, would be in effect for up to three years, both beginning January 1, 1998. A final CPUC decision on hydro PBR is expected by year-end 1997. In September 1996, the CPUC adopted a non-generation transmission and distribution (T&D) PBR mechanism for SCE which began on January 1, 1997. According to the CPUC decision, beginning in 1998, the transmission portion is to be separated from non- generation PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001. Key elements of the non-generation PBR include: T&D rates indexed for inflation based on the Consumer Price Index less a productivity factor; elimination of the kilowatt-hour sales adjustment; adjustments for cost changes that are not within SCE's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will share gains and losses from T&D operations. In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all of its oil- and gas-fueled generation assets. This application builds on SCE's March 1996 plan which outlined how SCE proposed to divest 50% of these assets. Under the new proposal, SCE would continue to operate and maintain the divested power plants for at least two years following their sale, as mandated by the recent restructuring legislation. In addition, SCE would offer workforce transition programs page 21 to those employees who may be impacted by divestiture-related job reductions. SCE's proposal is contingent on the overall electric industry restructuring implementation process continuing on a satisfactory path. CPUC approval of the oil- and gas-fueled generation divestiture was requested for late 1997. In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996 filing related to the conceptual aspects of separating costs as requested by CPUC and FERC directives) for the functional unbundling of its rates for electric service, beginning on January 1, 1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates in separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning. Hearings on SCE's rate unbundling plan were concluded in April 1997. A final decision on this matter is expected in the third quarter of 1997. Recovery of costs to transition to a competitive market would be implemented through a non-bypassable CTC. This charge would apply to all customers who were using or began using utility services on or after the December 20, 1995, decision date. In August 1996, in compliance with the CPUC's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September 1996. Under the rate freeze codified in the legislation, the CTC will be determined residually (i.e., after subtracting other cost components for the PX, T&D, nuclear decommissioning and public benefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately $13.1 billion (1998 net present value), assuming the fossil plants have a market value equal to their net book value, and $13.8 billion (1998 net present value), assuming the fossil plants have no market value. These estimates are based on incurred costs, and forecasts of future costs and assumed market prices. However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of: $7.5 billion from SCE's qualifying facility contracts, which are the direct result of legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUC) to provide service to customers. Such commitments include the recovery of income tax benefits previously flowed-through to customers, postretirement benefit transition costs, accelerated recovery of San Onofre and Palo Verde and certain other costs. On February 14, 1997, SCE submitted an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included. Hearings on various phases of this issue began in December 1996 and will continue throughout 1997. A decision is expected before January 1, 1998. If the CPUC's restructuring is implemented as outlined, SCE would be allowed to recover its CTC (subject to a lower return on equity) and believes it should be allowed to continue to apply accounting standards that recognize the economic effects of rate regulation for its generation- related assets during the 1998-2001 transition period. However, in response to a request by the staff of the Securities and Exchange Commission (SEC), in December 1996, SCE submitted its views on the continued applicability of regulatory accounting standards for its generation-related assets. In its submittal, SCE and its independent accountants jointly concluded that, based on their current analysis, SCE will continue to meet the criteria for applying these accounting standards through the 1998-2001 transition period. In its February 1997 response, the SEC staff expressed continuing concern with SCE's conclusion and page 22 indicated that they wanted to meet further with SCE and the other major California electric utilities to resolve this matter. SCE and the other major California electric utilities met with the SEC in March 1997. Subsequently, the SEC asked a series of questions to be answered by each of California's major electric utilities. SCE responded to the SEC's questions in early April 1997. The authority to require SCE to discontinue applying regulatory accounting standards rests with the SEC, although matters such as this can be referred to the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) for resolution. On April 28, 1997, this regulatory accounting matter was added to the EITF's agenda for discussion at its May 21-22, 1997 meeting. If the EITF is able to reach a consensus on this matter, SCE will be required to follow the EITF's guidance. If SCE is required to discontinue the application of these regulatory accounting standards for its generation-related assets, and the EITF does not change the current requirements of these standards, SCE would have to write off generation-related regulatory assets, which at March 31, 1997, totaled approximately $500 million on an after-tax basis, primarily for the recovery of income tax benefits previously flowed- through to customers, purchased-power agreement termination payments, unamortized loss on reacquired debt and the Palo Verde phase-in plan. SCE believes that a proper application of regulatory accounting standards will result in it no longer meeting the criteria to apply these accounting standards to all of its non-hydroelectric generation-related assets after the end of the 1998-2001 transition period. If SCE continues the application of these accounting standards during the transition period, but during the transition period events occur that result in SCE no longer meeting the criteria for applying such standards, SCE may be required to write off the remaining balance of its recorded generation-related regulatory assets existing at that time. If a non-cash write-off is required, SCE believes that it should not affect the stranded-cost recovery plans set forth in the CPUC's December 1995 restructuring decision and legislation enacted by the State of California in September 1996. Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been applied absent the regulatory process, SCE believes that the depreciable lives of its generation-related assets would not vary significantly from that of an unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets. SCE also believes that any depreciation-related differences would be recovered through the CTC. If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not recovered through another regulatory mechanism. At this time, SCE cannot predict what other revisions will ultimately be made during the restructuring process in subsequent proceedings or implementation phases, or the effect, after the transition period, that competition will have on its results of operations or financial position. FERC Restructuring Decision In April 1996, the FERC issued its decision on stranded cost recovery and open access transmission, effective July 1996. The decision, reaffirmed in a March 1997 FERC order, requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also provides utilities with the recovery of stranded costs, which are prior-service costs incurred under the current regulatory framework. In addition to providing recovery of page 23 stranded costs associated with existing wholesale customers, the FERC directed that it would have primary jurisdiction over the recovery of stranded costs associated with retail-turned-wholesale customers, such as the formation of a new municipal electric system. Retail stranded costs resulting from a state-authorized retail direct-access program are the responsibility of the states and the FERC would only address recovery of these costs if the state has no authority to do so. In compliance with the April 1996 FERC decision, SCE filed a revised open access tariff with the FERC in July 1996. The tariff became effective on an interim basis, subject to refund, as of its filing date. The FERC accepted SCE's compliance filing in February 1997. SCE will revise its tariff to reflect the few revisions set forth in the March 1997 order. ENVIRONMENTAL PROTECTION Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. As further discussed in Note 2 of "Notes to Consolidated Financial Statements," Edison International records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site. Unless there is a probable amount, Edison International records the lower end of this range of costs. Edison International's recorded estimated minimum liability to remediate its 55 identified sites (54 at SCE and 1 at EME) was $112 million at March 31, 1997. One of SCE's sites, a former pole-treating facility, is considered a federal Superfund site and represents 72% of Edison International's recorded liability. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $211 million. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. The CPUC allows SCE to recover environmental-cleanup costs at 35 of its sites, representing $96 million of Edison International's recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $101 million for its estimated minimum environmental- cleanup costs expected to be recovered through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can now be made for these sites. Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $4 million to $10 million. page 24 Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup costs, Edison International believes that costs ultimately recorded will not have a material adverse effect on its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates. The 1990 federal Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide. Power companies receive emissions allowances from the federal government and may bank or sell excess allowances. SCE expects to have excess allowances under Phase II of the Clean Air Act (2000 and later). The act also calls for a study to determine if additional regulations are needed to reduce regional haze in the southwestern U.S. In addition, another study is in progress to determine the specific impact of air contaminant emissions from the Mohave Coal Generating Station on visibility in Grand Canyon National Park. The potential effect of these studies on sulfur dioxide emissions regulations for Mohave is unknown. Edison International's projected capital expenditures to protect the environment are $831 million for the 1997-2001 period, mainly for aesthetics treatment, including undergrounding certain transmission and distribution lines. The possibility that exposure to electric and magnetic fields (EMF) emanating from power lines, household appliances and other electric sources may result in adverse health effects is receiving increased attention. The scientific community has not yet reached a consensus on the nature of any health effects of EMF. However, the CPUC has issued a decision which provides for a rate-recoverable research and public education program conducted by California electric utilities, and authorizes these utilities to take no-cost or low-cost steps to reduce EMF in new electric facilities. SCE is unable to predict when or if the scientific community will be able to reach a consensus on any health effects of EMF, or the effect that such a consensus, if reached, could have on future electric operations. PALO VERDE STEAM TUBE RUPTURE In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional cracking was found in other tubes. Arizona Public Service Company (APS), the operating agent for Palo Verde, has taken, and will continue to take, remedial actions that it believes have slowed the rate of steam generator tube degradation in all three units. APS believes that the steam generators in Unit 2 will have to be replaced within five to ten years. SCE estimates its share of the steam generator replacement costs to be between $16 million and $30 million, plus replacement power costs. SCE is evaluating APS' analyses, conducting its own review, and has not yet decided whether it supports replacement of the steam generators. SAN ONOFRE STEAM GENERATOR TUBES The San Onofre Units 2 and 3 steam generators have performed relatively well through the first 15 years of operation, with low rates of ongoing tube degradation. During the most recent Unit 2 refueling and inspection outage, however, an increased rate of degradation was identified, resulting in removing 1.8% of the tubes from service. The cumulative total of Unit 2's tubes removed from service is now 5.5%, well below the maximum 10% allowed in the steam generator design before the rating capacity of the unit must be reduced. As a result of the increased degradation, a mid-cycle inspection outage will be conducted in 1998 for Unit 2. Depending on the results of the current refueling and inspection page 25 outage for Unit 3, a mid-cycle inspection outage may also be required in 1998 for that unit. During the current, scheduled 75-day refueling outage of Unit 3, which began in April 1997, inspections of structural supports for steam generator tubes identified several areas where the thickness of the supports had been reduced, apparently by erosion during normal plant operation. Additional inspection and analysis is continuing, and the results will be reviewed with the Nuclear Regulatory Commission in early June 1997. Corrective actions may include removing a limited number of tubes from service by plugging, which could be completed within the scheduled outage. Additional actions could be required which might extend the outage. In the recent inspection of Unit 2's steam generators, the similar tube supports showed no signs of the erosion affecting Unit 3. NEW EARNINGS PER SHARE STANDARD A new accounting pronouncement establishes standards for computing and presenting earnings per share. The standard must be implemented for year- end 1997 financial reports and, in some instances, will require restatement of prior-period earnings per share data; earlier application of the standard is not permitted. The standard will not have any effect on reported earnings per share. PROPOSED NEW ACCOUNTING STANDARD During 1996, the Financial Accounting Standards Board issued an exposure draft that would establish accounting standards for the recognition and measurement of closure and removal obligations. The exposure draft would require the estimated present value of an obligation to be recorded as a liability, along with a corresponding increase in the plant or regulatory asset accounts when the obligation is incurred. If the exposure draft is approved in its present form, it would affect SCE's accounting practices for the decommissioning of its nuclear power plants, obligations for coal mine reclamation costs and any other activities related to the closure or removal of long-lived assets. SCE does not expect that the accounting changes proposed in the exposure draft would have an adverse effect on its results of operations even after deregulation due to its current and expected future ability to recover these costs through customer rates. The nonutility subsidiaries are currently reviewing what impact the exposure draft may have on their results of operations and financial position. page 26 PART II--OTHER INFORMATION Item 1. Legal Proceedings Edison Mission Energy PMNC Litigation In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County, entitled The Parsons Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which plaintiffs assert general monetary claims under the construction turnkey agreement in the amount of $136.8 million. In addition to defending this action, Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the construction turnkey agreement. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations. Southern California Edison Company QF Litigation On May 20, 1993, four geothermal QFs filed a lawsuit against SCE in Los Angeles County Superior Court, claiming that SCE underpaid, and continues to underpay, the plaintiffs for energy. SCE denied the allegations in its response to the complaint. The action was brought on behalf of Vulcan/BN Geothermal Power Company, Elmore L.P., Del Ranch L.P., and Leathers L.P., each of which was partially owned by a subsidiary of Edison Mission Energy (a subsidiary of Edison International) at the time of filing. In April 1996, Edison Mission Energy's 50% share in these projects was sold to CalEnergy. In October 1994, plaintiffs submitted an amended complaint to the court to add causes of action for unfair competition and restraint of trade. In July 1995, after several motions to strike had been heard by the court, the plaintiffs served a fourth amended complaint, which omitted the previous claims based on alleged restraint of trade. The plaintiffs allege in the fourth amended complaint that past underpayments have totaled at least $21 million. In other court filings, plaintiffs contend that additional contract payments owing from the beginning of the alleged underpayments through the end of the contract term could total approximately $60 million. Plaintiffs also seek unspecified punitive damages and an injunction to enjoin SCE from "future" unfair competition. After SCE's motion to strike portions of the fourth amended complaint was denied, SCE filed an answer to the fourth amended complaint which denies its material allegations. On May 1, 1996, the parties entered into an agreement for a settlement of all claims in dispute. Pursuant to the agreement, the specific terms of which are confidential, a settlement amount has been paid and the parties have entered into mutual general releases, with respect to the period before January 1, 1996. SCE intends to seek recovery of this payment through rates. SCE has also agreed, subject to CPUC approval, to increase payments to plaintiffs for specified levels of energy deliveries for the period after December 31, 1995. Plaintiffs have reserved the right to continue the litigation with respect to the period after December 31, 1995, if CPUC approval is not obtained. On August 8, 1996, the Company filed its application with the CPUC for approval of the settlement as it pertains to the period after 1995. On December 20, 1996, the ORA filed a protest to the application. In its protest, the ORA requests that the CPUC not grant the application or, in the alternative, that the CPUC conduct hearings on the application. On January 17, 1997, the Company page 27 filed a reply to the ORA's request. On February 27, 1997, a prehearing conference was held, at which time SCE's application was set for hearing to commence on April 23, 1997. This hearing date was subsequently vacated by the assigned ALJ due to ongoing discussions to resolve issues raised by ORA's protest. Between January 1994 and October 1994, SCE was named as a defendant in a series of eight lawsuits brought by independent power producers of wind generation. Seven of the lawsuits were filed in Los Angeles County Superior Court and one was filed in Kern County Superior Court. The lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs by limiting fixed energy payments to a single 10-year period rather than beginning a new 10-year period of fixed energy payments for each stage of development. In its responses to the complaints, SCE denied the plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek declaratory relief regarding the proper interpretation of the contracts. Plaintiffs allege a combined total of approximately $189 million in damages, which includes consequential damages claimed in seven of the eight lawsuits. On March 1, 1995, the court in the lead Los Angeles Superior Court case granted the plaintiffs' motion seeking summary adjudication that the contract language in question is not reasonably susceptible to SCE's position that there is only a single, 10-year period of fixed payments. Following the March 1 ruling, a ninth lawsuit was filed in the Los Angeles Superior Court raising claims similar to those alleged in the first eight. SCE subsequently responded to the complaint in the new lawsuit by denying its material allegations. On April 5, 1995, SCE filed a petition for Writ of Mandate, Prohibition or Other Appropriate Relief, requesting that the Court of Appeal of the State of California, Second Appellate District issue a writ directing the Los Angeles Superior Court to vacate its March 1 order granting summary adjudication. In a decision filed August 9, 1995, the Court of Appeal issued a writ directing that the order be overturned, and a new order be entered denying the motion. In light of the Court of Appeal decision in the lead Los Angeles case, a summary adjudication motion in the Kern County case was withdrawn. On March 25, 1996, pursuant to a court-approved stipulation, all but one of the cases were consolidated for trial in Los Angeles Superior Court. Shortly thereafter, on April 3, 1997, pursuant to stipulation of the parties, the Kern County case was ordered to be coordinated with the Los Angeles cases so that it too will be tried in Los Angeles. Trial on the consolidated cases began on March 11, 1997, and is presently in progress. No trial date has been set in the ninth unconsolidated case. Environmental Litigation Electric and Magnetic Fields ("EMF") SCE is involved in three lawsuits alleging that various plaintiffs developed cancer as a result of exposure to EMF from SCE facilities. SCE denied the material allegations in its responses to each of these lawsuits. The first lawsuit was filed in Orange County Superior Court and served on SCE in June 1994. There are five named plaintiffs and six named defendants, including SCE. Three of the five plaintiffs are presently or were formerly employed by Grubb & Ellis, a real estate brokerage firm with offices located in a commercial building known as the Koll Center in Newport Beach. Two of the named plaintiffs are spouses of the other plaintiffs. Grubb & Ellis and the owners and developers of the Koll Center are also named as defendants in the lawsuit. This lawsuit alleges, among other things, that the three plaintiffs employed by Grubb & Ellis developed various forms of cancer as a result of exposure to EMF from electrical facilities owned by SCE and/or the other defendants located on Koll Center property. No specific damage amounts are alleged in the complaint, but supplemental documentation prepared by the plaintiffs indicates that plaintiffs allege compensatory damages of approximately $8 page 28 million, plus unspecified punitive damages. In December 1995, the court granted SCE's motion for summary judgment and dismissed the case. Plaintiffs have filed a Notice of Appeal. Briefs have been submitted but no date for oral argument has been set. A second lawsuit was filed in Orange County Superior Court and served on SCE in January 1995. This lawsuit arises out of the same fact situation as the June 1994 lawsuit described above and involves the same defendants. There are four named plaintiffs, two of whom were formerly employed by Grubb & Ellis and now allegedly have various forms of cancer. The other two plaintiffs are the spouses of those two individuals. No specific damage amounts are alleged in the complaint, but supplemental documentation prepared by the plaintiffs indicates that plaintiffs will allege compensatory damages of approximately $13.5 million, plus unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed a cross-complaint against the other co-defendants, requesting indemnification and declaratory relief concerning the rights and responsibilities of the parties. This case has been stayed pending appellate review of the trial judge's sanction order against the plaintiffs' attorneys. The Court of Appeals has heard oral argument on this issue, but no decision has been issued. A third case was filed in Orange County Superior Court and served on SCE in March 1995. The plaintiff alleges, among other things, that he developed cancer as a result of EMF emitted from SCE distribution lines which he alleges were not constructed in accordance with CPUC standards. No specific damage amounts are alleged in the complaint but supplemental documentation prepared by the plaintiff indicates that plaintiff will allege compensatory damages of approximately $5.5 million, plus unspecified punitive damages. No trial date has been set in this case. San Onofre Personal Injury Litigation An SCE engineer employed at San Onofre died in 1991 from cancer of the abdomen. On February 6, 1995, his children sued SCE and SDG&E, as well as Combustion Engineering, the manufacturer of the fuel rods for the plant, in the U.S. District court for the Southern District of California. Plaintiffs alleged that the former employee's illness resulted from, and was aggravated by, exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods. Plaintiffs sought unspecified compensatory and punitive damages. On April 3, 1995, the court granted the defendants' motion to dismiss 14 of the plaintiffs' claims. SCE's April 20, 1995, answer to the complaint denied all material allegations. On October 10, 1995, the court granted plaintiffs' motion to include the Institute of Nuclear Power Operations (an organization dedicated to achieving excellence in nuclear power operations) as a defendant in the suit. On December 7, 1995, the court granted SCE's motion for summary judgment on the sole outstanding claim against it, basing the ruling on the worker's compensation system being the exclusive remedy for the claim. Plaintiffs have appealed this ruling to the Ninth Circuit Court of Appeals. All trial court proceedings have been stayed pending the ruling of the Court of Appeals. The impact to SCE, if any, from further proceedings in this case against the remaining defendants cannot be determined at this time. On July 5, 1995, a former SCE reactor operator and his wife sued SCE and SDG&E in the U.S. District court for the Southern District of California. Plaintiffs also named Combustion Engineering, the manufacturer of the fuel rods for the plant, and the Institute of Nuclear Power Operations as defendants. The former employee died of leukemia shortly after the complaint was filed. Plaintiffs allege that the former operator's illness resulted from, and was aggravated by, exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods. Plaintiffs seek unspecified compensatory and punitive damages. On November 22, 1995, the complaint was amended to allege wrongful death page 29 and added the former employee's two children as plaintiffs. On December 22, 1995, SCE filed a motion to dismiss or, in the alternative, for summary judgment based on worker's compensation exclusivity. On March 25, 1996, the court granted SCE's motion for summary judgment. Plaintiffs have appealed this ruling to the Ninth Circuit Court of Appeals. All trial court proceedings have been stayed pending the ruling of the Court of Appeals in this case and in the case described in the above paragraph. The impact to SCE, if any, from further proceedings in this case against the remaining defendants cannot be determined at this time. On August 31, 1995, the wife and daughter of a former San Onofre security supervisor sued SCE and SDG&E in the U.S. District court for the Southern District of California. Plaintiffs also named Combustion Engineering, the manufacturer of fuel rods for the plant, and the Institute of Nuclear Power Operations as defendants. The security officer worked for a contractor in 1982, worked for SCE as a temporary employee (1982-1984), and later worked as an SCE security supervisor (1984-1994). The officer died of leukemia in 1994. Plaintiffs allege that the former officer's illness resulted from, and was aggravated by, his exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods. Plaintiffs seek unspecified compensatory and punitive damages. SCE's November 13, 1995, answer to the complaint denied all material allegations. All trial court proceedings have been stayed pending the rulings of the Court of Appeals in the cases described in the above two paragraphs. On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District Court for the Southern District of California. Plaintiffs also named Combustion Engineering, the manufacturer of the fuel rods for the San Onofre plant. The employee worked for SCE at San Onofre from 1981 to 1990. Plaintiffs alleged that the employee transported radioactive byproducts on his person, clothing and/or tools to his home where his wife was then exposed to radiation that caused her leukemia. Plaintiffs seek unspecified compensatory and punitive damages. SCE's December 19, 1995, partial answer to the complaint denied all material non-employment related allegations. SCE's motion to dismiss the employee's employment related allegations based on worker's compensation exclusivity was granted on March 19, 1996. The employee's wife died on August 15, 1996. On September 20, 1996, the complaint was amended to allege wrongful death and to add the employee's two children as plaintiffs. SCE's motion for summary judgment was denied on April 9, 1997. The trial is scheduled to begin on November 24, 1997. On November 28, 1995, a former contract worker at San Onofre, her husband, and her son, sued SCE in the U.S. District Court for the Southern District of California. Plaintiffs also named Combustion Engineering, the manufacturer of the fuel rods for the San Onofre plant. Plaintiffs allege that the former contract worker transported radioactive byproducts on her person and clothing to her home where her son was then exposed to radiation that caused his leukemia. Plaintiffs seek unspecified compensatory and punitive damages. SCE's January 2, 1996, answer denied all material allegations. On August 12, 1996, the Court dismissed the claims of the former worker and her husband with prejudice. This case is expected to go to trial in early 1998, after completion of the trial in the case described in the preceding paragraph. Employment Discrimination Litigation On September 21, 1994, nine African-American employees filed a lawsuit against Edison International and SCE on behalf of a class of African- American employees, alleging racial discrimination in job advancement, pay, training and evaluation. The lawsuit was filed in the United States District Court for the Central District of California. The plaintiffs sought injunctive relief, as well as an unspecified amount of compensatory and punitive damages, attorneys' fees, costs and interest. Edison page 30 International and SCE responded by denying the material allegations of the complaint and asserting several affirmative defenses. Simultaneous with discovery, the parties entered into settlement discussions. The parties agreed to include the Equal Employment Opportunity Commission (EEOC) in their settlement discussions after that agency indicated its intent to intervene in the lawsuit in support of the plaintiffs. The parties and EEOC agreed upon settlement terms and submitted a proposed Consent Decree to the court for approval. After certain issues raised by the court were addressed through a modification of the proposed Decree, the court granted preliminary approval of the modified Consent Decree on August 5, 1996, ordered that notice be given to the class members, and scheduled a final fairness hearing on September 26, 1996. Fifteen individuals and an organization filed timely objections to the proposed Consent Decree and a motion to intervene in the lawsuit. Thirteen individuals filed timely requests to be excluded from the monetary provisions of the proposed Decree. On September 25, 1996, the court denied the motion to intervene. After the hearing on September 26, at which the court heard oral argument from the objectors, the court on September 30, 1996, overruled the objections and granted final approval of the Consent Decree. The Decree provides that a settlement fund of $8.15 million for back pay claims and $3.1 million for emotional distress claims be established, and it contains an expedited claim review process for class members who make claims to the settlement fund. The Decree also provides for improvements in the Company's internal claims resolution process, expansion of career development and skills training programs, expansion of diversity training programs, and improvements in other human resources systems. The Decree has a seven-year term, with the possibility of early termination after five years. On October 25, 1996, the organization and individuals who sought to intervene and/or object to the Consent Decree served notice of appeal from the court's orders denying intervention and approving the Consent Decree. The Court of Appeals ordered that the appellants file their opening brief by March 12, 1997, and that appellees file any responsive brief by April 11, 1997. Appellants moved for an extension of time to file their opening brief, and appellees filed a joint motion to dismiss the appeal for lack of prosecution. On April 29, 1997, the Court of Appeals granted appellees' motion and ordered that the appeal be dismissed. Oil Pipeline Litigation On November 1, 1996, plaintiff, a crude oil pipeline company, filed a lawsuit against SCE and the City of Los Angeles (the "City") in the United States District Court for the Central District of California claiming that SCE and the City had interfered with its attempt to construct a proposed 132-mile oil pipeline ("Pacific Pipeline") designed to transport oil from the San Joaquin Valley and Santa Barbara to the Los Angeles refineries. Plaintiff alleges, among other things, that SCE and the City wrongfully initiated administrative and other legal proceedings in an attempt to derail and obstruct the construction of the Pacific Pipeline. Plaintiff alleges that these acts constitute unfair competition, tortious interference with economic advantage and violate state and federal antitrust laws. Plaintiff further claims that because of the alleged delays, it could suffer losses in excess of $300 million. Additionally, plaintiff seeks treble and punitive damages. The deadline for filing a response to the complaint has been continued pending the outcome of a motion by plaintiff filed in a related lawsuit seeking to dismiss the City of Los Angeles' complaint therein against the U.S. Forest Service and plaintiff. SCE intends to deny the substantive allegations of the complaint. page 31 Item 4. Submission of Matters to a Vote of Security Holders Election of Directors At Edison International's Annual Meeting of Shareholders on April 17, 1997, shareholders elected eighteen nominees to the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld from each Director-nominee were as follows: Name Number of Votes ---- --------------------------- For Withheld ----------- ---------- Howard P. Allen 342,527,189 10,674,181 John E. Bryson 342,669,433 10,531,936 Winston H. Chen 343,210,005 9,991,365 Stephen E. Frank 343,034,201 10,167,169 Camilla C. Frost 342,852,388 10,348,981 Joan C. Hanley 343,150,402 10,050,967 Carl F. Huntsinger 343,176,300 10,025,069 Charles D. Miller 343,164,009 10,037,361 Luis G. Nogales 342,958,278 10,243,092 Ronald L. Olson 343,119,801 10,081,569 J. J. Pinola 342,920,165 10,281,204 James M. Rosser 343,119,686 10,081,684 E. L. Shannon, Jr. 343,048,766 10,152,604 Robert H. Smith 343,219,811 9,981,559 Thomas C. Sutton 343,254,213 9,947,156 Daniel M. Tellep 343,215,086 9,986,283 James D. Watkins 342,914,600 10,286,770 Edward Zapanta 343,136,392 10,064,978 Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 23. Consent of Independent Public Accountants 27. Financial Data Schedule (b) Reports on Form 8-K: None page 32 SIGNATURES 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. EDISON INTERNATIONAL (Registrant) By R. K. BUSHEY --------------------------------- R. K. BUSHEY Vice President and Controller By K. S. STEWART --------------------------------- K. S. STEWART Assistant General Counsel and Assistant Secretary May 15, 1997 EX-27 2 EIX FINANCIAL DATA SCHEDULE
UT Edison International Financial Data Schedule - Exhibit 27 1,000 3-MOS DEC-31-1996 MAR-31-1997 PER-BOOK $11,561,432 7,179,591 2,125,874 3,079,541 0 23,946,438 2,491,241 77,622 3,639,305 6,208,168 425,000 283,755 4,141,431 0 3,036,996 252,694 505,047 0 68,344 18,706 9,006,297 23,946,438 2,000,725 96,076 1,547,589 1,643,665 357,060 (24,291) 332,769 176,095 156,674 11,862 144,812 103,670 91,189 603,268 $0.35 $0.34
EX-23 3 CONSENT OF IND PUBLIC ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report included in this quarterly report on Form 10-Q for the quarter ended March 31, 1997, of Edison International into the previously filed Registration Statements which follow: Registration Form File No. Effective Date ----------------- -------- -------------- Form S-3 333-08115 July 15, 1996 Form S-8 333-30913 May 16, 1996 Form S-8 33-32302 June 2, 1993 Form S-8 33-46713 June 2, 1993 Form S-8 33-46714 June 2, 1993 Form S-3 33-44148 September 17, 1993 ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Los Angeles, California May 14, 1997 -----END PRIVACY-ENHANCED MESSAGE-----