UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) /X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended March 31, 1998 --------------------------------------------- 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 800) 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 (for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Class Outstanding at May 11, 1998 - ---------------------------------------- -------------------------------------- Common Stock, no par value 362,227,097
EDISON INTERNATIONAL INDEX Page No ---- Part I. Financial Information: Item 1. Consolidated Financial Statements: Consolidated Statements of Income -- Three Months Ended March 31, 1998, and 1997 1 Consolidated Statements of Comprehensive Income -- Three Months Ended March 31, 1998, and 1997 1 Consolidated Balance Sheets -- March 31, 1998, and December 31, 1997 2 Consolidated Statements of Cash Flows -- Three Months Ended March 31, 1998, and 1997 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition 12 Part II. Other Information: Item 1. Legal Proceedings 26 Item 4. Submission of Matters to a Vote of Security Holders 32 Item 6. Exhibits and Reports on Form 8-K 32
EDISON INTERNATIONAL PART I -- FINANCIAL INFORMATION Item 1. Consolidated Financial Statements CONSOLIDATED STATEMENTS OF INCOME In thousands, except per-share amounts <TABLE> <CAPTION> 3 Months Ended March 31, - -------------------------------------------------------------------------------------------------------------------- 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) <S> <C> <C> Electric utility revenue $1,622,689 $1,695,401 Diversified operations 286,871 305,324 - ------------------------------------------------------------------------------------------------------------------- Total operating revenue 1,909,560 2,000,725 - ------------------------------------------------------------------------------------------------------------------- Fuel 167,321 200,233 Purchased power 576,506 628,674 Provisions for regulatory adjustment clauses-- net (238,017) (88,173) Other operating expenses 387,179 330,270 Maintenance 101,969 96,155 Depreciation and decommissioning 411,320 340,121 Income taxes 136,719 96,076 Property and other taxes 40,762 40,309 - ------------------------------------------------------------------------------------------------------------------- Total operating expenses 1,583,759 1,643,665 - ------------------------------------------------------------------------------------------------------------------- Operating income 325,801 357,060 - ------------------------------------------------------------------------------------------------------------------- Provision for rate phase-in plan -- (11,309) Allowance for equity funds used during construction 2,781 2,003 Interest and dividend income 30,716 15,842 Minority interest (1,508) (27,965) Other nonoperating income (deductions)-- net (9,199) (2,862) - ------------------------------------------------------------------------------------------------------------------- Total other income (deductions)-- net 22,790 (24,291) - ------------------------------------------------------------------------------------------------------------------- Income before interest and other expenses 348,591 332,769 - ------------------------------------------------------------------------------------------------------------------- Interest on long-term debt 179,109 152,425 Other interest expense 21,213 31,259 Allowance for borrowed funds used during construction (1,892) (2,412) Capitalized interest (3,905) (5,177) Dividends on subsidiary preferred securities 10,056 11,862 - ------------------------------------------------------------------------------------------------------------------- Total interest and other expenses-- net 204,581 187,957 - ------------------------------------------------------------------------------------------------------------------- Net income $ 144,010 $ 144,812 - ------------------------------------------------------------------------------------------------------------------- Weighted-average shares of common stock outstanding 370,279 419,665 Basic earnings per share $.39 $.35 Diluted earnings per share $.38 $.34 Dividends declared per common share $.26 $.25 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME In thousands 3 Months Ended March 31, - ------------------------------------------------------------------------ ------------------------------------------- 1998 1997 - ------------------------------------------------------------------------ ------------------------------------------- Net Income $ 144,010 $ 144,812 Cumulative translation adjustments-- net 8,318 (26,901) Unrealized gains on securities-- net 14,014 7,243 - ------------------------------------------------------------------------------------------------------------------- Comprehensive income $ 166,342 $ 125,154 - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. <PAGE 1> EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands <TABLE> <CAPTION> March 31, December 31, 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) ASSETS Transmission and distribution: Utility plant, at original cost, subject to <S> <C> <C> cost-based rate regulation $11,333,083 $11,213,352 Accumulated provision for depreciation (5,690,973) (5,573,742) Construction work in progress 482,386 492,614 - ------------------------------------------------------------------------------------------------------------------- 6,124,496 6,132,224 - ------------------------------------------------------------------------------------------------------------------- Generation: Utility plant, at original cost, not subject to cost-based rate regulation 9,367,923 9,522,127 Accumulated provision for depreciation and decommissioning (5,241,980) (4,970,137) Construction work in progress 101,759 100,283 Nuclear fuel, at amortized cost 145,607 154,757 - ------------------------------------------------------------------------------------------------------------------- 4,373,309 4,807,030 - ------------------------------------------------------------------------------------------------------------------- Total utility plant 10,497,805 10,939,254 - ------------------------------------------------------------------------------------------------------------------- Nonutility property -- less accumulated provision for depreciation of $259,376 and $238,386 at respective dates 3,224,973 3,178,375 Nuclear decommissioning trusts 2,001,906 1,831,460 Investments in partnerships and unconsolidated subsidiaries 1,367,950 1,340,853 Investments in leveraged leases 1,332,627 959,646 Other investments 322,710 260,427 - ------------------------------------------------------------------------------------------------------------------- Total other property and investments 8,250,166 7,570,761 - ------------------------------------------------------------------------------------------------------------------- Cash and equivalents 1,360,569 1,906,505 Receivables, including unbilled revenue, less allowances of $24,145 and $26,722 for uncollectible accounts at respective dates 898,689 1,077,671 Fuel inventory 53,464 58,059 Materials and supplies, at average cost 131,278 132,980 Accumulated deferred income taxes-- net -- 123,146 Regulatory balancing accounts-- net 495,078 193,311 Prepayments and other current assets 77,728 105,811 - ------------------------------------------------------------------------------------------------------------------- Total current assets 3,016,806 3,597,483 - ------------------------------------------------------------------------------------------------------------------- Unamortized debt issuance and reacquisition expense 369,163 359,304 Rate phase-in plan -- 3,777 Income tax-related deferred charges 1,549,631 1,543,380 Other deferred charges 1,210,769 1,087,108 - ------------------------------------------------------------------------------------------------------------------- Total deferred charges 3,129,563 2,993,569 - ------------------------------------------------------------------------------------------------------------------- Total assets $24,894,340 $25,101,067 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. <PAGE 2> EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands, except share amounts <TABLE> <CAPTION> March 31, December 31, 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) CAPITALIZATION AND LIABILITIES Common shareholders' equity: Common stock (366,074,497 and 375,764,429 <S> <C> <C> shares outstanding at respective dates) $ 2,202,669 $ 2,260,974 Accumulated other comprehensive income: Cumulative translation adjustments-- net 38,774 30,456 Unrealized gain in equity securities-- net 74,044 60,030 Retained earnings 3,017,164 3,175,883 - ------------------------------------------------------------------------------------------------------------------- 5,332,651 5,527,343 - ------------------------------------------------------------------------------------------------------------------- Preferred securities of subsidiaries: Not subject to mandatory redemption 183,755 183,755 Subject to mandatory redemption 425,000 425,000 Long-term debt 8,868,359 8,870,781 - ------------------------------------------------------------------------------------------------------------------- Total capitalization 14,809,765 15,006,879 - ------------------------------------------------------------------------------------------------------------------- Other long-term liabilities 494,370 479,637 - ------------------------------------------------------------------------------------------------------------------- Current portion of long-term debt 745,955 868,026 Short-term debt 395,005 329,550 Accounts payable 429,570 441,049 Accrued taxes 542,397 576,841 Accrued interest 120,939 131,885 Dividends payable 99,999 95,146 Accumulated deferred income taxes-- net 94,577 -- Deferred unbilled revenue and other current liabilities 1,168,265 1,285,679 - ------------------------------------------------------------------------------------------------------------------- Total current liabilities 3,596,707 3,728,176 - ------------------------------------------------------------------------------------------------------------------- Accumulated deferred income taxes-- net 4,105,301 4,085,296 Accumulated deferred investment tax credits 343,771 350,685 Customer advances and other deferred credits 1,532,397 1,441,303 - ------------------------------------------------------------------------------------------------------------------- Total deferred credits 5,981,469 5,877,284 - ------------------------------------------------------------------------------------------------------------------- Minority interest 12,029 9,091 - ------------------------------------------------------------------------------------------------------------------- Commitments and contingencies (Notes 1 and 2) Total capitalization and liabilities $24,894,340 $25,101,067 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. <PAGE 3> EDISON INTERNATIONAL CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands <TABLE> <CAPTION> 3 Months Ended March 31, - ------------------------------------------------------------------------------------------------------------------- 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) Cash flows from operating activities: <S> <C> <C> Net income $ 144,010 $ 144,812 Adjustments for non-cash items: Depreciation and decommissioning 411,320 340,121 Amortization 28,066 13,580 Rate phase-in plan 3,777 10,690 Deferred income taxes and investment tax credits 218,045 54,117 Equity in income from partnerships and unconsolidated subsidiaries (23,086) ( 40,113) Other long-term liabilities 14,733 28,123 Regulatory asset related to the sale of utility plant (98,041) -- Loss on sale of utility plant 62,633 -- Other-- net (71,705) (26,175) Changes in working capital: Receivables 175,876 103,643 Regulatory balancing accounts (301,767) ( 74,983) Fuel inventory, materials and supplies 6,297 14,662 Prepayments and other current assets 39,579 46,897 Accrued interest and taxes (45,390) 53,882 Accounts payable and other current liabilities (108,661) ( 89,060) Distributions from partnerships and unconsolidated subsidiaries 37,539 20,672 - ------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 493,225 600,868 - ------------------------------------------------------------------------------------------------------------------- Cash flows from financing activities: Long-term debt issued 521,032 5,677 Long-term debt repaid (669,812) (271,567) Common stock issued -- 3,943 Common stock repurchased (263,315) (214,492) Rate reduction notes issued (4,757) -- Rate reduction notes repaid (12,354) -- Nuclear fuel financing-- net (8,623) 6,031 Short-term debt financing-- net 65,455 31,415 Dividends paid (94,326) (107,018) Other-- net 367 724 - ------------------------------------------------------------------------------------------------------------------- Net cash used by financing activities (466,333) (545,287) - ------------------------------------------------------------------------------------------------------------------- Cash flows from investing activities: Additions to property and plant (198,957) (158,008) Proceeds from sale of plant 33,901 -- Funding of nuclear decommissioning trusts (39,683) (27,889) Investments in partnerships and unconsolidated subsidiaries (44,368) (14,234) Unrealized gain on securities-- net 14,014 7,243 Other-- net (337,735) (25,895) - ------------------------------------------------------------------------------------------------------------------- Net cash used by investing activities (572,828) (218,783) - ------------------------------------------------------------------------------------------------------------------- Net decrease in cash and equivalents (545,936) (163,202) Cash and equivalents, beginning of period 1,906,505 896,594 - ------------------------------------------------------------------------------------------------------------------- Cash and equivalents, end of period $1,360,569 $ 733,392 - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. <PAGE 4> 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 1997 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 1997 Annual Report. Certain prior-period amounts were reclassified to conform to the March 31, 1998, financial statement presentation. Note 1. Regulatory Matters California Electric Utility Industry Restructuring Restructuring Decision -- The California Public Utilities Commission's (CPUC) December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which provides competition and customer choice starting April 1, 1998. Key elements of the CPUC's restructuring decision included: creation of the power exchange (PX) and independent system operator (ISO); availability of customer choice for electricity supply and certain billing and metering services; 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 the competition transition charge (CTC). Restructuring Legislation -- In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted 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 included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow Southern California Edison Company (SCE) to reduce rates by at least 10% to these customers, beginning January 1, 1998. The legislation included 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 mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation contained 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 Notes -- In December 1997, after receiving approval from both the CPUC and the California Infrastructure and Economic Development Bank, a limited liability company created by SCE issued approximately $2.5 billion of rate reduction notes. Residential and small commercial customers, whose 10% rate reduction began in January 1998, will repay the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. <PAGE 5> EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Rate-setting -- In December 1996, SCE filed a comprehensive plan addressing 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 beginning January 1, 1998. The transmission component of this rate unbundling process was addressed at the Federal Energy Regulatory Commission (FERC) through a March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the date the ISO begins operation. In August 1997, the CPUC issued a decision which adopted a 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 reallocated amount through market revenue, other rate-making mechanisms or another review process later in its divestiture proceeding. 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. In October 1997, the FERC gave conditional, interim authorization for operation of the PX and ISO to begin on January 1, 1998. 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. The start-up of the PX and ISO was delayed by three months due to insufficient testing of systems. On March 31, 1998, both the PX and ISO began bidding and scheduling for April 1, 1998, when the ISO took over operational control of the power system. In 1996, the CPUC issued an interim order establishing a restructuring trust which would obtain loans up to $250 million (increased to $300 million in November 1997) backed by utility guarantees. The loans were used to build hardware and software systems for the ISO and PX. SCE's share of the loan guarantees is 45% or $135 million. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In December 1997, the CPUC approved the utilities' request that the 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 $101 million, plus interest and fees over the four-year transition period; SCE's share is 45%, or $45 million. 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. Effective April 1, 1998, after a three month delay in the implementation of direct access, customers are now able to choose to remain utility customers with either bundled electric service or an hourly PX pricing option 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. <PAGE 6> EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Revenue Cycle Services -- A decision issued by the CPUC in May 1997, introduced customer choice to metering, billing and related services (referred to as revenue cycle services) that have been provided by California's investor-owned utilities. Under this revenue cycle services unbundling decision, beginning in April 1998 (delayed from January 1998), energy service providers (ESPs) can provide their customers with one consolidated bill for their services and the utility's services, request the utility to provide a consolidated bill to the customer or elect to have both the ESP and the utility bill the customer for their respective charges. In addition, beginning in April 1998, customers with maximum demand above 20 kW (primarily industrial and medium 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 customers who elect to have ESPs 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. PBR -- In September 1996, the CPUC adopted a non-generation or transmission and distribution (T&D) PBR mechanism for SCE which began on January 1, 1997. In accordance with this CPUC decision, beginning in April 1998 the transmission portion was 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. The CPUC has announced its intention to consider unbundling SCE's cost of capital by major utility function. On May 8, 1998, SCE filed an application on this issue. A CPUC decision is expected by year-end. In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE's hydroelectric plants. The mechanism sets the hydroelectric revenue requirement in 1998 and establishes a formula for extending it through the duration of the electric industry restructuring transition period, or until market valuation of the hydroelectric facilities, whichever occurs first. The mechanism provides that power sales revenue from hydroelectric facilities in excess of the hydroelectric revenue requirement be credited against the costs to transition to a competitive market (see CTC discussion below). Divestiture -- In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its gas- and oil-fueled generation plants. Under this 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. In September 1997, the CPUC approved SCE's proposal to auction the 12 plants. In early December 1997, SCE filed a compliance filing with the CPUC stating that it had sold 10 plants; the CPUC approved the sale of the 10 plants in mid-December 1997. In the first quarter of 1998, SCE announced the pending sales of the 11th and 12th plants. SCE has received CPUC approval of the sale of the 11th plant and approval of the sale of the 12th plant is expected by the end of second quarter 1998. The total sales price of the 12 plants is $1.2 billion, over $500 million more than the combined book value. Net proceeds of the sales will be used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. The transfer of ownership of the 12 plants is expected to be completed by the end of second quarter 1998. <PAGE 7> EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CTC -- The costs to transition to a competitive market are being recovered through a non-bypassable CTC. This charge applies to all customers who were using or began using utility services on or after the CPUC's December 20, 1995, decision date. In October 1996, SCE amended its August 1996 transition cost filing to reflect the effects of the legislation enacted in September 1996. The CTC is being 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 had a market value equal to their net book value, and $13.8 billion (1998 net present value) assuming the fossil plants had no market value. These estimates were 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 were comprised of: $7.5 billion from SCE's qualifying facility (QF) 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 (successful completion of the sale of SCE's gas-fired generating plants would reduce this estimate of transition costs for SCE-owned generation to less than $5 billion) 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 Units 2 and 3 and the Palo Verde 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 was separated into two phases; Phase 1 addressed the rate-making issues and Phase 2 the quantification issues. A decision on Phase 1 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. The Phase 2 decision, which was issued in November 1997, established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil- and hydroelectric-generation related assets) beginning July 1997, five months earlier than anticipated. SCE has filed an application for rehearing on the 1997 rate of return issue. Accounting for Generation-Related Assets -- If the CPUC's electric industry restructuring plan continues 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). During the third quarter of 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities. SCE took this action after a consensus was reached by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) in July 1997, 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. However, implementation of the EITF consensus did not require SCE to write off any of its generation-related assets, including regulatory assets of approximately $900 million at March 31, 1998. SCE has retained 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 <PAGE 8> EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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 by the FERC in its March and November 1997 orders, 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 addressed 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 were 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. The open access transmission tariff was terminated as of April 1, 1998, when the ISO began operation. Mojave Cogeneration Contract In 1991, SCE filed its testimony in the QF phase of the 1991 Energy Cost Adjustment Clause proceeding. In 1993, the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the reasonableness of SCE's QF contracts and alleged that SCE had imprudently renegotiated a QF contract with the Mojave Cogeneration Company. The report recommended a disallowance of $32 million (1993 net present value) over the contract's 20-year life. Subsequently, SCE and the ORA reached a settlement where SCE agreed to a one-time reduction to its energy-cost adjustment clause balancing account of $14 million plus interest. Because SCE and the ORA were unable to finalize their settlement, hearings on the ORA's disallowance recommendations were held in June 1997. During the hearings, the ORA presented testimony updating its assessment of ratepayer harm to $45 million (1997 net present value) over the contract's life. On April 19, 1998, the CPUC issued a decision resulting in a $16 million disallowance, which has been fully reflected in SCE's financial statements. <PAGE 9> EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. In December 1997, the Brooklyn Navy Yard Project partnership completed a $407 million permanent, nonrecourse financing for the project. In February 1997, the contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $137 million. In addition to defending this action, the partnership 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 agreed to indemnify the partnership and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to the lenders. Edison International 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). Edison International's recorded estimated minimum liability to remediate its 51 identified sites (50 at SCE and one at EME) is $178 million. 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. The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $90 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 <PAGE 10> EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 $150 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can now be made for these sites. Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $4 million to $10 million. Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup costs, Edison International believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates. Nuclear Insurance Federal law limits public liability claims from a nuclear incident to $8.9 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $79 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of $158 million per nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million has also been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. These policies are issued primarily by mutual insurance companies owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $28 million per year. Insurance premiums are charged to operating expense. <PAGE 11> EDISON INTERNATIONAL Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition RESULTS OF OPERATIONS First Quarter 1998 vs. First Quarter 1997 Earnings Edison International's basic earnings per share were 39(cent) for the first quarter of 1998, compared to 35(cent) for the first quarter of 1997. Southern California Edison Company's (SCE) earnings were unchanged at 27(cent) per share, as Edison International's share repurchase plan offset SCE's lower authorized revenue. Edison Mission Energy (EME) and Edison Capital had combined earnings of 15(cent) per share, a 5(cent)-per-share increase. The increase was primarily due to earnings contributed by EME's investment in First Hydro, which benefited from higher energy prices in the United Kingdom and increased utilization, as well as earnings generated by Edison Capital's 1997 cross-border lease transactions. Edison Enterprises and the parent company were responsible for a 3(cent)-per-share loss in quarterly earnings, compared to a 2(cent)-per-share loss in 1997, primarily due to continued start-up costs at Edison Enterprises (Edison International's new retail arm comprised of Edison Source, Edison EV, Edison Select and Edison Utility Services) . Operating Revenue Electric utility revenue decreased 4% during the first quarter of 1998, compared with the same period in 1997, as an 8% decrease in average residential rates (mandated by legislation enacted in September 1996) was partially offset by a 3% increase in sales volume. Over 99% of electric utility 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). Legislation enacted in September 1996 provided for, among other things, at least a 10% rate reduction (financed through the issuance of rate reduction notes) for residential and small commercial customers in 1998 and other rates to remain frozen at June 1996 levels (system average of 10.1(cent) per kilowatt-hour). See discussion in Competitive Environment. Revenue from diversified operations decreased 6%, primarily due to a new series of power-sales-related contracts associated with EME's 49% acquisition of Loy Yang B in May 1997. The decrease was partially offset by increased revenue related to higher energy sales at EME's First Hydro project. . Operating Expenses Fuel expense decreased 16%, mostly due to significantly lower gas prices at SCE. In addition, EME's fuel expense decreased, due to the new fuel supply agreement entered into by Loy Yang B related to EME's 49% acquisition in May 1997, partially offset by an increase at First Hydro as a result of higher prices and increased generation. Purchased-power expense decreased 8%, due to an increase in SCE's power generation from San Onofre Nuclear Generating Station Unit 2. San Onofre Unit 2 was shut down the entire first quarter of 1997 for a refueling outage. A factor that increases expenses in all periods is the federal requirement that SCE purchase power from certain nonutility generators even though energy prices under these contracts are generally higher than other sources. For the twelve months ended March 31, 1998, 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. <PAGE 12> Provisions for regulatory adjustment clauses decreased substantially, primarily due to undercollections in the transition cost balancing account. Beginning in January 1998, the difference between generation-related revenue and generation-related costs is being accumulated in the transition cost balancing account, effectively eliminating all other balancing accounts except those used in the administration of public-purpose funds. Also, in January 1998, overcollections in the kilowatt-hour sales and energy cost balancing accounts, which were previously transferred to an interim balancing account, were credited to the transition cost balancing account. The December 31, 1997, balances in these balancing accounts were also transferred to the transition cost balancing account. Other operating expenses increased 17%, mostly due to direct access activities and storm damage expense at SCE resulting from a harsher winter in 1998, and continued start-up expenses at Edison Enterprises. Depreciation and decommissioning expense increased 21%, primarily due to the accelerated recovery of SCE's gas-and oil-fueled generation plants and the further acceleration of the San Onofre and Palo Verde Nuclear Generating Station units. The accelerated recoveries implemented in 1998 are part of the competition transition charge (CTC) mechanism. (See further discussion under California Electric Utility Industry Restructuring.) The increase was partially offset by a decrease at EME related to an extension in the useful life of Loy Yang B's plant and equipment. Income taxes increased 42%, primarily due to an increase at SCE related to higher pre-tax income, as well as additional amortization related to the CTC mechanism. The additional amortization related to the CTC mechanism will continue to cause an increase in the effective tax rate. Also, Edison Capital had increased income tax expense related to revenue generated by its cross-border lease transactions. 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) was collected evenly over the final six years of each unit's plan. The plan ended in February 1996, September 1996 and January 1998 for Units 1, 2 and 3, respectively. The provision is a non-cash offset to the collection of deferred revenue. Interest and dividend income increased significantly, due to higher investment balances at both SCE and EME, as well as increases in interest earned on SCE's higher balancing account undercollections. Minority interest decreased due to EME's May 1997 acquisition of the remaining 49% ownership interest in the Loy Yang B project. Other nonoperating income decreased substantially, mostly due to additional accruals at SCE for regulatory matters associated with the restructuring of California's electric utility industry. Interest and Other Expenses Interest on long-term debt increased 18%, mainly due to an increase at SCE related to the issuance of rate reduction notes in December 1997. Interest on the rate reduction notes was $39 million for the quarter ended March 31, 1998. Other interest expense decreased 32%, primarily reflecting a reduction in SCE's balancing account interest as a result of higher undercollections in 1998. Financial Condition Edison International's liquidity is primarily affected by debt maturities, dividend payments and capital expenditures, and investments in partnerships and unconsolidated subsidiaries. Capital resources include cash from operations and external financings. <PAGE 13> 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 85.9 million shares ($2.0 billion) between January 1995 and May 4, 1998, funded by dividends from its subsidiaries and the issuance of rate reduction notes. For the first quarter of 1998, Edison International's cash flow coverage of dividends decreased to 5.2 times from 5.6 times for the year-earlier period, as a result of the ongoing share repurchase program. Edison International's dividend payout ratio for the twelve-month period ended March 31, 1998, was 56%. Cash Flows from Operating Activities Net cash provided by operating activities totaled $493 million in the first quarter of 1998, compared to $601 million in the first quarter of 1997. Cash from operations exceeded capital requirements for both periods presented. Cash Flows from Financing Activities At March 31, 1998, Edison International and its subsidiaries had $3.4 billion of borrowing capacity available under lines of credit totaling $3.6 billion. SCE had available lines of credit of $1.8 billion, with $1.3 billion 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 total lines of credit of $1.0 billion, with $950 million available. The nonutility companies had total lines of credit of $800 million, with $700 million 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 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 March 31, 1998, SCE could issue approximately $11.1 billion of additional first and refunding mortgage bonds and $3.9 billion of preferred stock at current interest and dividend rates. EME owns, through a wholly owned subsidiary, 50% of the Brooklyn Navy Yard project. In December 1997, the Brooklyn Navy Yard project partnership completed a $407 million permanent, nonrecourse financing for the project. In February 1997, the contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $137 million. In addition to defending this action, the partnership 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 agreed to indemnify the partnership and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to the lenders. Edison International believes that the outcome of this litigation will not materially affect its results of operations or financial position. EME has firm commitments of $271 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 $185 million, primarily for 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 and funds available from EME's revolving line of credit. <PAGE 14> California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At March 31, 1998, SCE had the capacity to pay $1.4 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. In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE is the sole member, issued approximately $2.5 billion of rate reduction notes to Bankers Trust Company of California, as certificate trustee for the California Infrastructure and Economic Development Bank Special Purpose Trust SCE-1 (Trust), which is a special purpose entity established by the State of California. The terms of the rate reduction notes generally mirror the terms of the pass-through certificates issued by the Trust, which are known as rate reduction certificates. The proceeds of the rate reduction notes were used by the SPE to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created pursuant to the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from a non-bypassable tariff levied on residential and small commercial customers. Notwithstanding the legal sale of the transition property by SCE to the SPE, the amounts reflected as assets on SCE's balance sheet have not been reduced by the amount of the transition property sold to the SPE, and the liabilities of the SPE for the rate reduction notes are for accounting purposes reflected as long-term liabilities on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities. The rate reduction notes have maturities ranging from one to 10 years, and bear interest at rates ranging from 5.98% to 6.42%. The rate reduction notes are secured solely by the transition property and certain other assets of the SPE, and there is no recourse to SCE or Edison International. Although the SPE is consolidated with SCE in the financial statements, as required by generally accepted accounting principles, the SPE is legally separate from SCE, the assets of the SPE are not available to creditors of SCE or Edison International, and the transition property is legally not an asset of SCE or Edison International. Cash Flows from Investing Activities Cash flows from investing activities are affected by additions to property and plant, the nonutilities' investments in partnerships and unconsolidated subsidiaries, proceeds from the sale of plant (see discussion in Divestiture), and funding of nuclear decommissioning trusts. Decommissioning costs are accrued and recovered in rates over the term of each nuclear generating facility's operating license through charges to depreciation expense. SCE estimates that it will spend approximately $12.7 billion between 2013 --2070 to decommission its nuclear facilities. This estimate is based on SCE's current-dollar decommissioning costs ($2.1 billion), escalated using a 6.65% annual rate. These costs are expected to be funded from independent decommissioning trusts, which will receive SCE contributions of approximately $100 million per year until decommissioning begins. Cash used for the nonutility subsidiaries' investing activities was $375 million for the three-month period ended March 31, 1998, compared to $39 million for the same period in 1997. The increase is primarily due to Edison Capital's investment in leveraged leases. Market Risk Exposures Edison International's primary market risk exposures arise from fluctuations in energy prices, interest rates and foreign exchange rates. Edison International's risk management policy allows the use of derivative financial instruments to manage its financial exposures, but prohibits the use of these instruments for speculative or trading purposes. <PAGE 15> SCE has hedged a portion of its exposure to increases in natural gas prices. Increases in natural gas prices tend to increase the price of electricity purchased from the power exchange (PX). SCE's exposure is also limited by regulatory mechanisms that protect SCE from much of the risk arising from high electricity prices. Changes in interest rates, electricity pool pricing 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 includes $6 million in the first quarter of 1998 and $3 million in the first quarter of 1997. 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, where 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 can be sold in two structures: one-way contracts, where a specified monthly amount is received in advance and difference payments are made when the pool price is above the price specified in the contract, and two-way contracts, where the counterparty pays First Hydro when the pool price is below the contract priced instead of a specified monthly amount. 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 $30 million in the first quarter of 1998, compared to an increase of $15 million in the first quarter of 1997, as a result of electricity rate swap agreements. Loy Yang B sells its electrical energy through a centralized electricity pool, 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 described below. Vesting contracts were put into place by the State of Victoria, 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 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. These contracts are accounted for as electricity rate swap agreements. 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 increased by $21 million for the quarter ended March 31, 1998, 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 <PAGE 16> relationship between macroeconomic variables will behave in a manner that is consistent with historical or forecasted relationships. Construction on the two-unit Paiton project is approximately 91% complete, and commercial operation is expected in the first half of 1999. The tariff is higher in the early years and steps down over time, and the tariff for the Paiton project includes infrastructure to be used in common by other units at the Paiton complex. The plant's output is fully contracted with the state-owned electricity company for payment in U.S. dollars. The projected rate of growth of the Indonesian economy and the exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated significantly since the Paiton project was contracted, approved and financed. The project received substantial finance and insurance support from the Export-Import Bank of the United States, The Export-Import Bank of Japan, the U.S. Overseas Private Investment Corporation and the Ministry of International Trade and Industry of Japan. The Paiton project's senior debt ratings have been reduced from investment grade to speculative grade based on the rating agencies' perceived increased risk that the state-owned electricity company might not be able to honor the electricity sales contract with Paiton. A Presidential decree has deemed some power plants, but not including the Paiton project, subject to review, postponement or cancellation. EME continues to monitor the situation closely. Projected Capital Requirements Edison International's projected construction expenditures for the next five years are: 1998 -- $911 million; 1999 -- $703 million; 2000 -- $693 million; 2001 -- $690 million; and 2002 -- $671 million. Long-term debt maturities and sinking fund requirements for the five twelve-month periods following March 31, 1998, are: 1999 -- $725 million; 2000 - -- $1.2 billion; 2001 -- $746 million; 2002 -- $532 million; and 2003 -- $667 million. Preferred stock redemption requirements for the five twelve-month periods following March 31, 1998, are: 1999 through 2002 -- zero and 2003 -- $105 million. Regulatory Matters Legislation enacted in September 1996 provided for, among other things, a 10% rate reduction for residential and small commercial customers in 1998 and other rates to remain frozen at June 1996 levels (system average of 10.1(cent) per kilowatt-hour). See further discussion in Competitive Environment -- Restructuring Legislation. In 1998, revenue is affected by various mechanisms depending on the utility operation. Revenue related to distribution operations is determined through a performance-based rate-making mechanism (PBR) (see discussion in Competitive Environment -- PBR) and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return. Until the independent system operator (ISO) began operation, transmission revenue was determined by the same mechanism as distribution operations. After March 31, 1998, transmission revenue is determined through FERC-authorized rates and transmission assets earn a 9.43% return. These rates are subject to refund. See discussions in the Competitive Environment -- Rate-setting and FERC Restructuring Decision sections. Revenue from generation-related operations is determined through the CTC mechanism, nuclear rate-making agreements and the competitive market. Revenue related to fossil and hydroelectric generation operations is recovered from two sources. The portion that is made uneconomic by electric industry restructuring is recovered through the CTC mechanism. The portion that is economic is recovered through the market. In 1998, fossil and hydroelectric generation assets earn a 7.22% return. A more detailed discussion is in Competitive Environment -- CTC. 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 <PAGE 17> nuclear assets are earning an annual rate of return of 7.35%. In addition, the San Onofre plan authorizes a fixed rate of approximately 4(cent) per kilowatt-hour generated for 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 incentive pricing portion. Palo Verde's 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. Beginning January 1, 1998, both the San Onofre and Palo Verde rate-making plans became part of the CTC mechanism. The changes in revenue from the regulatory mechanisms discussed above, excluding the effects of other rate actions, are expected to have a minimal impact on 1998 earnings. However, the issuance of the rate reduction notes in December 1997, which enables the repurchase of debt and equity, will have a negative impact on 1998 earnings of approximately $97 million. The impact on earnings per share is mitigated by the repurchase of common stock from the rate reduction note proceeds. Prior to the restructuring of the electric utility industry, SCE recovered its non-nuclear capital additions to utility plant through depreciation rates authorized in the general rate case. As part of the CTC Phase 2 decision, the CPUC authorized recovery of the December 31, 1995, balances, of non-nuclear generating facilities through the CTC mechanism. The CPUC stated that rate recovery for capital additions to the non-nuclear generating facilities should be sought through a separate filing. In October 1997, SCE filed an application with the CPUC requesting rate recovery of $61 million of net capital additions to its non-nuclear generating facilities in 1996. Hearings were held in early 1998. The ORA and Toward Utility Reform Network recommended a combined total disallowance of $37 million. A CPUC decision is expected in third quarter 1998. In third quarter 1998, SCE plans to file an application for rate recovery of capital additions to these same generating facilities for the period January 1, 1997, through April 1, 1998 (or the date of divestiture). In 1991, SCE filed its testimony in the Qualifying Facilities (QF) phase of the 1991 Energy Cost Adjustment Clause proceeding. In 1993, the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the reasonableness of SCE's QF contracts and alleged that SCE had imprudently renegotiated a QF contract with the Mojave Cogeneration Company. The report recommended a disallowance of $32 million (1993 net present value) over the contract's 20-year life. Subsequently, SCE and the ORA reached a settlement where SCE agreed to a one-time reduction to its energy-cost adjustment clause balancing account of $14 million plus interest. Because SCE and the ORA were unable to finalize their settlement, hearings on the ORA's disallowance recommendations were held in June 1997. During the hearings, the ORA presented testimony updating its assessment of ratepayer harm to $45 million (1997 net present value) over the contract's life. On April 9, 1998, the CPUC issued a decision resulting in a $16 million disallowance, which has been fully reflected in SCE's financial statements. Competitive Environment SCE currently operates in a highly regulated environment in which it has an obligation to deliver 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 Decision -- The CPUC's December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which provides competition and customer choice starting April 1, 1998. Key elements of the CPUC's restructuring decision included: creation of the PX and ISO; availability of customer choice for electricity supply and certain billing and metering services; PBR for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation; and implementation of the CTC. <PAGE 18> Restructuring Legislation -- In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted 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 included 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 legislation included 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 mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation contained 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 Notes -- In December 1997, after receiving approval from both the CPUC and the California Infrastructure and Economic Development Bank, a limited liability company created by SCE issued approximately $2.5 billion of rate reduction notes. Residential and small commercial customers, whose 10% rate reduction began January 1, 1998, will repay the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. For further details, see the discussion under Cash Flows from Financing Activities. Rate-setting -- In December 1996, SCE filed a comprehensive plan addressing 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 beginning January 1, 1998. The transmission component of this rate unbundling process was addressed at the FERC through a March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the date the ISO begins operation. In August 1997, the CPUC issued a decision which adopted a 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 reallocated amount through market revenue, other rate-making mechanisms or another review process later in its divestiture proceeding. 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. In October 1997, the FERC gave conditional, interim authorization for operation of the PX and ISO to begin on January 1, 1998. 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. The start-up of the PX and ISO was delayed by three months due to insufficient testing of systems. On March 31, 1998, both the PX and ISO began bidding and scheduling for April 1, 1998, when the ISO took over operational control of the power system. In 1996, the CPUC issued an interim order establishing a restructuring trust which would obtain loans up to $250 million (increased to $300 million in November 1997) backed by utility guarantees. The loans were used to build hardware and software systems for the ISO and PX. SCE's share of the loan guarantees is 45%, or $135 million. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In December 1997, the CPUC approved the utilities' request that the restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable <PAGE 19> charge to be recovered from all retail customers. The amount of the PX charge is $101 million, plus interest and fees over the four-year transition period; SCE's share is 45%, or $45 million. 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. Effective April 1, 1998, after a three month delay in the implementation of direct access, customers are now able to choose to remain utility customers with either bundled electric service or an hourly PX pricing option 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. As of April 1, 1998, approximately 35,000 of SCE's 4.3 million customers have requested the direct access option. Revenue Cycle Services -- A decision issued by the CPUC in May 1997, introduced customer choice to metering, billing and related services (referred to as revenue cycle services) that have been provided by California's investor-owned utilities. Under this revenue cycle services unbundling decision, beginning in April 1998 (delayed from January 1998), energy service providers (ESPs) can provide their customers with one consolidated bill for their services and the utility's services, request the utility to provide a consolidated bill to the customer or elect to have both the ESP and the utility bill the customer for their respective charges. In addition, beginning in April 1998, customers with maximum demand above 20 kW (primarily industrial and medium 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 customers who elect to have ESPs 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 will expose SCE to the possible loss of revenue, higher stranded costs and a reduction in revenue security. PBR -- In September 1996, the CPUC adopted a non-generation or transmission and distribution (T&D) PBR mechanism for SCE which began on January 1, 1997. In accordance with the CPUC decision, beginning in April 1998 the transmission portion was 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. The CPUC has announced its intention to consider unbundling SCE's cost of capital by major utility function. On May 8, 1998, SCE filed an application on this issue. A CPUC decision is expected by year-end. In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE's hydroelectric plants. The mechanism sets the hydroelectric revenue requirement in 1998 and establishes a formula for extending it through the duration of the electric industry restructuring transition period, or until market valuation of the hydroelectric facilities, whichever occurs first. The mechanism provides that power sales revenue from hydroelectric facilities in excess of the hydroelectric revenue requirement be credited against the costs to transition to a competitive market (see CTC discussion below). <PAGE 20> Divestiture -- In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its gas- and oil-fueled generation plants. Under this 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. In September 1997, the CPUC approved SCE's proposal to auction the 12 plants. In early December 1997, SCE filed a compliance filing with the CPUC stating that it had sold 10 plants; the CPUC approved the sale of the 10 plants in mid-December 1997. In the first quarter of 1998, SCE announced the pending sales of the 11th and 12th plants. SCE has received CPUC approval of the sale of the 11th plant and approval of the sale of the 12th plant is expected by the end of second quarter 1998. The total sales price of the 12 plants is $1.2 billion, over $500 million more than the combined book value. Net proceeds of the sales will be used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. The transfer of ownership of the 12 plants is expected to be completed by the end of second quarter 1998. CTC -- The costs to transition to a competitive market are being recovered through a non-bypassable CTC. This charge applies to all customers who were using or began using utility services on or after the CPUC's December 20, 1995, decision date. In October 1996, SCE amended its August 1996 transition cost filing to reflect the effects of the legislation enacted in September 1996. The CTC is being 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 had a market value equal to their net book value, and $13.8 billion (1998 net present value) assuming the fossil plants had no market value. These estimates were 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 were comprised of: $7.5 billion from SCE's QF 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 (successful completion of the sale of SCE's gas-fired generating plants would reduce this estimate of transition costs for SCE-owned generation to less than $5 billion) 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 Units 2 and 3 and the Palo Verde units (as discussed in Regulatory Matters), 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 was separated into two phases; Phase 1 addressed the rate-making issues and Phase 2 the quantification issues. A decision on Phase 1 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. The Phase 2 decision, which was issued in November 1997, established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil- and hydroelectric-generation related assets) beginning July 1997, five months earlier than anticipated. SCE has filed an application for rehearing on the 1997 rate of return issue. Accounting for Generation-Related Assets -- If the CPUC's electric industry restructuring plan continues 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). During the third quarter of 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities. SCE took this action <PAGE 21> after a consensus was reached by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) in July 1997, 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. However, implementation of the EITF consensus did not require SCE to write off any of its generation-related assets, including regulatory assets of approximately $900 million at March 31, 1998. SCE has retained 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. 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 by the FERC in its March and November 1997 orders, 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 addressed 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 were 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. The open access transmission tariff was terminated as of April 1, 1998, when the ISO began operation. 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 to the Consolidated Financial Statements, Edison International records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures <PAGE 22> the liability quarterly, by assessing a range of reasonably likely costs for each identified site. Unless there is a probable amount, SCE records the lower end of this likely range of costs. Edison International's recorded estimated minimum liability to remediate its 51 identified sites is $178 million. One of SCE's sites, a former pole-treating facility, is considered a federal Superfund site and represents 42% of its recorded liability. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. SCE 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 SCE among a range of reasonably possible outcomes. The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $90 million of its 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 $150 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can 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. 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 $935 million for the 1998-2002 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. <PAGE 23> 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, which resulted in the removal of more tubes from service than had been expected. The steam generator design allows for the removal of up to 10% of the tubes before the rated capacity of the unit must be reduced. As a result of the increased degradation, a mid-cycle inspection outage was conducted in early 1998 for Unit 2. Continued degradation was found during this inspection. Monitoring of this degradation will occur at the next scheduled refueling outage in January 1999. An additional mid-cycle inspection outage may be required early in 2000. With the results from the February 1998 outage, 7% of the tubes have now been removed from service. 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. A follow-up mid-cycle inspection indicated that the erosion had been stabilized. Additional monitoring inspections are planned during the next scheduled refueling outage in 1999. To date, 5% of Unit 3's tubes have been removed from service. During Unit 2's February 1998 mid-cycle outage, similar tube supports showed no significant levels of such erosion. Accounting Rules 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. A recently issued accounting rule requires that costs related to start-up activities be expensed as incurred, effective January 1999. Edison International currently expenses its start-up costs and therefore, does not expect this new accounting rule to materially affect its results of operations or financial position. Year 2000 Issue Many of SCE's existing computer systems identify a year by using only two digits instead of four. If not corrected, these programs could fail or create erroneous results beginning in 2000. This situation has been referred to generally as the Year 2000 Issue. SCE has developed plans and is addressing the programming changes that it has determined are necessary in order for its computer systems to function properly beginning in 2000. Remediation of SCE's key financial systems for the Year 2000 Issue was completed in 1997. SCE's informational and operational systems have been assessed, and detailed plans have been developed to address modifications required to be completed, tested and operational by December 31, 1999. Preliminary estimates of the costs to complete these modifications, including the cost of new hardware and software application modifications, range from $55 million to $80 million, about half of which are expected to be capital costs. Current rate levels for providing electric service should be sufficient to provide funding for these modifications. Remediation of existing critical systems is expected to be 75% complete by the end of 1998. SCE expects its Year 2000 date conversion project to be completed on a timely basis, with no material adverse impact to its results of operations or financial position. <PAGE 24> SCE's Year 2000 date conversion project includes an assessment of critical interfaces with the computer systems of others and it does not expect a material adverse effect on its operating and business functions from the Year 2000 Issue. Forward-looking Information In the preceding 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 further actions by state and federal regulatory bodies setting rates and implementing the restructuring of the electric utility industry; the effects of new laws and regulations relating to restructuring and other matters; the effects of increased competition in the electric utility business, including the beginning of direct customer access to retail energy suppliers and the unbundling of revenue cycle services such as metering and billing; changes in prices of electricity and fuel costs; changes in market interest or currency exchange rates; foreign currency devaluation; new or increased environmental liabilities; and other unforeseen events. <PAGE 25> PART II -- OTHER INFORMATION Item 1. Legal Proceedings Edison International Tradename Litigation On September 30, 1997, an action was filed against Edison International in the United States District Court for the Southern District of New York alleging trademark infringement under the Lanham Act and related state causes of action for unfair competition. The complaint requested injunctive relief restraining Edison International from using various tradenames and trademarks utilizing the "Edison" name and sought to recover unspecified damages in profits from Edison International allegedly arising from infringing activities. On November 19, 1997, Edison International filed and served its answer to the complaint denying all of the substantive allegations and asserting affirmative defenses. After an initial status conference, the court stayed discovery in this matter to allow the parties to discuss a resolution of the matter. Such discussions are continuing and the stay of discovery has been extended by agreement of the parties. 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. (Brooklyn Navy Yard), Mission Energy New York, Inc. and B-41 Associates, L.P., 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, asserting general monetary claims in excess of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment against Brooklyn Navy Yard in the amount of $43 million. On the same day, the court stayed all proceedings in the California action pending the appeal by PMNC of a denial of its motion to dismiss the New York action. Edison International believes that the outcome of this litigation will not have a material adverse effect on its financial position or results of operations. Southern California Edison Company 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 <PAGE 26> 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, 1996, 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 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 was 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 took place on November 17, 1997. On December 22, 1997, the judge ruled on the objections raised at the two hearings and ordered SCE to prepare a proposed Statement of Decision incorporating her ruling. SCE submitted this document to the court on January 13, 1998. At a hearing on February 4, 1998, the court, after considering additional objections to parts of the proposed order, directed SCE to prepare a further, revised order which would not materially change the court's previous, tentative rulings. This final statement of decision was filed on February 6, 1998. In addition, on February 20, 1998, the court entered a judgment against one of the Plaintiffs in the lead case. (Judgment has not yet been entered against the other plaintiff in the lead case because of outstanding issues related to SCE's damages arising from cross-claims by SCE against that plaintiff.) SCE has recently agreed to settle with the plaintiffs in seven of the lawsuits whereby SCE will waive its rights to recover costs against such plaintiffs in exchange for their agreement that there is only one fixed price period under each of their power purchase contracts with SCE and a mutual dismissal with prejudice of claims. SCE has also entered into a settlement agreement with the plaintiff in another of the lawsuits which resolves the issue of multiple fixed price periods on the same terms and which also resolves a related issue unique to that plaintiff in exchange for a nominal payment by SCE. This settlement is subject to bankruptcy court approval in bankruptcy proceedings involving the plaintiff. On April 24, 1998, the bankruptcy court issued an order approving the settlement. Geothermal Generators' Litigation On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court against another independent power producer of geothermal generation and six 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. On December 19, 1997, SCE filed a second amended complaint in response to which the Defendants filed a motion to strike, which was argued and taken under submission by the court on March 13, 1998. The Defendants also filed a motion for summary judgment, asserting that SCE's claims are time-barred or were released in connection with the settlement of prior litigation among some of the Defendants and two of SCE's affiliates, Mission Power Engineering, and The Mission Group (the Mission Parties). SCE asserts that the earlier settlement does not bar the claims it is prosecuting in this matter and that these <PAGE 27> claims are not time-barred. The motion was argued on April 22, 1998, and the matter was taken under submission at that time. SCE has also filed a cross motion for summary adjudication with respect to the issues raised in Defendants' summary judgment motion. No hearing date has been scheduled for SCE's motion for summary adjudication. In addition, the Defendants have filed a motion to stay SCE's case pending resolution of certain technical issues by the Great Basin Air Quality Management District under the doctrine of primary adjudication. The motion was heard for hearing on March 13, 1998. On April 30, 1998, the court denied the motion for stay without prejudice. The Defendants have also asserted various claims against SCE and the Mission Parties in a cross-complaint filed in the action commenced by SCE as well as in a separate action filed against SCE by three of the Defendants in Inyo County Superior Court. Following a hearing on November 20, 1997, the court consolidated these actions for all purposes and ordered the Defendants to file a second amended cross-complaint. The second amended cross-complaint asserts nineteen causes of action against SCE, three of which are also asserted against the Mission Parties, and alleges in excess of $75 million in compensatory damages and also punitive damages. Included are claims for declaratory relief; breach of the implied covenant of good faith and fair dealing; inducing breach of employee agreements; breach of contract; disparagement, and slander per se; injunctive relief and restitution for unfair business practices; anticipatory breach of contract; violation of Public Utilities Code Sections 453, 707 and 2106; and negligent and intentional misrepresentation. Several of these claims are premised on the theory that SCE has incorrectly interpreted the cross-complainants' contracts as providing for only a single "fixed price" period in view of the fact that the cross-complainants developed their projects in phases. This theory has also been asserted by other independent power producers in litigation pending in Los Angeles Superior Court. (See, "Wind Generators Litigation" above.) SCE filed a demurrer to the second amended cross-complaint which was argued on March 13, 1998, and taken under submission by the court. Based on the common issues asserted in the Wind Generation Litigation and the Defendants' second amended cross-complaint, SCE filed a petition to coordinate the consolidated actions pending in Inyo County Superior Court with the Wind Generation Litigation pending in Los Angeles County Superior Court. In connection with the petition to coordinate, SCE has also applied for a stay of all proceedings in Inyo County. Both the petition to coordinate and the application for stay were argued before the judge presiding in the Wind Generators Litigation and were denied without prejudice on April 9, 1998. 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. <PAGE 28> 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. A California Court of Appeal decision, Cynthia Jill Ford et al. v. Pacific Gas and Electric Co. (Ford), has held that the Superior Courts do not have jurisdiction to decide issues, such as those concerning EMF, which are regulated by the CPUC. The California Supreme Court recently denied the plaintiffs' petition for review in Ford and it is now binding throughout California. SCE intends to seek dismissal of these cases in light of the Court of Appeal's decision. San Onofre Personal Injury Litigation An SCE engineer employed at San Onofre died in 1991 from cancer of the abdomen. On February 6, 1995, his children sued SCE and SDG&E, as well as Combustion Engineering, the manufacturer of the fuel rods for the plant, in the U.S. District Court for the Southern District of California. Plaintiffs alleged that the former employee's illness resulted from, and was aggravated by, exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods. Plaintiffs sought unspecified compensatory and punitive damages. On April 3, 1995, the court granted the defendants' motion to dismiss 14 of the plaintiffs' 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 took place on December 4, 1997, and the matter is now under submission. 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 <PAGE 29> appealed this ruling to the Ninth Circuit Court of Appeals. Oral argument on the appeal took place on December 4, 1997, and the matter is now under submission. 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, 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 took place over approximately 22 days between January and March 1998 and resulted in a jury verdict for both defendants. It is not known whether plaintiffs will move for a new trial and/or appeal. 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 mid-1998, after completion of the trial court proceedings in the case described in the preceding paragraph. On November 20, 1997, a former contract worker at San Onofre and his wife sued SCE in the Superior Court of California, County of San Diego. The contract worker was an ironworker at San Onofre during a portion of 1995. The suit alleges that SCE allowed dangerous conditions to exist at San Onofre, causing him to sustain unspecified personal injuries. His wife alleges loss of consortium and other general damages. The case has been removed to the U.S. District Court for the Southern District of California. SCE filed a motion to dismiss the complaint for failure to state a claim. In April 1998, the plaintiffs and SCE stipulated that SCE's motion to dismiss be granted and that the plaintiffs be given leave to file an amended complaint on or before May 11, 1998. The plaintiffs have not yet filed an amended complaint. 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 <PAGE 30> (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. Plaintiff and SCE reached a settlement of this dispute for nonmonetary compensation. An agreement to dismiss the lawsuit was filed with the court on February 8, 1998. 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 revenue, 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 and SDG&E filed separate motions to dismiss this lawsuit on November 6, 1997. The employee responded to both motions on December 20, 1997. SCE and SDG&E replied to the employee's response on January 13, 1998. Oral argument on the motion to dismiss was heard on January 20, 1998, and the court has the matter under submission. Mohave Generating Station Environmental Litigation On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit in the U.S. District Court of Nevada against SCE and the other three co-owners of the Mohave Generating Station (Mohave). The lawsuit alleges that Mohave has been violating various provisions of the Clean Air Act, the Nevada state implementation plan, certain Environmental Protection Agency orders, and applicable pollution permits relating to opacity and sulfur dioxide emission limits over the last five years. The plaintiffs seek declaratory and injunctive relief as well as civil penalties. Under the Clean Air Act, the maximum civil penalty obtainable is $25,000 per day per violation. SCE and the co-owners obtained an extension to respond to the complaint and on April 10, 1998, filed a motion to dismiss. The plaintiffs' opposition to the motion was due on May 8, 1998. The reply brief to plaintiffs' opposition will be due May 22, 1998. <PAGE 32> Item 4. Submission of Matters to a Vote of Security Holders Election of Directors At Edison International's Annual Meeting of Shareholders on April 16, 1998 ("Annual Meeting"), shareholders elected sixteen nominees to the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld from each Director-nominee were as follows: <TABLE> <CAPTION> Number of Votes - ------------------------------------------------------------------------------------------------------------------- Name For Withheld - ------------------------------------------------------------------------------------------------------------------- <S> <C> <C> John E. Bryson 309,809,001 3,691,215 Winston H. Chen 310,096,788 3,403,428 Warren Christopher 309,542,029 3,958,188 Stephen E. Frank 310,028,191 3,472,026 Joan C. Hanley 310,034,561 3,465,655 Carl F. Huntsinger 310,041,039 3,459,178 Charles D. Miller 309,951,518 3,548,698 Luis G. Nogales 309,909,289 3,590,927 Ronald L. Olson 310,046,562 3,453,654 James M. Rosser 310,046,152 3,454,064 E. L. Shannon, Jr. 309,940,470 3,559,746 Robert H. Smith 310,053,524 3,446,692 Thomas C. Sutton 310,097,256 3,402,960 Daniel M. Tellep 310,060,093 3,440,123 James D. Watkins 309,878,586 3,621,630 Edward Zapanta 310,052,227 3,447,989 </TABLE> Equity Compensation Plan At the Annual Meeting, shareholders approved a compensation plan for Directors and employees of Edison International and its affiliates. The number of affirmative and negative votes, abstentions and broker non-votes with respect to the matter were as follows: <TABLE> <CAPTION> Broker Affirmative Negative Abstentions Non-votes ----------- -------- ----------- --------- <S> <C> <C> <C> <C> Common Stock 201,214,949 64,822,962 7,035,933 40,426,371 </TABLE> Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 3.1 Articles of Incorporation (File No. 1-9936, Form 10-Q for the quarterly period ended March 31, 1996)* 3.2 Bylaws as adopted by the Board of Directors effective January 1, 1998 (File No. 1-9936, Form 10-K for the year ended December 31, 1997)* - ---------------------- * Incorporated by reference pursuant to Rule 12b-32 . <PAGE 33> 10. Material Contracts 10.1 Option Gain Deferral Plan 10.2 Executive Deferred Compensation Plan 10.3 Officer Long-term Incentive Compensation Plan 11. Computation of Primary and Fully Diluted Earnings Per Share 27. Financial Data Schedule (b) Reports on Form 8-K: April 7, 1998 Item 5: Other Events: Sale of SCE Generating Plants SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EDISON INTERNATIONAL (Registrant) By R. K. BUSHEY -------------------------------------------------- R. K. BUSHEY Vice President and Controller By K. S. STEWART ------------------------------------------------- K. S. STEWART Assistant General Counsel and Assistant Secretary May 12, 1998