-----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, H8WLidFB5F2sEe+dDBEX6xD/4ylcHFlhZ9fC4xozSa0a5VYNNwIZB3ZM2BJq6Zb/ NJwIiW/k+EYFYuCy1tGz2g== 0000827052-97-000030.txt : 19971113 0000827052-97-000030.hdr.sgml : 19971113 ACCESSION NUMBER: 0000827052-97-000030 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19970930 FILED AS OF DATE: 19971113 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: SEC FILE NUMBER: 001-09936 FILM NUMBER: 97716086 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 INTERNATIONAL 10-Q PAGE 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 September 30, 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) 626-302-2222 (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 November 6, 1997 - -------------------------- ------------------------------- Common Stock, no par value 381,446,797 PAGE EDISON INTERNATIONAL INDEX Page No. ---- Part I. Financial Information: Item 1. Consolidated Financial Statements: Consolidated Statements of Income--Three and Nine Months Ended September 30, 1997 and 1996 2 Consolidated Balance Sheets--September 30, 1997, and December 31, 1996 3 Consolidated Statements of Cash Flows--Nine Months Ended September 30, 1997, and 1996 5 Notes to Consolidated Financial Statements 6 Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition 16 Part II. Other Information: Item 1. Legal Proceedings 32 Item 6. Exhibits and Reports on Form 8-K 38 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 9 Months Ended September 30, September 30, ------------------------ -------------------------- 1997 1996 1997 1996 ---------- --------- ---------- ---------- (Unaudited) Electric utility revenue $2,433,526 $2,346,161 $5,972,894 $5,717,283 Diversified operations 304,255 222,023 932,797 632,300 ---------- ---------- ---------- ---------- Total operating revenue 2,737,781 2,568,184 6,905,691 6,349,583 ---------- ---------- ---------- ---------- Fuel 463,069 249,385 857,630 555,065 Purchased power 900,781 938,588 2,117,116 2,026,762 Provisions for regulatory adjustment clauses -- net (185,416) (66,531) (277,439) (170,214) Other operating expenses 438,282 333,300 1,223,453 1,082,843 Maintenance 89,883 67,461 302,885 219,185 Depreciation and decommissioning 342,422 302,276 1,024,799 865,938 Income taxes 186,116 228,356 395,732 467,555 Property and other taxes 32,338 46,943 105,329 152,528 ---------- ---------- ---------- ---------- Total operating expenses 2,267,475 2,099,778 5,749,505 5,199,662 ---------- ---------- ---------- ---------- Operating income 470,306 468,406 1,156,186 1,149,921 ---------- ---------- ---------- ---------- Provision for rate phase-in plan (13,218) (22,021) (35,908) (69,966) Allowance for equity funds used during construction 1,691 3,466 5,591 10,934 Interest and dividend income 21,996 14,216 56,987 42,315 Minority interest (779) (12,812) (38,468) (40,681) Other nonoperating income (deductions) -- net (20,419) (12,172) (30,153) (2,125) ---------- ---------- ---------- ---------- Total other income (deductions) -- net (10,729) (29,323) (41,951) (59,523) ---------- ---------- ---------- ---------- Income before interest and other expenses 459,577 439,083 1,114,235 1,090,398 ---------- ---------- ---------- ---------- Interest on long-term debt 144,139 149,683 448,947 447,142 Other interest expense 34,001 22,286 90,261 67,921 Allowance for borrowed funds used during construction (2,036) (2,179) (6,733) (6,874) Capitalized interest (3,381) (19,407) (11,457) (53,055) Dividends on subsidiary preferred securities 10,063 11,881 32,593 35,626 ---------- ---------- ---------- ---------- Total interest and other expenses -- net 182,786 162,264 553,611 490,760 ---------- ---------- ---------- ---------- Net income $ 276,791 $ 276,819 $ 560,624 $ 599,638 ========== ========== ========== ========== Weighted-average shares of common stock outstanding 394,076 436,476 407,133 440,135 Earnings per share $0.70 $0.63 $1.38 $1.36 Dividends declared per common share $0.25 $0.25 $0.75 $0.75
The accompanying notes are an integral part of these financial statements. page 2 EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands
September 30, December 31, 1997 1996 ------------- ----------- (Unaudited) ASSETS Transmission and distribution utility plant, at original cost, subject to cost-based rate regulation $11,087,199 $10,973,311 Accumulated provision for depreciation (5,294,706) (5,128,652) Construction work in progress 461,850 461,048 ----------- ----------- 6,254,343 6,305,707 ----------- ----------- Generation utility plant, at original cost, not subject to cost-based rate regulation 9,502,679 9,427,076 Accumulated provision for depreciation and decommissioning (4,800,890) (4,302,419) Construction work in progress 71,598 95,597 Nuclear fuel, at amortized cost 167,682 176,827 ----------- ----------- 4,941,069 5,397,081 ----------- ----------- Total utility plant 11,195,412 11,702,788 ----------- ----------- Nonutility property -- less accumulated provision for depreciation of $238,523 and $203,256 at respective dates 3,372,037 3,570,237 Nuclear decommissioning trusts 1,608,465 1,485,525 Investments in partnerships and unconsolidated subsidiaries 1,549,553 1,371,824 Investments in leveraged leases 954,367 584,515 Other investments 124,093 103,973 ----------- ----------- Total other property and investments 7,608,515 7,116,074 ----------- ----------- Cash and equivalents 585,020 896,594 Receivables, including unbilled revenue, less allowances of $22,046 and $26,230 for uncollectible accounts at respective dates 1,322,193 1,094,498 Fuel inventory 57,027 72,480 Materials and supplies, at average cost 148,762 154,266 Accumulated deferred income taxes -- net 191,563 240,429 Regulatory balancing accounts -- net 100,935 -- Prepayments and other current assets 160,379 113,654 ----------- ----------- Total current assets 2,565,879 2,571,921 ----------- ----------- Unamortized debt issuance and reacquisition expense 353,060 346,834 Rate phase-in plan 16,220 50,703 Income tax-related deferred charges 1,581,243 1,741,091 Other deferred charges 1,089,488 1,029,203 ----------- ----------- Total deferred charges 3,040,011 3,167,831 ----------- ----------- Total assets $24,409,817 $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
September 30, December 31, 1997 1996 ------------- ----------- (Unaudited) CAPITALIZATION AND LIABILITIES Common shareholders' equity: Common stock (386,952,629 and 424,524,178 shares outstanding at respective dates) $ 2,328,294 $ 2,547,403 Cumulative translation adjustments -- net 27,209 63,898 Unrealized gain in equity investments -- net 56,012 33,382 Retained earnings 3,351,507 3,752,549 ----------- ----------- 5,763,022 6,397,232 Preferred securities of subsidiaries: Not subject to mandatory redemption 183,755 283,755 Subject to mandatory redemption 425,000 425,000 Long-term debt 7,049,436 7,474,679 ----------- ----------- Total capitalization 13,421,213 14,580,666 ----------- ----------- Other long-term liabilities 504,734 423,925 ----------- ----------- Current portion of long-term debt 347,882 592,143 Short-term debt 1,452,964 397,098 Accounts payable 503,451 437,657 Accrued taxes 827,422 530,365 Accrued interest 113,325 131,079 Dividends payable 101,136 108,563 Regulatory balancing accounts -- net -- 181,488 Deferred unbilled revenue and other current liabilities 1,207,811 1,059,240 ----------- ----------- Total current liabilities 4,553,991 3,437,633 ----------- ----------- Accumulated deferred income taxes -- net 4,110,945 4,283,219 Accumulated deferred investment tax credits 356,173 372,377 Customer advances and other deferred credits 1,455,346 753,755 ----------- ----------- Total deferred credits 5,922,464 5,409,351 ----------- ----------- Minority interest 7,415 707,039 ----------- ----------- Commitments and contingencies (Notes 1 and 2) Total capitalization and liabilities $24,409,817 $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
9 Months Ended September 30, ----------------------------- 1997 1996 --------- ----------- (Unaudited) Cash flows from operating activities: Net income $ 560,624 $ 599,638 Adjustments for non-cash items: Depreciation and decommissioning 1,024,799 865,938 Amortization 60,582 81,748 Rate phase-in plan 34,483 63,802 Deferred income taxes and investment tax credits 4,499 (103,136) Equity in income from partnerships and unconsolidated subsidiaries (164,170) (131,293) Other long-term liabilities 80,809 3,574 Other -- net (83,113) 5,470 Changes in working capital components: Receivables (283,344) (158,844) Regulatory balancing accounts (282,423) (131,814) Fuel inventory, materials and supplies 20,957 35,515 Prepayments and other current liabilities (45,063) (24,435) Accrued interest and taxes 277,924 449,377 Accounts payable and other current liabilities 218,830 211,113 Distributions from partnerships and unconsolidated subsidiaries 126,411 108,025 ---------- --------- Net cash provided by operating activities 1,551,805 1,874,678 ---------- --------- Cash flows from financing activities: Long-term debt issued 1,474,873 1,285,274 Long-term debt repayments (2,011,200) (1,093,835) Preferred securities redemptions (100,000) -- Common stock repurchased (884,686) (166,287) Nuclear fuel financing -- net (12,628) 20,510 Short-term debt financing -- net 1,046,208 (161,966) Dividends paid (310,354) (331,709) Other -- net 4,708 745 ---------- --------- Net cash used by financing activities (793,079) (447,268) ---------- --------- Cash flows from investing activities: Additions to property and plant (514,396) (607,253) Funding of nuclear decommissioning trusts (109,202) (110,241) Investments in partnerships and unconsolidated subsidiaries (219,819) (209,808) Unrealized gain in equity investments -- net 22,630 11,246 Other -- net (249,513) 33,105 ---------- --------- Net cash used by investing activities (1,070,300) (882,951) ---------- --------- Net increase (decrease) in cash and equivalents (311,574) 544,459 Cash and equivalents, beginning of period 896,594 507,151 ---------- --------- Cash and equivalents, end of period $ 585,020 $1,051,610 ========== =========
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. As a result of industry restructuring legislation enacted by the State of California and a related change in the application of accounting principles for rate-regulated enterprises adopted recently by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF), during the third quarter of 1997 Southern California Edison Company (SCE) began accounting for its investment in generation facilities in accordance with generally accepted accounting principles applicable to enterprises in general. Although this change did not result in any adjustment of the carrying value of such investment, it is shown separately on Edison International's Balance Sheet under the caption "Generation utility plant, at original cost, not subject to cost-based rate regulation." The competitive market for electric generation in California is scheduled to begin January 1, 1998. 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 Edison International's basic earnings per share, which replaces primary earnings per share. Certain prior-period amounts were reclassified to conform to the September 30, 1997, financial statement presentation. Note 1. Regulatory Matters California Electric Utility Industry Restructuring Restructuring Legislation - In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopts the California Public Utilities Commission's (CPUC) 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 SCE 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 during the 1998-2001 transition period. page 6 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In addition, the legislation mandates the implementation of a non- bypassable competition transition charge (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. Rate Reduction Bonds - In May 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 March 31, 2002. At the same time, 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. On September 3, 1997, the CPUC approved SCE's request. Subject to prior approval of the Infrastructure Bank, it is anticipated that the rate reduction bonds will be issued in the fourth quarter of 1997. CPUC Restructuring Decision - The CPUC's 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 CTC. Rate-setting - 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 Federal Energy Regulatory Commission (FERC) directives) for the functional unbundling of its rates for electric service, beginning 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 into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning. The transmission component of this rate unbundling process is being addressed at the FERC through a March 1997 filing. (See PX and ISO discussion below.) Hearings on SCE's rate unbundling (also known as rate-setting) plan were concluded in April 1997. On August 1, 1997, the CPUC issued a decision which adopted the methodology for determining CTC residually (see CTC discussion below) and adopted SCE's revenue requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revenue requirement by reallocating $76 million of it annually to other functions such as generation and transmission. Under the decision, SCE will be able to recover most of the annual $76 million through market revenue, the CTC mechanism after petitioning the CPUC to modify its prior decisions, or another review process later in the transition period. PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the FERC regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities, the ISO, and the page 7 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS PX to file more specific information. The filing was made in March 1997, and included SCE's proposed transmission revenue requirement. On October 29, 1997, the FERC gave conditional, interim authorization for operation of the PX and ISO to begin on January 1, 1998. Prior to January 2, 1998, the chief executive officers of the PX, ISO and the three utilities must certify that all the conditions are in place to ensure reliable electric power operations. In addition, the FERC stated it would closely monitor the PX and ISO, require further studies and make modifications, where necessary. A comprehensive review will be performed by the FERC after three years of operation of the PX and ISO. 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 are backed by utility guarantees; SCE's share is 45%, or $113 million. 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 October 17, 1997, the three utilities jointly filed a petition to modify the CPUC decision that established the restructuring trust and authorized the $250 million loan guarantees. The petition requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new total would be $135 million. The petition also requested that a one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is $85 million; SCE's share is 45%, or $38 million. A CPUC decision on the petition is expected by year-end 1997. Direct Customer Access - In May 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 remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), 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. Revenue Cycle Services - A decision issued by the CPUC in May 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, direct access 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. However, not all electric generation service providers will necessarily offer each billing option. 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 page 8 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. PBR - In 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D), and power generation. With the CPUC's 1995 restructuring decision and the passage of restructuring legislation in 1996, the majority of power generation ratemaking (primarily fossil-fueled and nuclear) was assigned to other mechanisms. 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. In April 1997, a CPUC interim order determined that the proposed structure for the fossil-fueled plants' local reliability contracts should be determined by the ISO, and therefore would be under the FERC's jurisdiction. A FERC decision is expected by year- end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was no longer critical to the restructuring process and asked SCE to make a compliance filing to determine the revenue requirement necessary for hydroelectric generation operations. SCE has proposed that the difference between the CPUC-determined hydroelectric revenue requirement and the market revenue from hydroelectric generation would flow through the CTC mechanism. A final CPUC decision is expected by year-end 1997. In September 1996, the CPUC adopted a non-generation or 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. Divestiture - In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all twelve of its oil- and gas-fueled generation plants. 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 restructuring legislation enacted in September 1996. 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. On September 3, 1997, the CPUC approved SCE's proposal to auction the twelve plants. On September 5, 1997, SCE began the auction of five plants by accepting indications of interest from potential buyers. On October 3, 1997, SCE accepted indications of interest from potential buyers on the other seven plants. On October 22, 1997, the CPUC issued a Mitigated Negative Declaration for the divestiture of SCE's twelve generation plants, which finds there will page 9 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS be no significant environmental impact resulting from the sale of the plants. The CPUC is expected to certify the Declaration when it approves the divestiture of the plants. SCE plans to conclude both auctions and receive CPUC approval of the divestiture by year-end 1997. Any differences between the net book value and the market value of the oil- and gas-fueled generation plants is expected to be recovered through a non-bypassable CTC. CTC - 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, 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 prior 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 Nuclear Generating Station Units 2 and 3 and the Palo Verde Nuclear Generating Station units, and certain other costs. In February 1997, SCE filed 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. This issue has been separated into two phases: Phase 1 captures the rate-making issues and Phase 2 the quantification issues. Hearings on Phase 1 were held in December 1996 and a decision was issued in June 1997, which, among other things, required the establishment of a transition cost balancing account and annual transition cost proceedings, set a market rate forecast for 1998 transition costs, and required that generation-related regulatory assets be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997. On October 20, 1997, a proposed decision was issued by the administrative law judge. Among other things, the proposed decision would reduce SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil generation-related assets) beginning July 1997. The proposed decision, if adopted, and excluding the effects of other rate actions, will have a negative impact on 1997 earnings of approximately 3 cents per share. A final decision on Phase 2 is expected in the fourth quarter of 1997. Accounting for Generation-Related Assets - If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of return). page 10 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As previously reported, since November 1996, SCE and the other major California electric utilities have been engaged in discussions with the Securities and Exchange Commission staff regarding the proper application of regulatory accounting standards in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the EITF during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities. However, SCE will not be required to write off any of its generation- related assets, including regulatory assets of approximately $900 million at September 30, 1997. SCE will retain these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a non-bypassable CTC to distribution customers. These regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached by the EITF also permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism. If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets as a one-time, non-cash charge against earnings. If such a write-off were to be required, SCE believes that it should not affect the recovery of stranded costs provided for in the legislation and restructuring plan. 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 opportunity to recover stranded costs associated with existing wholesale customers, retail-turned-wholesale customers and retail wheeling when the page 11 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retail- turned-wholesale customers, such as a new municipal electric system or a municipal annexation. However, the FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has discretion to defer to a state stranded-cost-calculation method. In January 1997, the FERC accepted the open access transmission tariff SCE filed in compliance with the April 1996 decision. The rates included in the tariff are being collected subject to refund. In May 1997, SCE filed a revised open access tariff to reflect the few revisions set forth in the March 1997 order. 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 filed several rounds of testimony on this issue. Hearings concluded in February 1997. On July 11, 1997, SCE and the ORA executed an agreement that settles all pending and future issues related to these contracts. The settlement agreement, which was filed on July 16, 1997, is subject to CPUC approval and has been fully reflected in the financial statements. 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. The subsidiary funded all of the required equity during construction and will be required to fund all remaining costs of the project facility until the close of non-recourse financing. The estimated total cost is $492 million, of which $457 million has been spent through September 30, 1997. In December 1995, a $254 million tax-exempt bond financing for the project was obtained through the New York City Industrial Development Agency (NYCIDA). EME has guaranteed the obligations of the project pursuant to the financing and indemnified NYCIDA for environmental liability up to $40 million. page 12 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In February 1997, the contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY) 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 arising out of 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. 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. In connection with the issuance of the San Onofre Units 2 and 3 operating permits, SCE reached an agreement with the California Coastal Commission in 1991 to restore certain marine mitigation sites. The restorations include two sites: designated wetlands and the construction of an artificial kelp reef off the California coast. After SCE requested certain modifications to the agreement, the Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediation required at these two sites. SCE elected to pay for the costs of marine mitigation in lieu of placing the funds into a trust. Rate recovery of these costs is occurring through the San Onofre incentive pricing plan. Edison International's recorded estimated minimum liability to remediate its 53 identified sites (52 at SCE and 1 at EME) is $185 million, which includes $75 million for the two sites discussed above. 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 $246 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. page 13 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The CPUC allows SCE to recover environmental-cleanup costs at 42 of its sites, representing $97 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 $159 million for its estimated minimum environmental- cleanup costs expected to be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan. 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 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 page 14 EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 $32 million per year. Insurance premiums are charged to operating expense. page 15 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 Earnings Edison International's earnings per share for the three and nine months ended September 30, 1997, were 70 cents and $1.38, respectively, compared with 63 cents and $1.36 for the same periods in 1996. Southern California Edison Company's (SCE) earnings were 57 cents and $1.13 for the quarter and year-to-date periods ended September 30, 1997, compared to 56 cents and $1.15 for the year-earlier periods. SCE made one-time adjustments (after-tax) for workforce management costs of 7 cents (charge) in second quarter 1996 and 4 cents (benefit) in third quarter 1996. Excluding these special items, Edison International's earnings for the three and nine months ended September 30, 1997, increased 11 cents and decreased 1 cent, respectively, compared to the same periods in 1996. The quarterly increase in earnings per share reflects an increase in electricity sales, higher earnings at the nonutility subsidiaries, the impact of Edison Mission Energy Company's (EME) lower effective tax rate, and the effects of the ongoing share repurchase program. The year-to-date decrease is primarily due to the refueling outages at SCE's San Onofre Nuclear Generating Station (see discussion in Regulatory Matters) and the new rate-making treatment for the Palo Verde Nuclear Generating Station. These decreases were partially offset by income from Edison Capital's new cross-border leases, EME's effective tax rate change, as well as the ongoing share repurchase program. Operating Revenue Electric utility revenue increased slightly for the three and nine months ended September 30, 1997, compared with the same periods in 1996. The quarterly increase is primarily due to an increase in non-residential retail rates, partially offset by a decrease in resale sales volume. The year-to-date increase is due to a 3% increase in sales volume from commercial and agricultural customers (due to an improving Southern California economy), as well as a slight increase in resale rates. Over 98% of operating revenue is from retail sales. Retail rates are regulated by the California Public Utilities Commission (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 for, among other things, at least a 10% rate page 16 reduction (financed through the issuance of rate reduction bonds) for residential and small commercial customers beginning in 1998 (see discussion in Competitive Environment). Revenue from diversified operations increased 37% and 48%, respectively, for the three and nine months ended September 30, 1997, primarily due to the start-up of EME's Loy Yang B Unit 2 and Kwinana projects. The Loy Yang B Unit 2 and Kwinana projects began commercial operations during the fourth quarter of 1996. In addition, revenue from diversified operations increased due to additional revenue from Edison Capital's May 1997 $360 million investment in cross-border leases in the Netherlands and in South Australia. Operating Expenses Fuel expense increased 86% and 55% for the three and nine months ended September 30, 1997, respectively. The increases are primarily due to a $174 million gas contract termination payment during the third quarter, combined with higher gas prices and the extended refueling outages at San Onofre. San Onofre Unit 2 was shut down during the entire first quarter of 1997, Unit 3 was shut down 80 days of the second quarter, and both units had a combined outage of 30 days during the third quarter of 1997, resulting in an overall increase in gas-powered generation for both periods presented. There were no comparable outages for the same periods in 1996. Fuel expense also increased at EME due to the start-up of Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996 and higher fuel costs at the First Hydro project due to increased generation and higher prices. Purchased-power expense decreased 4% during the quarter, as cost increases in spot market purchases were more than offset by decreases in federally mandated contract payments. For the nine months ended September 30, 1997, purchased-power expense increased 5% due to increased power purchases in the open market and increases in power purchased under federally-mandated contracts. SCE is required under federal law to purchase all power delivered by certain nonutility generators (up to a project's rated capacity) even though energy prices under these contracts are generally higher than other sources. For the twelve months ended September 30, 1997, SCE paid about $1.6 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 for both periods presented compared with the year-earlier periods. The quarterly decrease is primarily due to undercollections in the energy cost balancing account resulting from gas contract termination payments made in third quarter 1997, as well as a lesser amount of actual base-rate revenue from kilowatt-hour sales exceeding CPUC-authorized estimates. These quarterly undercollections were partially offset by a net overcollection resulting from the San Onofre units operating at a lower capacity in third quarter 1997 (30 days of refueling and inspection outages) compared to third quarter 1996 when the San Onofre units operated at a higher capacity than estimated. Another offset to the quarterly decrease is an overcollection due to the accelerated recovery of SCE's remaining investment at San Onofre. The year-to-date decrease is mainly due to an undercollection related to the gas contract termination payments made in 1997 and actual energy costs exceeding CPUC-authorized fuel and purchased-power cost estimates. This undercollection was partially offset by overcollections related to: actual base-rate revenue from kilowatt- hour sales exceeding CPUC-authorized estimates; the effects of the San Onofre refueling outages in 1997 and the acceleration of SCE's remaining investment at San Onofre. page 17 Other operating expenses increased 32% and 13%, respectively, for the three and nine months ended September 30, 1997, compared with the year- earlier periods. The quarterly increase is due to increased operating costs at San Onofre for inspections associated with the earlier Unit 2 and 3 outages, along with increased expenses associated with meter reading, customer records and interim direct access activities. Also contributing to the increases were higher administrative costs at Edison Enterprises and EME. The year-to-date increase is primarily due to the same quarterly reasons at EME and Edison Enterprises, as well as higher costs associated with the sale of property at Mission Land in 1997. For the year-to-date period, SCE's quarterly increase was more than offset by reductions in pension-related expenses associated with the voluntary retirement programs in 1996. Maintenance expense increased substantially in both periods presented compared with the year-earlier periods, due to increased maintenance costs for SCE's electric plant assets and scheduled refueling outages at the San Onofre units. Depreciation and decommissioning expense increased 13% and 18%, respectively, for the quarter and year-to-date ended September 30, 1997, due to increases in plant assets and the accelerated recovery of the Palo Verde Nuclear Generating Station units effective January 1997. The start- up of Loy Yang B Unit 2 and the Kwinana project, which began commercial operations in the fourth quarter of 1996, also contributed to increases at EME. Income taxes decreased 19% and 15%, respectively, for the three and nine months ended September 30, 1997, compared to the year-earlier periods, due to a decrease in pre-tax income. Property and other taxes decreased 31% for both the three and nine months ended September 30, 1997, compared to the same periods in 1996, due to SCE's reclassification of payroll taxes to operation and maintenance expense in 1997. Other Income and Deductions 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 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. Interest and dividend income increased 55% and 35%, respectively, for the three and nine months ended September 30, 1997, compared to the year- earlier periods, primarily due to EME's higher international cash balances. Minority interest decreased for both periods presented, primarily due to the May 1997 acquisition of the remaining 49% ownership interest in EME's Loy Yang B project. Other nonoperating income decreased for both periods presented, primarily due to additional accruals for regulatory matters and increased costs resulting from the effect of a rise in Edison International's stock price on SCE's stock option plan. Interest and Other Expenses Other interest expense increased 53% and 33% for the three and nine months ended September 30, 1997, respectively, compared to the same periods in 1996, due to higher levels of short-term debt at SCE used to retire first page 18 and refunding mortgage bonds during the third quarter of 1997. EME also had increased interest expense from the net effect of $450 million of securities issued by Edison Mission Energy Funding Corporation in December 1996 and the December 1996 repayment of a 200 million Australian dollar loan. Capitalized interest decreased for both periods presented, primarily due to the completion of construction of 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 $2.3 billion of its outstanding shares of common stock. Edison International has repurchased 68.4 million shares ($1.5 billion) between January 1995 and November 4, 1997, funded by dividends from its subsidiaries and its lines of credit. For the nine months ended September 30, 1997, Edison International's cash flow coverage of dividends decreased to 5.0 times from 5.7 times for the same period in 1996, as a result of the ongoing share repurchase program and the repayment of SCE's long-term debt. Edison International's dividend payout ratio for the twelve-month period ended September 30, 1997, was 61%. Cash Flows from Operating Activities Net cash provided by operating activities totaled $1.6 billion for the nine-month period ended September 30, 1997, compared with $1.9 billion in 1996. Cash from operations exceeded capital requirements for both periods presented. Cash Flows from Financing Activities At September 30, 1997, Edison International and its subsidiaries had $1.9 billion of borrowing capacity available under lines of credit totaling $3.6 billion. SCE had $1.8 billion of borrowing capacity under lines of credit, with $900 million available ($400 million for general purpose, short-term debt and $500 million for the long-term refinancing of its variable-rate pollution-control bonds). The parent company had a $1.0 billion line of credit with $315 million of borrowing capacity available. The nonutility companies had available lines of credit of $800 million, with $716 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 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 September 30, 1997, SCE could issue approximately $9.5 billion of additional first and refunding mortgage bonds and $5.2 billion of preferred stock at current interest and dividend rates. page 19 EME owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard project. The subsidiary 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 $457 million had been spent through September 30, 1997. In December 1995, a $254 million tax-exempt bond financing for the project was obtained through the New York City Industrial Development Agency (NYCIDA). EME has guaranteed the obligations of the project pursuant to the financing and indemnified NYCIDA for environmental liability up to $40 million. In February 1997, the contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY) 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 arising out of the turnkey agreement. EME believes that the outcome of this litigation will not materially affect its results of operations or financial position. In April 1997, EME completed financing and commenced construction of the Doga project, a 180 megawatt gas-powered power plant near Istanbul, Turkey. A wholly owned subsidiary of EME will own 80% of this project. In connection with the financing, EME has guaranteed $25 million in equity contributions and will continue making equity contributions until commercial operation begins, which is scheduled for late 1998. In May 1997, Edison Capital closed its largest infrastructure transaction in recent years by entering into a cross-border lease transaction in the Eems Power Station located in the Netherlands. This transaction is valued at $200 million. The Eems power station is a new, five unit (335 MW each) gas fired, combined cycle power plant. It is operated by EPON, the largest power generating company in the Netherlands. Edison Capital also acquired an interest in the electric power transmission system in South Australia. This cross-border lease transaction is valued at $160 million. EME has firm commitments of $320 million to make equity and other contributions, primarily for the Paiton project in Indonesia, the ISAB project in Italy, and the Doga project in Turkey. EME also has contingent obligations to make additional contributions of $479 million, primarily for a 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. 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 September 30, 1997, SCE had the capacity to pay $1.7 billion 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 page 20 trusts. Decommissioning costs are accrued and recovered in rates over the term of each nuclear generating facility's operating license through charges to depreciation expense. SCE estimates that it will spend approximately $12.7 billion to decommission its nuclear facilities primarily between 2013-2070. This estimate is based on SCE's current- dollar decommissioning costs ($2.0 billion), escalated using a 6.65% annual rate. These amounts 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 $501 million for the nine-month period ended September 30, 1997, compared with $240 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 Australia and fluctuations in foreign currency exchange rates can have a significant impact on EME's results of operations. EME has mitigated 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 included $9 million and $6 million, respectively, for the nine months ended September 30, 1997, and 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 electrical energy. 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 $27 million for the nine months ended September 30, 1997, compared to a decrease of $4 million in the corresponding period of the prior year, as a result of electricity rate swap agreements. Loy Yang B sells their electrical energy through a centralized electricity pool (Victorian Wholesale Electricity Market which will be integrated into the National Electricity Market), which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The Victorian Power Exchange, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate the exposure to price volatility of the electricity traded in the pool, Loy Yang B has entered into a number of financial hedges. From May 8, 1997, to December 31, 2000, approximately 53% to 64% of the plant output sold is hedged under vesting contracts with the remainder of the plant capacity hedged under the state hedge. Vesting contracts were put into place by the State, between each generator and each distributor, prior to the privatization of electric power distributors in order to provide more predictable pricing for those electricity customers that were unable to choose their electricity retailer. Vesting contracts set base strike prices at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the page 21 contract and the half-hourly pool clearing price for the element of power under contract. These contracts can be sold as one-way or two-way contracts which are structured similar to the electricity rate swap agreements described above. The state hedge is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997, and terminating October 31, 2016. The State guarantees the State Electricity Commission of Victoria's obligations under the state hedge. Loy Yang B's electric revenue was increased by $43 million for the nine-month period ended September 30, 1997, as a result of hedging contract arrangements. As EME continues to expand into foreign markets, fluctuations in foreign currency exchange rates can affect the amount of its equity contributions to, distributions from, and results of operations of 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 years are: 1997--$856 million; 1998--$1.0 billion; 1999--$807 million; 2000--$763 million; and 2001--$721 million. Long-term debt maturities and sinking fund requirements for the five twelve-month periods following September 30, 1997, are: 1998--$341 million; 1999--$587 million; 2000--$547 million; 2001--$544 million; and 2002--$212 million. Preferred stock redemption requirements for the five twelve-month periods following September 30, 1997, are: 1998 through 2001--zero and 2002--$105 million. REGULATORY MATTERS SCE's 1997 CPUC-authorized rates are unchanged from 1996 levels due to legislation enacted in September 1996 which requires that rates remain frozen at the June 10, 1996, level (system average of 10.1 cent per kilowatt- hour). See further 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, will have a negative impact on 1997 earnings of approximately 1 cent per share. On October 20, 1997, a proposed decision was issued by a CPUC administrative law judge in Phase 2 of the competition transition charge (CTC) proceeding. Among other things, the proposed decision would reduce SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil generation-related assets) beginning July 1997. The proposed decision, if adopted, and excluding the effects of other rate actions, will have a negative impact on 1997 earnings of approximately 3 cents per share. The CPUC has authorized revised rate-making plans for SCE's nuclear facilities, which call 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 an authorized rate of 9.49% in 1997 for other assets. In addition, the page 22 San Onofre plan authorizes a fixed rate of approximately 4 cent 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 the 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 disallowance's have been consolidated into one proceeding. SCE and the ORA filed several rounds of testimony on this issue. Hearings concluded in February 1997. On July 11, 1997, SCE and the ORA executed an agreement that settles all pending and future issues related to these contracts. The settlement agreement, which was filed on July 16, 1997, is subject to CPUC approval and has been fully reflected in the financial statements. 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 Restructuring Legislation - 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 SCE 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 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 page 23 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. Rate Reduction Bonds - In May 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 March 31, 2002. At the same time, 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. On September 3, 1997, the CPUC approved SCE's request. Subject to prior approval of the Infrastructure Bank, it is anticipated that the rate reduction bonds will be issued in the fourth quarter of 1997. CPUC Restructuring Decision - The CPUC's 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 CTC. Rate-setting - 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 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 into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning. The transmission component of this rate unbundling process is being addressed at the FERC through a March 1997 filing. (See PX and ISO discussion below.) Hearings on SCE's rate unbundling (also known as rate-setting) plan were concluded in April 1997. On August 1, 1997, the CPUC issued a decision which adopted the methodology for determining CTC residually (see CTC discussion below) and adopted SCE's revenue requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revenue requirement by reallocating $76 million of it annually to other functions such as generation and transmission. Under the decision, SCE will be able to recover most of the annual $76 million through market revenue, the CTC mechanism after petitioning the CPUC to modify its prior decisions, or another review process later in the transition period. PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the FERC regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities, the ISO, and the PX to file more specific information. The filing was made in March 1997, and included SCE's proposed transmission revenue requirement. On October 29, 1997, the FERC gave conditional, interim authorization for operation of the PX and ISO to begin on January 1, 1998. Prior to January 2, 1998, the chief executive officers of the PX, ISO and the three utilities must certify that all the conditions are in place to ensure reliable electric power operations. In addition, the FERC stated it would closely monitor the PX and ISO, require further studies and make modifications, where necessary. A comprehensive review will be performed page 24 by the FERC after three years of operation of the PX and ISO. 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 are backed by utility guarantees; SCE's share is 45%, or $113 million. 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 October 17, 1997, the three utilities jointly filed a petition to modify the CPUC decision that established the restructuring trust and authorized the $250 million loan guarantees. The petition requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new total would be $135 million. The petition also requested that a one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is $85 million; SCE's share is 45%, or $38 million. A CPUC decision on the petition is expected by year-end 1997. Direct Customer Access - In May 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 remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), 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. Revenue Cycle Services - A decision issued by the CPUC in May 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, direct access 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. However, not all electric generation service providers will necessarily offer each billing option. 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. PBR - In 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D) and power generation. With the CPUC's 1995 restructuring decision and the passage of restructuring page 25 legislation in 1996, the majority of power generation ratemaking (primarily fossil-fueled and nuclear) was assigned to other mechanisms. 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. In April 1997, a CPUC interim order determined that the proposed structure for the fossil-fueled plants' local reliability contracts should be determined by the ISO, and therefore would be under the FERC's jurisdiction. A FERC decision is expected by year- end 1997. In June 1997, the CPUC determined that a hydroelectric PBR was no longer critical to the restructuring process and asked SCE to make a compliance filing to determine the revenue requirement necessary for hydroelectric generation operations. SCE has proposed that the difference between the CPUC-determined hydroelectric revenue requirement and the market revenue from hydroelectric generation would flow through the CTC mechanism. A final CPUC decision is expected by year-end 1997. In September 1996, the CPUC adopted a non-generation or 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. Divestiture - In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all twelve of its oil- and gas-fueled generation plants. 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 restructuring legislation enacted in September 1996. 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. On September 3, 1997, the CPUC approved SCE's proposal to auction the twelve plants. On September 5, 1997, SCE began the auction of five plants by accepting indications of interest from potential buyers. On October 3, 1997, SCE accepted indications of interest from potential buyers on the other seven plants. On October 22, 1997, the CPUC issued a Mitigated Negative Declaration for the divestiture of SCE's twelve generation plants, which finds there will be no significant environmental impact resulting from the sale of the plants. The CPUC is expected to certify the Declaration when it approves the divestiture of the plants. SCE plans to conclude both auctions and receive CPUC approval of the divestiture by year-end 1997. Any differences between the net book value and the market value of the oil- and gas-fueled generation plants is expected to be recovered through a non-bypassable CTC. CTC - 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 page 26 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, 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 prior 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 Nuclear Generating Station Units 2 and 3 and the Palo Verde Nuclear Generating Station units, and certain other costs. In February 1997, SCE filed 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. This issue has been separated into two phases: Phase 1 captures the rate-making issues and Phase 2 the quantification issues. Hearings on Phase 1 were held in December 1996 and a decision was issued in June 1997, which, among other things, required the establishment of a transition cost balancing account and annual transition cost proceedings, set a market rate forecast for 1998 transition costs, and required that generation-related regulatory assets be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997. On October 20, 1997, a proposed decision was issued by the administrative law judge. Among other things, the proposed decision would reduce SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil generation-related assets) beginning July 1997. The proposed decision, if adopted, and excluding the effects of other rate actions, will have a negative impact on 1997 earnings of approximately 3 cent per share. A final decision on Phase 2 is expected in the fourth quarter of 1997. Accounting for Generation-Related Assets - If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of return). As previously reported, since November 1996, SCE and the other major California electric utilities have been engaged in discussions with the Securities and Exchange Commission staff regarding the proper application of regulatory accounting standards in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities. However, SCE will not be required to write off any of its generation- related assets, including regulatory assets of approximately $900 million at September 30, 1997. SCE will retain these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a non-bypassable CTC to distribution customers. These regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed-through to customers, page 27 purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached by the EITF also permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism. If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets as a one-time, non-cash charge against earnings. If such a write-off were to be required, SCE believes that it should not affect the recovery of stranded costs provided for in the legislation and restructuring plan. 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 opportunity to recover stranded costs associated with existing wholesale customers, retail-turned-wholesale customers and retail wheeling when the state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retail- turned-wholesale customers, such as a new municipal electric system or a municipal annexation. However, the FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has discretion to defer to a state stranded-cost-calculation method. In January 1997, the FERC accepted the open access transmission tariff SCE filed in compliance with the April 1996 decision. The rates included in the tariff are being collected subject to refund. In May 1997, SCE filed a revised open access 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 the Consolidated Financial Statements, Edison International records its environmental liabilities when site page 28 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. In connection with the issuance of the San Onofre Units 2 and 3 operating permits, SCE reached agreement with the California Coastal Commission in 1991 to restore certain marine mitigation sites. The restorations include two sites: designated wetlands and the construction of an artificial kelp reef off the California coast. After SCE requested certain modifications to the agreement, the Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediation required at these two sites. SCE elected to pay for the costs of marine mitigation in lieu of placing the funds into a trust. Rate recovery of these costs is occurring through the San Onofre incentive pricing plan. Edison International's recorded estimated minimum liability to remediate its 53 identified sites is $185 million, which includes $75 million for the two sites discussed above. One of SCE's sites, a former pole-treating facility, is considered a federal Superfund site and represents 43% 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 $246 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 42 of its sites, representing $97 million of Edison International's recorded liability, through an incentive mechanism. 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 $159 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan. 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. page 29 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 has been the subject of scientific research. After many years of research, scientists have not found that exposure to EMF causes disease in humans. Research on this topic is continuing. 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 supports the purchase of spare steam generators that could be used, if needed, in any of the Palo Verde units. SCE estimates its share of the steam generator replacement costs to be between $16 million and $30 million, plus replacement power costs. 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 steam generator tube degradation. However, during the Unit 2 scheduled refueling and inspection outage, which was completed in Spring 1997, an increased rate of tube 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. During Unit 3's refueling outage, which was completed in July 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. As a result, a mid- cycle inspection outage is planned for 1998. However, during Unit 2's Spring 1997 inspection outage, similar tube supports showed no signs of such erosion. page 30 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 Edison International's basic earnings per share, which replaces primary 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 31 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 Qualifying Facilities (QF) Litigation On May 20, 1993, four geothermal QFs filed a lawsuit against Southern California Edison Company (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 California Public Utilities Commission (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, SCE filed its application with the CPUC for approval of the settlement as it pertains to the period after 1995. On December 20, 1996, the CPUC's Office of Ratepayer Advocates (ORA) filed a protest to the application. In its protest, the ORA requests that the page 32 CPUC not grant the application or, in the alternative, that the CPUC conduct hearings on the application. On January 17, 1997, SCE 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 start on April 23, 1997. This hearing date was subsequently vacated by the assigned administrative law judge due to ongoing discussions to resolve issues raised by ORA's protest. As a result of those discussions, SCE and the ORA entered into a stipulation and agreement (Stipulation) effective July 11, 1997. In the Stipulation, the ORA agrees to withdraw its protest and support SCE's application in return for SCE's agreement that the cost recovery issues presented in the application may be transferred for a decision in SCE's 1992 Energy Cost Adjustment Clause (ECAC) proceeding, where related issues are currently pending. The Stipulation further provides for SCE and the ORA to file a joint motion for approval of the Stipulation. The motion was filed on September 25, 1997. In light of the Stipulation, plaintiffs and SCE have entered into two amendments to the May 1, 1996, settlement agreement. The first amendment provides for the post-1995 portion of the settlement to become effective through 1997 upon CPUC approval consistent with the Stipulation. The second amendment resulted in plaintiffs dismissing the lawsuit without prejudice pending final CPUC resolution of the issues raised by SCE's application. On October 15, 1997, the assigned administrative law judge issued a draft decision on SCE's application and the motion for approval of the Stipulation. The draft decision would approve the application subject to the terms of the Stipulation. As of this date, the CPUC has not yet acted on the draft decision. Wind Generators' Litigation 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 of the consolidated cases, beginning with the lead case, commenced on March 10, 1997. The consolidated cases are to be tried one after another in bifurcated fashion with the liability phase of each and all of the cases page 33 to be tried before commencement of the damages phase, if applicable. Testimony and arguments in the liability phase of the lead case concluded on May 20, 1997. On July 7, 1997, the court issued a tentative decision which effectively would resolve all liability issues in the lead case in SCE's favor. A proposed Statement of Decision consistent with the conclusions in the tentative decision has been submitted by SCE and argument on the same took place at a hearing on October 31, 1997. The hearing was not concluded at that time and further argument has therefore been scheduled for November 19, 1997. In addition, a status conference has been scheduled for December 17, 1997, at which time the court will address scheduling of trial dates in the remaining cases and a date for commencement of the damages phase of the lead case. Geothermal Generators' Litigation On June 9, 1997, SCE filed a complaint in Los Angeles Superior Court against another independent power producer of geothermal generation and five of its affiliated entities (collectively the "Defendants"). SCE alleges that in order to avoid power production plant shutdowns caused by excessive noncondensable gas in the geothermal field brine, the Defendants routinely vented highly toxic hydrogen sulfide gas from unmonitored release points beginning in 1990 and continuing through at least 1994, in violation of applicable federal, state and local environmental law. According to SCE, these violations constituted material breaches by the Defendants of their obligations under their contracts and applicable law. The complaint seeks termination of the contracts and damages for excess power purchase payments made to the Defendants. The Defendants' motion to transfer venue to Inyo County Superior Court was granted on August 31, 1997. The Defendants have responded to SCE's allegations by filing both a demurrer and a motion to strike. These matters are currently set for hearing on November 20, 1997, in Inyo County Superior Court. In addition, the Defendants have filed a motion for summary judgment on the grounds that SCE's claims are time-barred or that such claims were released in connection with the settlement of the prior litigation between some of the Defendants and SCE's affiliates, Mission Power Engineering Co., Edison Mission Energy and The Mission Group. The Defendants have also filed a cross-complaint which names SCE, Mission Power Engineering Co., Edison Mission Energy and The Mission Group. In response to SCE's demurrer, the Defendants withdrew their cross-complaint and filed a first amended cross-complaint. The first amended cross- complaint asserts twelve causes of action for alleged violation of certain orders of the CPUC, declaratory relief with respect to the contracts, breach of the implied covenant of good faith and fair dealing, inducing breach of employment agreements, abuse of process, breach of settlement agreements, disparagement and slander per se, and unfair business practices under section 17200 of the California Business and Professions Code. The first amended cross-complaint seeks damages in an unspecified amount as well as exemplary damages and injunctive relief. SCE has responded to the first amended cross-complaint by filing a demurrer, which is set for hearing on November 20, 1997, in Inyo County Superior Court. In addition to asserting the claims in the first amended cross-complaint, three of the Defendants (collectively the "Related Plaintiffs") have filed a separate lawsuit in Inyo County Superior Court. In a first amended complaint in the separate lawsuit, the Related Plaintiffs allege causes of action for breach of contract, breach of the implied covenant of good faith and fair dealing, declaratory relief, violation of California Public Utilities Code sections 702, 453 and 2106, unfair competition and false advertising. In addition, the Related Plaintiffs claim that SCE anticipatorily breached the contracts by asserting that all of the Related Plaintiffs' facilities are subject to a single "first period." The Related Plaintiffs seek recovery of $400,000,000 in alleged compensatory damages as well as exemplary damages and unspecified injunctive relief. SCE has demurred to the amended complaint and has also moved to strike page 34 or, in the alternative, to consolidate the Related Plaintiffs' claims with the Defendants' claims in the first lawsuit on the ground that the former claims should have been asserted as part of the amended cross-complaint in the original action. The hearing on SCE's demurrer and motion to strike or to consolidate is also currently set for November 20, 1997. No trial date in either of the two cases has been set. Electric and Magnetic Fields (EMF) Litigation 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 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. Although stayed for a time pending appellate review of sanctions imposed against plaintiffs' attorneys by the trial court, the case has been remanded back to the trial court following the Court of Appeal's decision modifying the sanctions order. To date, no further proceedings have been scheduled. 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 San Diego Gas & Electric (SDG&E), as well as Combustion Engineering, the manufacturer of page 35 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' 15 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. Oral argument on the appeal has been set for December 4, 1997. All trial court proceedings have been stayed pending the ruling of the Court of Appeals. The impact on 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 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. Oral argument on the appeal has been set for December 4, 1997. 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 on 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, page 36 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 in this case is scheduled to begin on January 27, 1998. 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. 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. On June 30, 1997, SCE filed an answer to the complaint denying the substantive allegations and raising appropriate defenses. Rubaii False Claims Act Litigation In September 1997, SCE became aware of a complaint filed in the Southern District of the U.S. District Court of California by a San Onofre employee, acting at his own initiative on behalf of the United States under the False Claims Act, against SCE and SDG&E. The complaint alleges that SCE and SDG&E have submitted fraudulent claims to the United States government, the State of California and their customers resulting in $491 million in overpayments ($383 million of which is attributed to SCE). The employee alleges that SCE and SDG&E provided the CPUC with data which inflated projected costs at San Onofre while minimizing projected revenues, resulting in the CPUC setting inflated rates. The amount sought in this complaint is subject to trebling, plus civil penalties of $10,000 per false claim submitted for payment (for an unspecified number of claims). SCE filed a motion to dismiss this lawsuit on November 7, 1997. page 37 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 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 November 13, 1997 EX-23 2 EXHIBIT 23 PAGE 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 September 30, 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 November 12, 1997 EX-27 3 EXHIBIT 27
UT Edison International Financial Data Schedule - Exhibit 27 1,000 9-MOS DEC-31-1997 SEP-30-1997 PER-BOOK $11,195,412 7,608,515 2,565,879 3,040,011 0 24,409,817 2,328,294 83,221 3,351,507 5,763,022 425,000 183,755 2,810,221 0 4,192,343 869,509 347,882 0 46,872 19,879 9,751,334 24,409,817 6,905,691 395,732 5,353,773 5,749,505 1,156,186 (41,951) 1,114,235 521,018 593,217 32,593 560,624 300,962 259,503 1,551,805 $1.38 $1.37
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