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 June 30, 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 August 12, 1998 - ----------------------------------- ----------------------------------------- Common Stock, no par value 353,638,586
EDISON INTERNATIONAL INDEX Page No. ---- Part I. Financial Information: Item 1. Consolidated Financial Statements: Consolidated Statements of Income -- Three and Six Months Ended June 30, 1998, and 1997 1 Consolidated Statements of Comprehensive Income -- Three and Six Months Ended June 30, 1998, and 1997 1 Consolidated Balance Sheets -- June 30, 1998, and December 31, 1997 2 Consolidated Statements of Cash Flows -- Six Months Ended June 30, 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 27 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 6 Months Ended June 30, June 30, June 30, June 30, - ------------------------------------------------------------------------------------------------------------------- 1998 1997 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) <S> <C> <C> <C> <C> Sales to ultimate consumers $1,531,452 $1,763,003 $3,077,286 $3,391,417 Sales to power exchange 303,685 -- 303,685 -- Other 87,330 80,960 164,185 147,948 - ------------------------------------------------------------------------------------------------------------------- Total electric utility revenue 1,922,467 1,843,963 3,545,156 3,539,365 Diversified operations 320,253 323,219 607,124 628,543 - ------------------------------------------------------------------------------------------------------------------- Total operating revenue 2,242,720 2,167,182 4,152,280 4,167,908 - ------------------------------------------------------------------------------------------------------------------- Fuel 100,259 194,328 267,580 394,561 Purchased power -- contracts 525,355 587,660 1,101,862 1,216,335 Purchased power -- power exchange 343,784 -- 343,784 -- Provisions for regulatory adjustment clauses-- net 485,492 (3,850) 247,474 (92,023) Other operating expenses 562,533 457,964 949,702 788,007 Maintenance 98,597 116,848 200,566 213,002 Depreciation, decommissioning and amortization 404,031 342,254 815,354 682,375 Income taxes 99,010 113,541 235,728 209,616 Property and other taxes 33,194 32,682 73,955 72,992 Gains on sale of utility plant (708,154) (3,065) (708,149) (2,836) - ------------------------------------------------------------------------------------------------------------------- Total operating expenses 1,944,101 1,838,362 3,527,856 3,482,029 - ------------------------------------------------------------------------------------------------------------------- Operating income 298,619 328,820 624,424 685,879 - ------------------------------------------------------------------------------------------------------------------- Provision for rate phase-in plan -- (11,381) -- (22,690) Allowance for equity funds used during construction 2,908 1,897 5,690 3,900 Interest and dividend income 25,078 19,149 55,794 34,991 Minority interest (859) (9,724) (2,367) (37,689) Other nonoperating income (deductions)-- net (9,107) (6,870) (18,308) (9,732) - ------------------------------------------------------------------------------------------------------------------- Total other income (deductions)-- net 18,020 (6,929) 40,809 (31,220) - ------------------------------------------------------------------------------------------------------------------- Income before interest and other expenses 316,639 321,891 665,233 654,659 - ------------------------------------------------------------------------------------------------------------------- Interest on long-term debt 147,505 152,382 326,617 304,806 Other interest expense 20,319 25,001 41,531 56,260 Allowance for borrowed funds used during construction (1,979) (2,284) (3,871) (4,696) Capitalized interest (4,461) (2,899) (8,365) (8,076) Dividends on subsidiary preferred securities 9,952 10,669 20,008 22,531 - ------------------------------------------------------------------------------------------------------------------- Total interest and other expenses-- net 171,336 182,869 375,920 370,825 - ------------------------------------------------------------------------------------------------------------------- Net Income $ 145,303 $ 139,022 $ 289,313 $ 283,834 - ------------------------------------------------------------------------------------------------------------------- Weighted-average shares of common stock outstanding 360,251 408,310 365,150 413,888 Basic earnings per share $.40 $.34 $.79 $.69 Diluted earnings per share $.40 $.34 $.78 $.68 Dividends declared per common share $.26 $.25 $.52 $.50 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME In thousands 3 Months Ended 6 Months Ended June 30, June 30, June 30, June 30, - ------------------------------------------------------------------------------------------------------------------- 1998 1997 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) Net income $145,303 $139,022 $289,313 $283,834 Cumulative translation adjustments-- net (7,585) 7,270 733 (19,631) Unrealized gains on securities-- net 1,384 7,205 15,398 14,448 - ------------------------------------------------------------------------------------------------------------------- Comprehensive income $139,102 $153,497 $305,444 $278,651 - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. 1
EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands <TABLE> <CAPTION> June 30, December 31, 1998 1997 - ------------------------------------------------------------------------------------------------------------------- ASSETS (Unaudited) Transmission and distribution: Utility plant, at original cost, subject to <S> <C> <C> cost-based rate regulation $11,454,066 $11,213,352 Accumulated provision for depreciation (5,796,847) (5,573,742) Construction work in progress 481,192 492,614 - ------------------------------------------------------------------------------------------------------------------- 6,138,411 6,132,224 - ------------------------------------------------------------------------------------------------------------------- Generation: Utility plant, at original cost, not subject to cost-based rate regulation 2,021,636 9,522,127 Accumulated provision for depreciation and decommissioning (1,065,888) (4,970,137) Construction work in progress 86,043 100,283 Nuclear fuel, at amortized cost 133,070 154,757 - ------------------------------------------------------------------------------------------------------------------- 1,174,861 4,807,030 - ------------------------------------------------------------------------------------------------------------------- Total utility plant 7,313,272 10,939,254 - ------------------------------------------------------------------------------------------------------------------- Nonutility property -- less accumulated provision for depreciation of $263,826 and $238,386 at respective dates 3,098,311 3,178,375 Nuclear decommissioning trusts 2,056,275 1,831,460 Investments in partnerships and unconsolidated subsidiaries 1,306,520 1,340,853 Investments in leveraged leases 1,386,397 959,646 Other investments 323,749 260,427 - ------------------------------------------------------------------------------------------------------------------- Total other property and investments 8,171,252 7,570,761 - ------------------------------------------------------------------------------------------------------------------- Cash and equivalents 1,655,860 1,906,505 Receivables, including unbilled revenue, less allowances of $21,345 and $26,722 for uncollectible accounts at respective dates 1,163,372 1,077,671 Fuel inventory 50,965 58,059 Materials and supplies, at average cost 116,678 132,980 Accumulated deferred income taxes-- net 313,360 123,146 Regulatory balancing accounts-- net 50,234 193,311 Prepayments and other current assets 54,136 105,811 - ------------------------------------------------------------------------------------------------------------------- Total current assets 3,404,605 3,597,483 - ------------------------------------------------------------------------------------------------------------------- Unamortized nuclear investment-- net 2,561,325 -- Unamortized debt issuance and reacquisition expense 362,125 359,304 Rate phase-in plan -- 3,777 Income tax-related deferred charges 1,559,336 1,543,380 Other deferred charges 1,212,663 1,087,108 - ------------------------------------------------------------------------------------------------------------------- Total deferred charges 5,695,449 2,993,569 - ------------------------------------------------------------------------------------------------------------------- Total assets $24,584,578 $25,101,067 - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. 2
EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands, except share amounts <TABLE> <CAPTION> June 30, December 31, 1998 1997 - ------------------------------------------------------------------------------------------------------------------- CAPITALIZATION AND LIABILITIES (Unaudited) Common shareholders' equity: Common stock (355,014,497 and 375,764,429 <S> <C> <C> shares outstanding at respective dates) $2,136,122 $ 2,260,974 Accumulated other comprehensive income: Cumulative translation adjustments-- net 31,189 30,456 Unrealized gain in equity securities-- net 75,428 60,030 Retained earnings 2,812,621 3,175,883 - ------------------------------------------------------------------------------------------------------------------- 5,055,360 5,527,343 - ------------------------------------------------------------------------------------------------------------------- Preferred securities of subsidiaries: Not subject to mandatory redemption 128,755 183,755 Subject to mandatory redemption 406,700 425,000 Long-term debt 8,677,728 8,870,781 - ------------------------------------------------------------------------------------------------------------------- Total capitalization 14,268,543 15,006,879 - ------------------------------------------------------------------------------------------------------------------- Other long-term liabilities 495,703 479,637 - ------------------------------------------------------------------------------------------------------------------- Current portion of long-term debt 791,407 868,026 Short-term debt 139,498 329,550 Accounts payable 443,642 441,049 Accrued taxes 738,798 576,841 Accrued interest 147,969 131,885 Dividends payable 92,893 95,146 Deferred unbilled revenue and other current liabilities 1,385,007 1,285,679 - ------------------------------------------------------------------------------------------------------------------- Total current liabilities 3,739,214 3,728,176 - ------------------------------------------------------------------------------------------------------------------- Accumulated deferred income taxes-- net 4,319,530 4,085,296 Accumulated deferred investment tax credits 333,919 350,685 Customer advances and other deferred credits 1,413,751 1,441,303 - ------------------------------------------------------------------------------------------------------------------- Total deferred credits 6,067,200 5,877,284 - ------------------------------------------------------------------------------------------------------------------- Minority interest 13,918 9,091 - ------------------------------------------------------------------------------------------------------------------- Commitments and contingencies (Notes 1 and 2) Total capitalization and liabilities $24,584,578 $25,101,067 - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. 3
EDISON INTERNATIONAL CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands <TABLE> <CAPTION> 6 Months Ended June 30, - ------------------------------------------------------------------------------------------------------------------- 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (Unaudited) Cash flows from operating activities: <S> <C> <C> Net income $ 289,313 $ 283,834 Adjustments for non-cash items: Depreciation, decommissioning and amortization 815,354 682,375 Other amortization 76,334 35,814 Rate phase-in plan 3,777 21,584 Deferred income taxes and investment tax credits 4,802 (13,317) Equity in income from partnerships and unconsolidated subsidiaries (62,727) (84,014) Other long-term liabilities 16,066 82,141 Regulatory asset related to the sale of utility plant (107,991) -- Net gains on sale of utility plant (640,339) -- Other-- net (149,610) (91,267) Changes in working capital: Receivables (123,278) (52,220) Regulatory balancing accounts 143,077 (94,972) Fuel inventory, materials and supplies 23,396 11,714 Prepayments and other current assets 62,503 86,223 Accrued interest and taxes 178,041 125,139 Accounts payable and other current liabilities 153,165 (48,768) Distributions from partnerships and unconsolidated subsidiaries 70,453 69,058 - ------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 752,336 1,013,324 - ------------------------------------------------------------------------------------------------------------------- Cash flows from financing activities: Long-term debt issued 716,441 1,475,537 Long-term debt repaid (873,737) (1,142,534) Common stock issued -- 4,661 Common stock repurchased (586,297) (500,285) Preferred securities redeemed (73,300) (100,000) Rate reduction notes repaid (82,465) -- Nuclear fuel financing-- net (18,871) (7,061) Short-term debt financing-- net (190,052) 235,592 Dividends paid (189,505) (210,944) Other-- net 367 973 - ------------------------------------------------------------------------------------------------------------------- Net cash used by financing activities (1,297,419) (244,061) - ------------------------------------------------------------------------------------------------------------------- Cash flows from investing activities: Additions to property and plant (398,277) (345,975) Proceeds from sale of plant 1,149,139 142,273 Funding of nuclear decommissioning trusts (76,881) (74,573) Investments in partnerships and unconsolidated subsidiaries (53,636) (162,076) Unrealized gain on securities-- net 15,398 14,448 Investments in leveraged leases (336,637) (270,626) Other-- net (4,668) (73,591) - ------------------------------------------------------------------------------------------------------------------- Net cash provided (used) by investing activities 294,438 (770,120) - ------------------------------------------------------------------------------------------------------------------- Net decrease in cash and equivalents (250,645) (857) Cash and equivalents, beginning of period 1,906,505 896,594 - ------------------------------------------------------------------------------------------------------------------- Cash and equivalents, end of period $1,655,860 $ 895,737 - ------------------------------------------------------------------------------------------------------------------- </TABLE> The accompanying notes are an integral part of these financial statements. 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. As a result of industry restructuring legislation enacted by the State of California and a related change in the application of accounting principles for rate-regulated enterprises adopted by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF), during the third quarter of 1997, Southern California Edison Company (SCE) began accounting for its investments in generation facilities in accordance with accounting principles applicable to enterprises in general, and SCE's balance sheets display a separate caption for its investments in generation. Application of accounting principles for enterprises in general to SCE's generation assets did not result in any adjustment of their carrying value; however, SCE's nuclear investments were reclassified as a regulatory asset in second quarter 1998. In June 1998, a new accounting standard for derivative instruments and hedging activities was issued. The new standard, which will be effective January 1, 2000, requires all derivatives to be recognized on the balance sheet at fair value. Gains or losses from changes in fair value would be recognized in earnings in the period of change unless the derivative is designated as a hedging instrument. Gains or losses from hedges of a forecasted transaction or foreign currency exposure would be reflected in other comprehensive income. Gains or losses from hedges of a recognized asset or liability or a firm commitment would be reflected in earnings for the ineffective portion of the hedge. SCE anticipates that most of its derivatives under the new standard would qualify for hedge accounting. SCE expects to recover in rates any market price changes from its derivatives that could potentially affect earnings. Edison International is studying the impact of the new standard on its nonutility subsidiaries, and is unable to predict at this time the impact on its financial statements. Certain prior-period amounts were reclassified to conform to the June 30, 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; competition and customer choice began on 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 Statute -- In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The Statute 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 are being recovered through the terms of their 5
EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS contracts while most of the remaining transition costs will be recovered through 2001. The Statute 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 allowed SCE to reduce rates by at least 10% to these customers, effective January 1, 1998. The Statute 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 Statute mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the Statute 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. A voter initiative, known as California Proposition 9, seeks to overturn major portions of the Statute. A more detailed discussion of Proposition 9 is in Note 2 to the Consolidated Financial Statements. 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, are repaying the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. A voter initiative on the November 1998 ballot seeks to prohibit the collection of these non-bypassable charges, or if the charges are found enforceable by a court, require SCE to offset such charges with an equal credit to customers. See Note 2 to the Consolidated Financial Statements. Rate-setting -- Beginning January 1, 1998, SCE's rates were unbundled into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning. The transmission component is being collected through Federal Energy Regulatory Commission (FERC)-approved rates, subject to refund. 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 (see PBR discussion below) 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 operation and maintenance contracts with the new owners of the divested generation plants. PX and ISO -- On March 31, 1998, both the PX and ISO began accepting bids and schedules for April 1, 1998, when the ISO took over operational control of the transmission system. The hardware and software systems being utilized by the PX and ISO in their bidding and scheduling activities were financed through loans of $300 million (backed by utility guarantees) obtained by restructuring trusts established by a CPUC order in 1996. The PX and ISO will repay the trusts' loans through charges for service to future PX and ISO customers. The restructuring implementation costs related to the start-up and development of the PX, which are paid by the utilities, will be recovered from all retail customers over the four-year transition period. SCE's share of the charge is $45 million, plus interest and fees. SCE's share of the ISO's start-up and development costs (approximately $16 million per year), will be paid over a 10-year period. Direct Customer Access -- Effective April 1, 1998, customers are now able to choose to remain utility customers with either bundled electric service or an hourly PX pricing option from SCE (which is purchasing its power through the PX), or choose direct access, which means the customer can contract directly with either independent power producers or energy service providers (ESPs) such as power brokers, marketers and aggregators. Additionally, all investor-owned-utility customers are paying the CTC whether or not they choose to buy power through SCE. Electric utilities are continuing to provide the core distribution service of delivering energy through their distribution system regardless of a 6
EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS customer's choice of electricity supplier. The CPUC is continuing to regulate the prices and service obligations related to distribution services. Revenue Cycle Services -- Effective April 1, 1998, customers have options regarding metering, billing and related services (referred to as revenue cycle services) that have been provided by California's investor-owned utilities. Now 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, 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 provide them with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to provide such customers with the utility's avoided costs net of costs incurred by the utility to facilitate the provision of such services by a firm other than the utility. PBR -- In September 1996, the CPUC adopted a transmission and distribution (T&D) PBR mechanism for SCE which began on January 1, 1997. Beginning in April 1998, the transmission portion was separated from PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001. Key elements of 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 is considering unbundling SCE's cost of capital based on major utility function. On May 8, 1998, SCE filed an application on this issue. A CPUC decision is expected in early 1999. Beginning in 1998, SCE's hydroelectric plants are operating under a PBR-type mechanism. The mechanism sets the hydroelectric revenue requirement 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. SCE has sold all 12 of its gas- and oil-fueled generation plants. Transfer of ownership of 11 plants was completed by June 30, 1998, and the transfer of ownership of the 12th plant took place on July 8, 1998. The total sales price of the 12 plants was $1.2 billion, over $500 million more than the combined book value. Net proceeds of the sales were used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. 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. The CTC is being determined residually by subtracting other rate components for the PX, T&D, nuclear decommissioning and public benefit programs from the frozen rate levels. SCE currently estimates its transition costs to be approximately $10.6 billion (1998 net 7
EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS present value) from 1998 through 2030. This estimate is based on incurred costs, forecasts of future costs and assumed market prices. However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of $6.4 billion from SCE's qualifying facilities contracts, which are the direct result of prior legislative and regulatory mandates, and $4.2 billion from costs pertaining to certain generating assets (successful completion of the sale of SCE's gas-fired generating plants has reduced this estimate of transition costs for SCE-owned generation) 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. This issue was separated into two phases; Phase 1 addressed the rate-making issues and Phase 2 the quantification issues. Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the establishment of a transition cost balancing account and annual transition cost proceedings; the setting of a market rate forecast for 1998 transition costs; the requirement that generation-related regulatory assets be amortized ratably over a 48-month period; the establishment of calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze; and the reduction of 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 described 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 based on a consensus reached by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF). The financial reporting effect of this discontinuance was to segregate these assets on the balance sheet; the EITF consensus did not require SCE to write off any of its generation-related assets, including related regulatory assets. However, the EITF did not specifically address the application of asset impairment standards to these assets. 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. The regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments and unamortized losses on reacquired debt. 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. During the second quarter of 1998, additional guidance was developed relating to the application of asset impairment standards to these assets. Using this guidance has resulted in SCE reducing its remaining nuclear plant investment by $2.6 billion and recording a regulatory asset on its balance sheet for the same amount. For this impairment assessment, the fair value of the investment was calculated by discounting future net cash flows. This reclassification had no effect on SCE's results of operations. If during the transition period events were to occur that made the recovery of generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets (approximately $2.4 billion, after tax, at June 30, 1998) as a one-time, non-cash charge against earnings. 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 8
EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Note 2. Contingencies In addition to the matters disclosed in these notes, Edison International is involved in other 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 other proceedings will not materially affect its results of operations or liquidity. California Proposition 9 -- November 1998 Voter Initiative In November 1997, individuals representing The Utilities Reform Network, Public Media Center and the Coalition Against Utility Taxes filed a proposed voter initiative that seeks to overturn major portions of the electric industry restructuring legislation enacted in California in September 1996 (Statute). The voter initiative proposes, among other things, to: (i) impose an additional 10% rate reduction for residential and small commercial customers beyond the 10% reduction that went into effect on January 1, 1998; (ii) block stranded-cost recovery of nuclear investments; (iii) restrict stranded-cost recovery of non-nuclear investments unless the CPUC finds that the utility would be deprived of the opportunity to earn a fair rate of return; and (iv) prohibit the collection of any charges in connection with a financing order for the purpose of making payments on rate reduction notes, or if the financing order is found enforceable by a court, require the utility to offset such charges with an equal credit to customers. On June 24, 1998, the California Secretary of State announced that the proposed voter initiative qualified for the November 1998 ballot. On July 17, 1998, the Secretary of State designated the initiative as Proposition 9 on the ballot. On May 22, 1998, Californians for Affordable and Reliable Electric Service (CARES), a coalition of California business organizations and utilities, filed a petition for writ of mandate with the Court of Appeal of the State of California. CARES is sponsored by the California Business Roundtable, the California Chamber of Commerce, San Diego Gas & Electric Company, the California Manufacturers Association, Pacific Gas & Electric Company, the California Retailers Association, and SCE, among other groups. The CARES petition challenged the initiative as illegal and unconstitutional on its face, and sought to remove the initiative from the November 1998 ballot. On July 2, 1998, the Court of Appeal denied the CARES petition. On July 6, 1998, CARES filed its appeal of the denial with the California Supreme Court. On July 15, 1998, the California Supreme Court denied the CARES petition. In these rulings, the Court of Appeal of the State of California and the California Supreme Court both decided, in effect, not to consider the legality and constitutionality of Proposition 9 prior to the November 1998 election. If Proposition 9 is voted into law, further litigation would ensue. Under the terms of a servicing agreement relating to the rate reduction notes, SCE (acting as the servicer) is required to take such legal or administrative actions as may be reasonably necessary to block or overturn any attempts to cause a repeal of, modification of, or supplement to the Statute, the financing order issued by the CPUC, or the rights of holders of the property right authorized by the Statute and the financing order by legislative enactment, voter initiative or constitutional amendment that would be adverse to holders of the rate reduction notes. The costs of such actions would be payable out of collections of the non-bypassable charges established by the financing order and the related issuance advice letter as an operating expense related to the rate reduction notes. However, SCE may be required to advance its own funds to satisfy its obligations as servicer to take such legal and administrative actions. 9
EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SCE is unable to predict the outcome of this matter, but if Proposition 9 were to be voted into law, and not immediately stayed and ultimately invalidated by the courts, it could have a material adverse effect on SCE's results of operation and financial position. Upon voter approval of Proposition 9, a write-down of a portion of SCE's generation-related assets might be required under applicable accounting principles, depending on SCE's assessment of both the probability that Proposition 9 would be struck down by the courts and the manner in which it would be interpreted and applied to SCE. The meaning of many provisions of Proposition 9 is unclear and, if the courts uphold it in whole or part, will be subject to judicial and regulatory interpretation. Depending on how Proposition 9 is interpreted and implemented with respect to SCE, the potential write-down of SCE's generation-related assets could amount to as much as $1.9 billion after tax. Additionally, if Proposition 9 passes and survives legal challenges, SCE could suffer impacts on its annual earnings, including the possibility of being required to offset customer charges necessary to pay the principal and interest on the rate reduction notes. Depending on how this provision and other provisions of Proposition 9 are interpreted and applied, the annual earnings reductions could be as large as $210 million in 1999, gradually declining to as much as $10 million in 2007, and immaterial amounts thereafter. 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. SCE has sold all of its gas- and oil-fueled power plants and has retained some liability associated with the divested properties. The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $91 million of Edison International's recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance 10
EDISON INTERNATIONAL NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 $148 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. 11
EDISON INTERNATIONAL Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition Results of Operations Earnings Edison International's basic earnings per share for the three and six months ended June 30, 1998, were 40(cent) and 79(cent), respectively, compared with 34(cent) and 69(cent) for the same periods in 1997. Southern California Edison Company's (SCE) earnings for the three and six months ended June 30, 1998, were 31(cent) and 58(cent), respectively, 1(cent) more than each of the year-earlier periods, primarily due to the operating performance at the San Onofre Nuclear Generating Station and Edison International's share repurchase program more than offsetting SCE's lower authorized revenue. The lower authorized revenue was driven by reduced authorized returns on generating assets and a lower earning asset base resulting from the accelerated recovery of investments and divestiture of gas- and oil-fueled generation assets. Edison Mission Energy (EME) and Edison Capital had combined earnings for the three and six months ended June 30, 1998, of 12(cent) and 27(cent), respectively, up 5(cent) and 11(cent) from the year-earlier periods. The increases were primarily due to earnings generated by Edison Capital's cross-border lease transactions in the Netherlands, South Australia and South Africa. The year-to-date increase also reflects earnings contributed by EME's investment in First Hydro, which benefited from higher energy prices in the United Kingdom. Edison Enterprises and the parent company were responsible for the following negative income effects: 3(cent) per share for the second quarter of 1998 and 6(cent) for the first half of 1998, compared to 3(cent) and 4(cent) for the same periods in 1997, primarily due to continued start-up costs at Edison Enterprises (Edison International's new retail businesses: Edison Source, Edison EV, Edison Select and Edison Utility Services). Operating Revenue Since April 1, 1998, SCE is required to sell all of its generated power to the power exchange (PX). For more details, see "Competitive Environment -- PX and ISO." Excluding the sales to the PX, electric utility revenue decreased 12% and 8%, respectively, for the three and six months ended June 30, 1998, compared to the year-earlier periods. The decreases reflect lower average residential rates (mandated by legislation enacted in September 1996). The quarterly decrease also includes a decrease in sales volume due to milder weather in second quarter 1998. Over 99% of electric utility revenue (excluding sales to the PX) 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 slightly for both the three and six months ended June 30, 1998, compared to the same periods in 1997, primarily due to a new series of power-sales-related contracts associated with EME's acquisition of the remaining 49% of Loy Yang B in May 1997. The year-to-date decrease was partially offset by increased revenue related to higher energy sales at EME's First Hydro project. Operating Expenses Fuel expense decreased 48% and 32%, respectively, for the three and six months ended June 30, 1998, compared to the same periods in 1997. The quarterly and year-to-date decreases resulted from the sale of SCE's gas- and oil-fueled plants. In addition, the year-to-date decrease also reflects significantly lower gas prices at SCE in the first quarter of 1998, as well as a decrease at EME due to the new fuel supply agreement entered into by Loy Yang B, partially offset by an increase at First Hydro as a result of higher prices and increased generation in 1998. 12
Since April 1, 1998, SCE is required to purchase all of its power from the PX for distribution to its customers. The new competitive market has caused SCE to only make federally required purchases or purchases required under long-term contracts and to discontinue making economy power purchases. Excluding the power purchased from the PX, purchased-power expense decreased 11% and 9%, respectively, for the three and six months ended June 30, 1998, compared to the year-earlier periods. The decreases are the result of SCE discontinuing economy purchases. SCE is required under federal law to purchase power from certain nonutility generators even though energy prices under these contracts are generally higher than other sources. For the twelve months ended June 30, 1998, SCE paid about $1.5 billion (including energy and capacity payments) more for these power purchases than the cost of power available from other sources. The CPUC has mandated the prices for these contracts. Provisions for regulatory adjustment clauses increased substantially for the quarter and six months ended June 30, 1998, compared to the same periods in 1997, primarily due to overcollections in the transition cost balancing account reflecting the gain on sales of the gas- and oil-fueled plants in second quarter 1998. The overcollections were partially offset by undercollections related to direct access activities, the delay in the start-up of the PX and independent system operator (ISO) and the issuance of the rate reduction notes in December 1997. 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. Other operating expenses increased for the three and six months ended June 30, 1998, compared to the same periods in 1997, primarily due to SCE's direct access activities, must-run reliability services and PX and ISO activities. The year-to-date increase also reflects storm damage expense at SCE resulting from a harsher winter in 1998, as well as continued start-up expenses at Edison Enterprises. Maintenance expense decreased 16% for the quarter ended June 30, 1998, compared to the year-earlier period, reflecting the extended refueling outages at San Onofre during the second quarter of 1997. Depreciation, decommissioning and amortization expense increased 18% and 19%, respectively, for the quarter and six months ended June 30, 1998, compared to the same periods in 1997. The increases are primarily due to the accelerated recovery of the 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 increases were partially offset by a decrease at EME related to an extension in the useful life of Loy Yang B's plant and equipment, from approximately 30 years, the term of the previous power-purchase agreement, to 50 years, the projected economic life of the plant. Income taxes decreased 13% and increased 12%, respectively, for the three and six months ended June 30, 1998, compared to the same periods in 1997. The quarterly decrease is primarily due to lower pre-tax income at SCE, partially offset by higher pre-tax income at Edison Capital. The year-to-date increase is mostly due to higher pre-tax income for the first quarter of 1998, 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. Gains on sale of utility plant are from the sale of 11 of SCE's 12 gas- and oil-fueled generation plants in the first half of 1998. Other Income and Deductions The provision for rate phase-in plan reflected 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 was a non-cash offset to the collection of deferred revenue. 13
Interest and dividend income increased 31% and 59%, respectively, for the three and six months ended June 30, 1998, compared to the year-earlier periods. The increases reflect higher investment balances due to the sale of SCE's gas- and oil-fueled generation plants. The year-to-date increase also reflects interest earned on higher balancing account undercollections in the first quarter of 1998. 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 33% and 88%, respectively, for the second quarter and first half of 1998, compared to the same periods in 1997. The decreases are due to additional accruals at SCE for regulatory matters associated with the restructuring of California's electric utility industry. The quarterly decrease also reflects the absence of second quarter 1997 income at EME related to a gain on sale of their ownership interest in BC Star Partners, partially offset by the extinguishment of Loy Yang B debt. Interest and Other Expenses Interest on long-term debt increased for the six months ended June 30, 1998, compared to the year-earlier periods, mainly due to an increase at SCE related to the issuance of rate reduction notes in December 1997, partially offset by lower expenses at EME due to lower principal balances on outstanding debt. Interest on the rate reduction notes was $38 million and $77 million, respectively, for the second quarter and first half of 1998. Other interest expense decreased 19% and 26%, respectively, for the three and six months ended June 30, 1998, compared to the same periods in 1997. The decreases are primarily due to lower levels of short-term debt at June 30, 1998, versus June 30, 1997. In addition, the year-to-date decrease reflects a reduction in SCE's balancing account interest expense as a result of higher undercollections in the first quarter of 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. Edison International's Board of Directors has authorized the repurchase of up to $2.8 billion (increased from $2.3 billion in July 1998) of its outstanding shares of common stock. Edison International has repurchased 95.3 million shares ($2.3 billion) between January 1995 and August 5, 1998, funded by dividends from its subsidiaries and the issuance of rate reduction notes. Edison International's cash flow coverage of dividends for the six months ended June 30, 1998, was 4.0 times, compared to 4.8 times for the same period in 1997. The decrease was primarily due to the ongoing share repurchase program, as well as the gain on sale of SCE's 11 gas- and oil-fueled generation plants. Edison International's dividend payout ratio for the twelve-month period ended June 30, 1998, was 55%. Cash Flows from Operating Activities Net cash provided by operating activities totaled $752 million for the six-month period ended June 30, 1998, compared with $1.0 billion in 1997. Cash from operations exceeded capital requirements for both periods presented. Cash Flows from Financing Activities At June 30, 1998, Edison International and its subsidiaries had $2.2 billion of borrowing capacity available under lines of credit totaling $2.6 billion. SCE had available lines of credit of $1.3 billion, with $735 million for general purpose short-term debt and $515 million for the long-term refinancing of its 14
variable-rate pollution-control bonds. The parent company had total lines of credit of $500 million, with $489 million available. The nonutility companies had total lines of credit of $800 million, with $452 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. 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 June 30, 1998, SCE could issue approximately $12.0 billion of additional first and refunding mortgage bonds and $4.4 billion of preferred stock at current interest and dividend rates. EME has firm commitments of $281 million to make equity and other contributions, primarily for the ISAB project in Italy, the Paiton project in Indonesia, the Tri-Energy project in Thailand, and the Doga project in Turkey. EME also has contingent obligations to make additional contributions of $203 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. 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 June 30, 1998, SCE had the capacity to pay $1.1 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. A voter initiative, known as California Proposition 9 on the November 1998 ballot, proposes to, among other things, prohibit the collection of any charges in connection with the financing order for the purpose of making payments on rate reduction notes. If Proposition 9 is voted into law and is not immediately overturned or is not stayed pending judicial review of its merits, the collection of charges necessary to pay the certificates while the litigation is pending could be precluded, which would adversely affect the 15
certificates and the secondary market for the certificates, including the pricing, liquidity, dates of maturity, and weighted-average lives of the certificates. In addition, if Proposition 9 is voted into law and upheld by the courts, it could have a further material adverse effect on the certificates and the holders of the certificates could incur a loss on their investment. A more detailed discussion is in "California Proposition 9 -- November 1998 Voter Initiative." 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. Any plan to decommission San Onofre Unit 1 prior to 2013 is not expected to affect SCE's annual contributions to the decommissioning trusts. Cash used for the nonutility subsidiaries' investing activities was $423 million for the six-month period ended June 30, 1998, compared to $401 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. 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 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 $12 million in the six months ended June 30, 1998, compared to $7 million for the same period in 1997. The maturity dates of several of EME's interest rate swap and collar 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 electric energy and capacity through a centralized electricity pool, which establishes a half-hourly clearing price or pool price for electric 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 purchasing 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 pool 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 $29 million for the six months ended 16
June 30, 1998, compared to an increase of $20 million for the same period in 1997, as a result of electricity rate swap agreements. The structure of the forward-contracts market and the pool is currently under review by the Director General of Electricity Supply, at the request of the Minister for Science, Energy and Industry in the United Kingdom, and a report is expected in the third quarter of 1998. Loy Yang B sells its electric 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 Government of Victoria (State), between each generator and each distributor, prior to the privatization of electric power distributors in order to provide more predictable pricing for those electricity customers that were unable to choose their electricity retailer. Vesting contracts set base strike prices at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the 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 $41 million for the six months ended June 30, 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. Statistical forecasting techniques are used to help assess foreign exchange risk and the probabilities of various outcomes. There can be no assurance, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between macroeconomic variables will behave in a manner that is consistent with historical or forecasted relationships. Construction on the two-unit Paiton project is approximately 93% 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 -- $867 million; 1999 -- $729 million; 2000 -- $685 million; 2001 -- $684 million; and 2002 -- $656 million. Long-term debt maturities and sinking fund requirements for the five twelve-month periods following June 30, 1998, are: 1999 -- $769 million; 2000 -- $991 million; 2001 -- $1.2 billion; 2002 -- $341 million; and 2003 -- $698 million. 17
Preferred stock redemption requirements for the five twelve-month periods following June 30, 1998, are: 1999 through 2001 -- zero; 2002 -- $105 million; and 2003 -- $9 million. Generating Station Acquisition On August 2, 1998, EME entered into agreements to acquire the 1,884-MW Homer City Generating Station for approximately $1.8 billion. Homer City, jointly owned by subsidiaries of GPU, Inc. and New York State Electric & Gas Corporation, is the only major regional coal-fired facility with direct high voltage interconnection to the New York Power Pool and the Pennsylvania-New Jersey-Maryland Power Pool without access charges. The plant is located near Pittsburgh, Pennsylvania. EME will operate the plant, which is one of the lowest-cost generation facilities in the region. The sale is subject to approval by the Pennsylvania Public Utility Commission, the New York State Public Service Commission and other regulatory agencies, and is expected to be completed by the first quarter of 1999. EME plans to finance this acquisition with a combination of debt secured by the project, EME corporate debt and cash. The acquisition is expected to have no effect on 1999 earnings and a positive effect on earnings in 2000 and beyond. 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 Statute." In 1998, revenue is determined 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 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 discussion in "Competitive Environment -- Rate-setting." 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 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. 18
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 1996 capital additions to its non-nuclear generating facilities. Hearings were held in early 1998. The CPUC's Office of Ratepayer Advocates and The Utilities 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 the date of divestiture. 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; competition and customer choice began on 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. Restructuring Statute -- In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The Statute 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 are being recovered through the terms of their contracts while most of the remaining transition costs will be recovered through 2001. The Statute 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 allowed SCE to reduce rates by at least 10% to these customers, effective January 1, 1998. The Statute 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 Statute mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the Statute 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. A voter initiative, known as California Proposition 9, seeks to overturn major portions of the Statute. A more detailed discussion of Proposition 9 is in "California Proposition 9 -- November 1998 Voter Initiative." 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, are repaying the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. A voter initiative on the November 1998 ballot seeks to prohibit the collection of these non-bypassable charges, or if the charges are found enforceable by a court, require SCE to offset such charges with an equal credit to customers. For further details, see the discussion in "Cash Flows from Financing Activities." 19
Rate-setting -- Beginning January 1, 1998, SCE's rates were unbundled into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning. The transmission component is being collected through FERC-approved rates, subject to refund. 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 (see "PBR" discussion below) 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 operation and maintenance contracts with the new owners of the divested generation plants. PX and ISO -- On March 31, 1998, both the PX and ISO began accepting bids and schedules for April 1, 1998, when the ISO took over operational control of the transmission system. The hardware and software systems being utilized by the PX and ISO in their bidding and scheduling activities were financed through loans of $300 million (backed by utility guarantees) obtained by restructuring trusts established by a CPUC order in 1996. The PX and ISO will repay the trusts' loans through charges for service to future PX and ISO customers. The restructuring implementation costs related to the start-up and development of the PX, which are paid by the utilities, will be recovered from all retail customers over the four-year transition period. SCE's share of the charge is $45 million, plus interest and fees. SCE's share of the ISO's start-up and development costs (approximately $16 million per year) will be paid over a 10-year period. Direct Customer Access -- Effective April 1, 1998, customers are now able to choose to remain utility customers with either bundled electric service or an hourly PX pricing option from SCE (which is purchasing its power through the PX), or choose direct access, which means the customer can contract directly with either independent power producers or energy service providers (ESPs) such as power brokers, marketers and aggregators. Additionally, all investor-owned-utility customers are paying the CTC whether or not they choose to buy power through SCE. Electric utilities are continuing to provide the core distribution service of delivering energy through their distribution system regardless of a customer's choice of electricity supplier. The CPUC is continuing to regulate the prices and service obligations related to distribution services. As of July 1, 1998, approximately 47,000 of SCE's 4.3 million customers have requested the direct access option. Revenue Cycle Services -- Effective April 1, 1998, customers have options regarding metering, billing and related services (referred to as revenue cycle services) that have been provided by California's investor-owned utilities. Now 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, 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 provide them with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to provide such customers with the utility's avoided costs net of costs incurred by the utility to facilitate the provision of such services by a firm other than the utility. The unbundling of revenue cycle services will expose SCE to the possible loss of revenue and a reduction in revenue security. PBR -- In September 1996, the CPUC adopted a transmission and distribution (T&D) PBR mechanism for SCE which began on January 1, 1997. Beginning in April 1998, the transmission portion was separated from PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001. Key elements of 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. 20
The CPUC is considering unbundling SCE's cost of capital based on major utility function. On May 8, 1998, SCE filed an application on this issue. A CPUC decision is expected in early 1999. Beginning in 1998, SCE's hydroelectric plants are operating under a PBR-type mechanism. The mechanism sets the hydroelectric revenue requirement 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. SCE has sold all 12 of its gas- and oil-fueled generation plants. Transfer of ownership of 11 plants was completed by June 30, 1998, and transfer of ownership of the 12th plant took place on July 8, 1998. The total sales price of the 12 plants was $1.2 billion, over $500 million more than the combined book value. Net proceeds of the sales were used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. 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. The CTC is being determined residually by subtracting other rate components for the PX, T&D, nuclear decommissioning and public benefit programs from the frozen rate levels. SCE currently estimates its transition costs to be approximately $10.6 billion (1998 net present value) from 1998 through 2030. This estimate is based on incurred costs, forecasts of future costs and assumed market prices. However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of $6.4 billion from SCE's qualifying facilities contracts, which are the direct result of prior legislative and regulatory mandates and $4.2 billion from costs pertaining to certain generating assets (successful completion of the sale of SCE's gas-fired generating plants has reduced this estimate of transition costs for SCE-owned generation) 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. This issue was separated into two phases; Phase 1 addressed the rate-making issues and Phase 2 the quantification issues. Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the establishment of a transition cost balancing account and annual transition cost proceedings; the setting of a market rate forecast for 1998 transition costs; the requirement that generation-related regulatory assets be amortized ratably over a 48-month period; the establishment of calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze; and the reduction of 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 described 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 based on a consensus reached by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF). The financial reporting effect of this discontinuance was to segregate these assets on the balance sheet; the EITF consensus did not require SCE to write off any of its generation-related assets, including related 21
regulatory assets. However, the EITF did not specifically address the application of asset impairment standards to these assets. 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. The regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments and unamortized losses on reacquired debt. 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. During the second quarter of 1998, additional guidance was developed relating to the application of asset impairment standards to these assets. Using this guidance has resulted in SCE reducing its remaining nuclear plant investment by $2.6 billion and recording a regulatory asset on its balance sheet for the same amount. For this impairment assessment, the fair value of the investment was calculated by discounting future net cash flows. This reclassification had no effect on SCE's results of operations. If during the transition period events were to occur that made the recovery of generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets (approximately $2.4 billion, after tax, at June 30, 1998) as a one-time, non-cash charge against earnings. 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. California Proposition 9 -- November 1998 Voter Initiative In November 1997, individuals representing The Utilities Reform Network, Public Media Center and the Coalition Against Utility Taxes filed a proposed voter initiative that seeks to overturn major portions of the electric industry restructuring legislation enacted in California in September 1996 (Statute). The voter initiative proposes, among other things, to: (i) impose an additional 10% rate reduction for residential and small commercial customers beyond the 10% reduction that went into effect on January 1, 1998; (ii) block stranded-cost recovery of nuclear investments; (iii) restrict stranded-cost recovery of non-nuclear investments unless the CPUC finds that the utility would be deprived of the opportunity to earn a fair rate of return; and (iv) prohibit the collection of any charges in connection with a financing order for the purpose of making payments on rate reduction notes, or if the financing order is found enforceable by a court, require the utility to offset such charges with an equal credit to customers. On June 24, 1998, the California Secretary of State announced that the proposed voter initiative qualified for the November 1998 ballot. On July 17, 1998, the Secretary of State designated the initiative as Proposition 9 on the ballot. On May 22, 1998, Californians for Affordable and Reliable Electric Service (CARES), a coalition of California business organizations and utilities, filed a petition for writ of mandate with the Court of Appeal of the State of California. CARES is sponsored by the California Business Roundtable, the California Chamber of Commerce, San Diego Gas & Electric Company, the California Manufacturers Association, Pacific Gas & Electric Company, the California Retailers Association, and SCE, among other groups. The CARES petition challenged Proposition 9 as illegal and unconstitutional on its face, and sought to remove the initiative from the November 1998 ballot. On July 2, 1998, the Court of Appeal denied the CARES petition. On July 6, 1998, CARES filed its appeal of the denial with the California Supreme Court. On July 15, 1998, the California Supreme Court denied the CARES petition. In these rulings, the Court of Appeal of the State of California and the California Supreme Court both decided, in effect, not to consider the legality and constitutionality of Proposition 9 prior to the November 1998 election. 22
If Proposition 9 is voted into law, further litigation would ensue. Under the terms of a servicing agreement relating to the rate reduction notes, SCE (acting as the servicer) is required to take such legal or administrative actions as may be reasonably necessary to block or overturn any attempts to cause a repeal of, modification of, or supplement to the Statute, the financing order issued by the CPUC, or the rights of holders of the property right authorized by the Statute and the financing order by legislative enactment, voter initiative or constitutional amendment that would be adverse to holders of the rate reduction notes. The costs of such actions would be payable out of collections of the non-bypassable charges established by the financing order and the related issuance advice letter as an operating expense related to the rate reduction notes. However, SCE may be required to advance its own funds to satisfy its obligations as servicer to take such legal and administrative actions. SCE is unable to predict the outcome of this matter, but if Proposition 9 were to be voted into law, and not immediately stayed and ultimately invalidated by the courts, it could have a material adverse effect on SCE's results of operation and financial position. Upon voter approval of Proposition 9, a write-down of a portion of SCE's generation-related assets might be required under applicable accounting principles, depending on SCE's assessment of both the probability that Proposition 9 would be struck down by the courts and the manner in which it would be interpreted and applied to SCE. The meaning of many provisions of Proposition 9 is unclear and, if the courts uphold it in whole or part, will be subject to judicial and regulatory interpretation. Depending on how Proposition 9 is interpreted and implemented with respect to SCE, the potential write-down of SCE's generation-related assets could amount to as much as $1.9 billion after tax. Additionally, if Proposition 9 passes and survives legal challenges, SCE could suffer impacts on its annual earnings, including the possibility of being required to offset customer charges necessary to pay the principal and interest on the rate reduction notes. Depending on how this provision and other provisions of Proposition 9 are interpreted and applied, the annual earnings reductions could be as large as $210 million in 1999, gradually declining to as much as $10 million in 2007, and immaterial amounts thereafter. 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 the liability quarterly, by assessing a range of reasonably likely costs for each identified site. Unless there is a probable amount, Edison International records the lower end of this 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 41% of its recorded liability. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $246 million. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. SCE has sold all of its gas- and oil-fueled power plants and has retained some liability associated with the divested properties. The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $91 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 $148 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. 23
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 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 environmental capital expenditures 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. 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 24
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 1, 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. In June 1998, a new accounting standard for derivative instruments and hedging activities was issued. The new standard, which will be effective January 1, 2000, requires all derivatives to be recognized on the balance sheet at fair value. Gains or losses from changes in fair value would be recognized in earnings in the period of change unless the derivative is designated as a hedging instrument. Gains or losses from hedges of a forecasted transaction or foreign currency exposure would be reflected in other comprehensive income. Gains or losses from hedges of a recognized asset or liability or a firm commitment would be reflected in earnings for the ineffective portion of the hedge. SCE anticipates that most of its derivatives under the new standard would qualify for hedge accounting. SCE expects to recover in rates any market price changes from its derivatives that could potentially affect earnings. Edison International is studying the impact of the new standard on its nonutility subsidiaries, and is unable to predict at this time the impact on its financial statements. Year 2000 Issue Many of Edison International'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 a comprehensive program in place to remediate potential Year 2000 impacts. SCE divides its Year 2000 Issue activities into five phases: inventory, impact assessment, remediation, testing and implementation. SCE's plan for critical systems is to be 75% complete by year-end 1998, and 100% complete by July 1999. A critical system is defined as those applications and systems, including embedded processor technology, which if not appropriately remediated, may have a significant impact on customers, the revenue stream, regulatory compliance, or the health and safety of personnel. The scope of this program includes three categories: mainframe computing, distributed computing and physical assets (also known as embedded processors). For mainframe financial systems, Year 2000 remediation was completed in the fourth quarter of 1997. Remediation for the material management system was completed in the second quarter of 1998. The customer information and billing system is scheduled to be replaced by the first quarter of 1999 with a system designed to be Year 2000-ready. Distributed computing assets include operations and business information systems. The critical operations information systems include outage management, power management, and plant monitoring and access retrieval systems. Business information systems include a data acquisition system for billing, the computer call center support system, credit support and maintenance management. SCE is on 25
schedule to have its mainframe and distributed computing assets Year 2000-ready within the timeframe discussed above. The physical asset portfolio includes systems in the generation, transmission, distribution, telecommunications and facilities areas. SCE has completed its inventory of these systems and impact assessment for critical physical assets is nearly complete. The other essential component of the SCE Year 2000 readiness program is to identify and assess vendor products and business partners for Year 2000 readiness. SCE has a process in place to identify and contact vendors and business partners to determine their Year 2000 status, and is evaluating the responses. SCE's general policy requires that all newly purchased products be Year 2000-ready or otherwise designed to allow SCE to determine whether such products present Year 2000 issues. SCE is also working to address Year 2000 issues related to all ISO and PX interfaces. Preliminary estimates of the costs to complete these modifications, including the cost of new hardware and software application modification, range from $55 million to $80 million, about half of which are expected to be capital costs. SCE expects current rate levels for providing electric service to be sufficient to provide funding for these modifications. Although SCE is confident that its critical systems will be fully remediated prior to year-end 1999, SCE believes that prudent business practices call for the development of contingency plans. Such contingency plans shall include developing strategies for dealing with Year 2000-related processing failures or malfunctions due to SCE's internal systems or from external parties. SCE's contingency plans are expected to be completed by March 1999; therefore, these risk factors are not yet fully known, and SCE's reasonably likely worst case scenario also is unknown at this time. Edison International does not expect the Year 2000 issue to have a material adverse effect on its results of operation or financial position; however, if not effectively remediated, negative effects from Year 2000 issues, including those related to internal systems, vendors, business partners, the ISO, the PX or customers, could cause results to differ. Edison Mission Energy is continuing its Year 2000 Issue review at its power projects and does not anticipate material expenditures to resolve this 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; the effects of the Year 2000 Issue; the passage and implementation of California Proposition 9; and other unforeseen events. 26
PART II -- OTHER INFORMATION Item 1. Legal Proceedings Edison International Tradename Litigation As previously reported in Part II, Item 1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, 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 As previously reported in Part II, Item 1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, 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. PMNC subsequently attached three checking accounts in the approximate amount of $500,000. 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. Southern California Edison Company Wind Generators' Litigation As previously reported in Part II, Item 1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, 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 ("Los Angeles County") and one was filed in Kern County Superior Court ("Kern County"). The lawsuits alleged 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 sought declaratory relief regarding the proper interpretation of the contracts. Plaintiffs alleged a combined total of approximately $189 million in damages, which included consequential damages claimed in seven of the eight lawsuits. Following the March 1 ruling, a ninth lawsuit was filed in Los Angeles County 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. 27
After receiving a favorable decision in the liability phase of the lead case, SCE agreed to settle with the plaintiffs in seven of the lawsuits on terms whereby SCE waived 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 also entered into a settlement agreement with the plaintiff in another of the lawsuits which resolved the issue of multiple fixed price periods on the same terms and which also resolved a related issue unique to that plaintiff in exchange for a nominal payment by SCE. This settlement was 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 As previously reported in Part II, Item 1 of the Registrant's quarterly Report on Form 10-Q for the quarter ended March 31, 1998, on June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court against an independent power producer of geothermal generation and six of its affiliated entities (collectively the "Coso Defendants"). SCE alleges that in order to avoid power production plant shutdowns caused by excessive noncondensable gas in the geothermal field brine, the Coso 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 Coso Defendants of their obligations under their contracts and applicable law. The complaint sought termination of the contracts and damages for excess power purchase payments made to the Coso Defendants. The Coso Defendants' motion to transfer venue to Inyo County Superior Court was granted on August 31, 1997. On December 19, 1997, SCE filed a first amended complaint in response to which the Coso Defendants filed a motion to strike the termination remedy sought by SCE. This motion was granted on June 1, 1998. The Coso 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 Coso Defendants and two of SCE's affiliates, Mission Power Engineering, and The Mission Group (the Mission Parties). The court denied the Coso Defendants' motion for summary judgment by order dated July 8, 1998. In addition, the Coso Defendants 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. On April 30, 1998, the court denied the motion for stay without prejudice. The Coso 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 Coso Defendants in Inyo County Superior Court. Following a hearing on November 20, 1997, the court consolidated these actions for all purposes and ordered the Coso Defendants to file a second amended cross-complaint, incorporating all but two of the claims in the separate 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 $115 million in compensatory damages and also punitive damages. 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, as well as a motion to strike, certain portions of the second amended cross-complaint which was argued on March 13, 1998. On May 22, 1998, the court granted SCE's motion to strike and sustained the demurrer with leave to amend. The Coso Defendants subsequently filed a motion for leave to file a third amended cross-complaint which was argued and taken under submission on July 9, 1998. 28
Electric and Magnetic Fields (EMF) Litigation As previously reported in Part II, Item 1 of the Registrant's quarterly Report on Form 10-Q for the quarter ended March 31, 1998, 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. In December 1995, the court granted SCE's motion for summary judgment in the first lawsuit and dismissed the case. Plaintiffs have filed a Notice of Appeal. Briefs have been submitted but no date for oral argument has been set. The second lawsuit has been dismissed by the plaintiffs. However, one of the named plaintiffs is now deceased and a wrongful death action was filed by her husband and children on May 7, 1998 and has been served on SCE. On July 23, 1998, the court granted SCE's motion for summary judgment in the third lawsuit and dismissed this case. A California Court of Appeal decision, Cynthia Jill Ford et al. v. Pacific Gas & 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 the remaining cases in light of the Court of Appeal's decision. San Onofre Personal Injury Litigation As previously reported in Part II, Item 1 of the Registrant's quarterly Report on Form 10-Q for the quarter ended March 31, 1998, SCE is involved in six lawsuits alleging personal injuries relating to San Onofre. 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 In the first lawsuit. 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 appealed this ruling to the Ninth Circuit Court of Appeals. On May 28, 1998, the Ninth Circuit Court affirmed the lower court's judgment in favor of SCE. 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 in a second lawsuit. Plaintiffs also named Combustion Engineering and the Institute of Nuclear Power Operations as defendants. 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 appealed this ruling to the Ninth Circuit Court of Appeals. On May 28, 1998, the Ninth Circuit Court affirmed the lower court's judgment in favor of SCE. 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 in the third lawsuit. Plaintiffs also named Combustion Engineering and the Institute of Nuclear Power Operations as defendants. All trial court proceedings have been stayed pending the ruling of the Court of Appeals, recently issued by the Ninth Circuit on May 28, 1998 affirming the lower court's judgment in favor of SCE, in the cases described in the above two paragraphs. A trial date has not yet been set. On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District Court for the Southern District of California in the fourth lawsuit. Plaintiffs also named Combustion Engineering. The trial in this case took place over approximately 22 days between January and March 1998 and resulted in 29
a jury verdict for both defendants. On March 19, 1998, the plaintiffs filed a motion for a new trial. That motion was denied on June 9, 1998. On July 6, 1998, plaintiffs filed a notice of appeal stating that they will appeal the trial court's judgment to the Ninth Circuit Court of Appeals. 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 in the fifth lawsuit. Plaintiffs also named Combustion Engineering. On August 12, 1996, the Court dismissed the claims of the former worker and her husband with prejudice. This case, with only the son as plaintiff, is expected to go to trial in late 1998 or early 1999. 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 in the sixth lawsuit. The case was 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. On May 11, 1998, the plaintiffs filed a first amended complaint. On May 22, 1998, SCE filed an answer denying the material allegations of the first amended complaint. False Claims Act Litigation As previously reported in Part II, Item 1 of the Registrant's quarterly Report on Form 10-Q for the quarter ended March 31, 1998, in September 1997, SCE became aware of a complaint filed in the Southern District of the U.S. District Court of California by a former San Onofre employee, acting at his own initiative on behalf of the United States under the False Claims Act, against SCE and SDG&E. SCE and SDG&E filed separate motions to dismiss this lawsuit on November 6, 1997. The former employee responded to both motions on December 20, 1997. SCE and SDG&E replied to the former employee's responses on January 13, 1998. Oral argument on the motion to dismiss was heard on January 20, 1998. On July 1, 1998, the U.S. District Court granted SCE's motion to dismiss. The court found that the filed rate doctrine barred the former employee's federal claims, but declined to rule on whether the state law claims would be likewise barred. Instead, the court declined to exercise jurisdiction over the state law claims in the wake of the dismissal of the federal claims. Mohave Generating Station Environmental Litigation As previously reported in Part II, Item 1 of the Registrant's quarterly Report on Form 10-Q for the quarter ended March 31, 1998, on February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit in the U.S. District Court of Nevada against SCE, which operates Mohave, and the other three co-owners of the Mohave Generating Station. 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, a motion to dismiss was filed. The plaintiffs filed an opposition to the motion to dismiss and a motion for partial summary judgment on May 8, 1998. On May 29, 1998, SCE and the co-owners filed their reply brief to the plaintiffs' opposition. On June 15, 1998, the plaintiffs filed their final reply brief. SCE and the co-owners filed their final reply to plaintiffs' opposition on June 25, 1998. The initial ruling by the court on these motions is expected in early fall. In addition, on June 4, 1998, the plaintiffs served SCE and its co-owners with a 60-day supplemental notice of intent to sue. This supplemental notice identified additional causes of action that may be added to the ongoing litigation after August 3, 1998. The new causes of action are expected to be a variation of the existing allegations, and are not expected to raise new substantive issues. The supplemental notice also stated the intent to add the National Parks and Conservation Association as an additional plaintiff to these proceedings. However, it is not expected that this will substantially change the timetable for the court's initial ruling on all the pending motions. 30
California Proposition 9 Litigation In November 1997, individuals representing The Utilities Reform Network, Public Media Center and the Coalition Against Utility Taxes filed a proposed voter initiative that seeks to overturn major portions of the electric industry restructuring legislation enacted in California in September 1996 ("Statute"). The voter initiative proposes, among other things, to: (i) impose an additional 10% rate reduction for residential and small commercial customers beyond the 10% reduction that went into effect on January 1, 1998; (ii) block stranded-cost recovery of nuclear investments; (iii) restrict stranded-cost recovery of non-nuclear investments unless the CPUC finds that the utility would be deprived of the opportunity to earn a fair rate of return; and (iv) prohibit the collection of any charges in connection with a financing order for the purpose of making payments on rate reduction notes, or if the financing order is found enforceable by a court, require the utility to offset such charges with an equal credit to customers. On June 24, 1998, the California Secretary of State announced that the proposed voter initiative qualified for the November 1998 ballot. On July 17, 1998, the Secretary of State designated the initiative as Proposition 9 on the ballot. On May 22, 1998, Californians for Affordable and Reliable Electric Service (CARES), a coalition of California business organizations and utilities (sponsored by the California Business Roundtable, the California Chamber of Commerce, San Diego Gas & Electric Company, the California Manufacturers Association, Pacific Gas & Electric Company, the California Retailers Association, and SCE, among other groups) filed a petition for writ of mandate with the Court of Appeal of the State of California. The CARES petition challenged the voter initiative (later designated as Proposition 9) as illegal and unconstitutional on its face, and sought to remove the initiative from the November 1998 ballot. On July 2, 1998, the Court of Appeal denied the CARES petition. On July 6, 1998, CARES filed its appeal of the denial with the California Supreme Court. On July 15, 1998, the California Supreme Court denied the CARES petition for pre-election review. In these rulings, the Court of Appeal of the State of California and the California Supreme Court both decided, in effect, not to consider the legality and constitutionality of Proposition 9 prior to the November 1998 election. If Proposition 9 is voted into law, further litigation would ensue. Under the terms of a servicing agreement relating to the rate reduction notes, SCE (acting as the servicer) is required to take such legal or administrative actions as may be reasonably necessary to block or overturn any attempts to cause a repeal of, modification of, or supplement to the Statute, the financing order issued by the CPUC, or the rights of holders of the property right authorized by the Statute and the financing order by legislative enactment, voter initiative or constitutional amendment that would be adverse to holders of the rate reduction notes. The costs of such actions would be payable out of collections of the non-bypassable charges established by the financing order and the related issuance advice letter as an operating expense related to the rate reduction notes. However, SCE may be required to advance its own funds to satisfy its obligations as servicer to take such legal and administrative actions. SCE is unable to predict the outcome of this matter, but if Proposition 9 is voted into law, and not immediately stayed and ultimately invalidated by the courts, it could have a material adverse effect on SCE's results of operation and financial position as more specifically described in California Proposition 9 -- November 1998 Voter Initiative in Item 2 of Part 1 of this Form, which is hereby incorporated by reference. 31
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)* 10. Material Contracts 10.1. Equity Compensation Plan 10.2. Retirement Plan for Directors 10.3. Director Deferred Compensation Plan 10.4. Form of Agreement for 1998 Employee Awards under the Equity Compensation Plan 10.5. Form of 1998 Director Award under the Equity Compensation Plan 11. Computation of Primary and Fully Diluted Earnings Per Share 27. Financial Data Schedule 32
(b) Reports on Form 8-K: None - ---------------------- * Incorporated by reference pursuant to Rule 12b-32 . SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EDISON INTERNATIONAL (Registrant) By RICHARD K. BUSHEY ------------------------------------------- RICHARD K. BUSHEY Vice President and Controller By K. S. STEWART ------------------------------------------- K. S. STEWART Assistant General Counsel and Assistant Secretary August 13, 1998