UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) /X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended March 31, 1999 ----------------------------------------------- OR / / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ___________________ to _____________________ Commission File Number 1-9936 EDISON INTERNATIONAL (Exact name of registrant as specified in its charter) CALIFORNIA 95-4137452 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California (Address of principal 91770 executive offices) (Zip Code) (626) 302-2222 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Class Outstanding at May 11, 1999 - ------------------------------------- ----------------------------------- Common Stock, no par value 347,207,106
EDISON INTERNATIONAL INDEX ----- Page No. ---- Part I. Financial Information: Item 1. Consolidated Financial Statements: Consolidated Statements of Income -- Three Months Ended March 31, 1999, and 1998 1 Consolidated Statements of Comprehensive Income -- Three Months Ended March 31, 1999, and 1998 1 Consolidated Balance Sheets -- March 31, 1999, and December 31, 1998 2 Consolidated Statements of Cash Flows -- Three Months Ended March 31, 1999, and 1998 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition 9 Part II. Other Information: Item 1. Legal Proceedings 23 Item 4. Submission of Matters to a Vote of Security Holders 26 Item 6. Exhibits and Reports on Form 8-K 27
EDISON INTERNATIONAL PART I -- FINANCIAL INFORMATION Item 1. Consolidated Financial Statements CONSOLIDATED STATEMENTS OF INCOME In thousands, except per-share amounts <TABLE> <CAPTION> 3 Months Ended March 31, - ---------------------------------------------------------------------- ------------------------------------------- 1999 1998 - ------------------------------------------------------------------------------------------------------------------ (Unaudited) - ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> Electric utility revenue $1,676,658 $1,622,689 Diversified operations 411,063 286,871 - ------------------------------------------------------------------------------------------------------------------ Total operating revenue 2,087,721 1,909,560 - ------------------------------------------------------------------------------------------------------------------ Fuel 114,383 167,321 Purchased power-- contracts 609,906 576,506 Purchased power-- power exchange-- net 116,956 -- Provisions for regulatory adjustment clauses-- net (279,030) (303,813) Other operating expenses 576,764 387,174 Maintenance 88,945 101,969 Depreciation, decommissioning and amortization 423,640 411,320 Income taxes 85,528 136,719 Property and other taxes 39,092 40,762 Net loss (gain) on sale of utility plant (2,200) 65,801 - ------------------------------------------------------------------------------------------------------------------ Total operating expenses 1,773,984 1,583,759 - ------------------------------------------------------------------------------------------------------------------ Operating income 313,737 325,801 - ------------------------------------------------------------------------------------------------------------------ Allowance for equity funds used during construction 2,836 2,781 Interest and dividend income 20,369 30,716 Minority interest (962) (1,508) Other nonoperating deductions-- net (8,580) (9,199) - ------------------------------------------------------------------------------------------------------------------ Total other income-- net 13,663 22,790 - ------------------------------------------------------------------------------------------------------------------ Income before interest and other expenses 327,400 348,591 - ------------------------------------------------------------------------------------------------------------------ Interest and amortization on long-term debt 151,821 179,109 Other interest expense 36,115 21,213 Allowance for borrowed funds used during construction (2,461) (1,892) Capitalized interest (10,718) (3,905) Dividends on subsidiary preferred securities 9,432 10,056 - ------------------------------------------------------------------------------------------------------------------ Total interest and other expenses-- net 184,189 204,581 - ------------------------------------------------------------------------------------------------------------------ Net income $ 143,211 $ 144,010 - ------------------------------------------------------------------------------------------------------------------ Weighted-average shares of common stock outstanding 348,327 370,279 Basic earnings per share $0.41 $0.39 Weighted average shares, including effect of dilutive securities 353,900 373,340 Diluted earnings per share $0.40 $0.38 Dividends declared per common share $0.27 $0.26 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME In thousands 3 Months Ended March 31, - ------------------------------------------------------------------------ ----------------------------------------- 1999 1998 - ------------------------------------------------------------------------ ----------------------------------------- (Unaudited) Net income $ 143,211 $ 144,010 Cumulative translation adjustments-- net (12,638) 8,318 Unrealized gain (loss) on securities-- net (9,146) 14,014 Reclassification adjustment for gains included in net income (17,371) -- - ------------------------------------------------------------------------------------------------------------------ Comprehensive income $ 104,056 $ 166,342 - ------------------------------------------------------------------------------------------------------------------ </TABLE> The accompanying notes are an integral part of these financial statements. 1
EDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS In thousands <TABLE> <CAPTION> March 31, December 31, 1999 1998 - ------------------------------------------------------------------------------------------------------------------ (Unaudited) ASSETS Transmission and distribution: Utility plant, at original cost, subject to <S> <C> <C> cost-based rate regulation $11,901,873 $11,771,678 Accumulated provision for depreciation (6,280,719) (6,062,562) Construction work in progress 554,209 455,233 - ------------------------------------------------------------------------------------------------------------------ 6,175,363 6,164,349 - ------------------------------------------------------------------------------------------------------------------ Generation: Utility plant, at original cost, not subject to cost-based rate regulation 1,692,358 1,689,469 Accumulated provision for depreciation, decommissioning and amortization (848,315) (833,917) Construction work in progress 74,993 61,431 Nuclear fuel, at amortized cost 164,489 172,250 - ------------------------------------------------------------------------------------------------------------------ 1,083,525 1,089,233 - ------------------------------------------------------------------------------------------------------------------ Total utility plant 7,258,888 7,253,582 - ------------------------------------------------------------------------------------------------------------------ Nonutility property -- less accumulated provision for depreciation of $303,910 and $296,732 at respective dates 4,889,503 3,072,354 Nuclear decommissioning trusts 2,311,082 2,239,929 Investments in partnerships and unconsolidated subsidiaries 1,623,817 1,615,106 Investments in leveraged leases 1,678,192 1,621,133 Other investments 228,727 572,856 - ------------------------------------------------------------------------------------------------------------------ Total other property and investments 10,731,321 9,121,378 - ----------------------------------------------------------------------------------------------------------------- Cash and equivalents 610,635 583,556 Receivables, including unbilled revenue, less allowances of $27,917 and $24,272 for uncollectible accounts at respective dates 1,282,475 1,315,830 Fuel inventory 70,275 51,299 Materials and supplies, at average cost 143,577 116,259 Accumulated deferred income taxes-- net 89,853 274,851 Regulatory balancing accounts-- net 974,190 648,781 Prepayments and other current assets 95,574 137,920 - ------------------------------------------------------------------------------------------------------------------ Total current assets 3,266,579 3,128,496 - ------------------------------------------------------------------------------------------------------------------ Unamortized nuclear investment-- net 1,962,973 2,161,998 Income tax-related deferred charges 1,502,897 1,463,256 Unamortized debt issuance and reacquisition expense 341,702 348,816 Other deferred charges 1,703,269 1,220,353 - ------------------------------------------------------------------------------------------------------------------ Total deferred charges 5,510,841 5,194,423 - ------------------------------------------------------------------------------------------------------------------ Total assets $26,767,629 $24,697,879 - ------------------------------------------------------------------------------------------------------------------ </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> March 31, December 31, 1999 1998 - ------------------------------------------------------------------------------------------------------------------ (Unaudited) CAPITALIZATION AND LIABILITIES Common shareholders' equity: Common stock (347,202,697 and 350,553,197 <S> <C> <C> shares outstanding at respective dates) $ 2,089,119 $ 2,109,279 Accumulated other comprehensive income: Cumulative translation adjustments-- net 17,061 29,699 Unrealized gain in equity securities-- net 27,342 53,859 Retained earnings 2,882,656 2,906,432 - ------------------------------------------------------------------------------------------------------------------ 5,016,178 5,099,269 - ------------------------------------------------------------------------------------------------------------------ Preferred securities of subsidiaries: Not subject to mandatory redemption 128,755 128,755 Subject to mandatory redemption 405,700 405,700 Long-term debt 7,823,187 8,008,154 - ------------------------------------------------------------------------------------------------------------------ Total capitalization 13,373,820 13,641,878 - ------------------------------------------------------------------------------------------------------------------ Other long-term liabilities 713,510 467,109 - ------------------------------------------------------------------------------------------------------------------ Current portion of long-term debt 1,188,764 920,333 Short-term debt 2,299,519 565,626 Accounts payable 393,337 489,751 Accrued taxes 575,026 629,906 Accrued interest 136,403 146,773 Dividends payable 94,343 91,742 Deferred unbilled revenue and other current liabilities 1,608,823 1,442,149 - ------------------------------------------------------------------------------------------------------------------ Total current liabilities 6,296,215 4,286,280 - ------------------------------------------------------------------------------------------------------------------ Accumulated deferred income taxes-- net 4,621,049 4,591,236 Accumulated deferred investment tax credits 259,645 270,689 Customer advances and other deferred credits 1,488,498 1,424,986 - ------------------------------------------------------------------------------------------------------------------ Total deferred credits 6,369,192 6,286,911 - ------------------------------------------------------------------------------------------------------------------ Minority interest 14,892 15,701 - ------------------------------------------------------------------------------------------------------------------ Commitments and contingencies (Notes 1 and 2) Total capitalization and liabilities $26,767,629 $24,697,879 - ------------------------------------------------------------------------------------------------------------------ </TABLE> The accompanying notes are an integral part of these financial statements. 3
EDISON INTERNATIONAL CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands <TABLE> <CAPTION> 3 Months Ended March 31, - ------------------------------------------------------------------------------------------------------------------ 1999 1998 - ------------------------------------------------------------------------------------------------------------------ (Unaudited) Cash flows from operating activities: <S> <C> <C> Net income $ 143,211 $ 144,010 Adjustments for non-cash items: Depreciation, decommissioning and amortization 423,640 411,320 Other amortization 20,689 15,066 Rate phase-in plan -- 3,777 Deferred income taxes and investment tax credits 144,279 218,045 Equity in income from partnerships and unconsolidated subsidiaries (64,441) (23,086) Income from leveraged leases (57,564) (36,382) Other long-term liabilities 52,523 14,733 Regulatory asset related to the sale of oil and gas plant 241 (98,041) Net loss (gain) on sale of oil and gas plant (1,124) 62,633 Other-- net (13,733) (22,323) Changes in working capital: Receivables 53,194 175,876 Regulatory balancing accounts (325,409) (301,767) Fuel inventory, materials and supplies (4,252) 6,297 Prepayments and other current assets 47,642 39,579 Accrued interest and taxes (34,770) (45,390) Accounts payable and other current liabilities 57,173 (108,661) Distributions from partnerships and unconsolidated subsidiaries 29,099 37,539 - ------------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities 470,398 493,225 - ------------------------------------------------------------------------------------------------------------------ Cash flows from financing activities: Long-term debt issued 234,878 521,032 Long-term debt repaid (43,705) (669,812) Rate reduction notes repaid (70,531) (17,111) Common stock repurchased (92,023) (263,315) Nuclear fuel financing-- net (8,836) (8,623) Short-term debt financing-- net 1,704,841 65,455 Dividends paid (91,513) (94,326) Other-- net -- 367 - ------------------------------------------------------------------------------------------------------------------ Net cash provided (used) by financing activities 1,633,111 (466,333) - ------------------------------------------------------------------------------------------------------------------ Cash flows from investing activities: Additions to property and plant (263,308) (198,957) Purchase of nonutility power station (1,800,355) -- Proceeds from sale of oil and gas plant 13,819 33,901 Funding of nuclear decommissioning trusts (37,126) (39,683) Investments in partnerships and unconsolidated subsidiaries (6,241) (44,368) Investment in leveraged leases 466 (336,637) Unrealized gain (loss) on securities-- net (26,517) 14,014 Other-- net 42,832 (1,098) - ------------------------------------------------------------------------------------------------------------------ Net cash used by investing activities (2,076,430) (572,828) - ------------------------------------------------------------------------------------------------------------------ Net increase (decrease) in cash and equivalents 27,079 (545,936) Cash and equivalents, beginning of period 583,556 1,906,505 - ------------------------------------------------------------------------------------------------------------------ Cash and equivalents, end of period $ 610,635 $ 1,360,569 - ------------------------------------------------------------------------------------------------------------------ </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 1998 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 1998 Annual Report and Form 10-K filed with the Securities and Exchange Commission. Certain prior-period amounts were reclassified to conform to the March 31, 1999, financial statement presentation. Since April 1, 1998, when the new market structure began, SCE has been selling all of its generation through the power exchange (PX), as mandated by the California Public Utilities Commission's (CPUC) 1995 restructuring decision. Through the PX, SCE satisfies the electric energy needs of customers who did not choose an alternative energy provider. These transactions with the PX are reported as Purchased power - power exchange - net. Generation sales through the PX were $282 million and $1.7 billion for the three and twelve months ended March 31, 1999, respectively. Purchases from the PX were $399 million and $2.4 billion for the three and twelve months ended March 31, 1999, respectively. Note 1. Regulatory Matters Recovery of Restructuring Implementation Costs The independent system operator (ISO) assumed operational control of the transmission system after the ISO and PX had begun accepting bids and schedules for electricity purchases on March 31, 1998. The restructuring implementation costs related to the start-up and development of the PX, which were paid by the utilities, were to 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. In May 1998, SCE filed an application with the CPUC to identify the categories of such costs (including costs related to the implementation of direct access), and to establish the reasonableness of those costs incurred in 1997. The CPUC split the application into two phases. Two proposed decisions Phase 1, which addressed the eligibility of the implementation costs, were issued on March 11, 1999. Both of these proposed decisions reject SCE's request for a determination of eligibility for several major categories of such costs. These proposed decisions further state that even for the cost categories they approve for eligibility, costs incurred in those categories after December 31, 1998, would not be eligible. Instead, these proposed decisions would have SCE recover many of the costs identified in its application from market revenue, although the decisions fail to identify the market and no specific mechanism or authority to recover such costs from any market has yet been established. SCE disagrees with much of the conclusions reached in these proposed decisions and has filed comments to that effect with the CPUC. A final CPUC decision is expected later this year. Under both of the proposed decisions, the reasonableness of 1997 and 1998 expenditures for eligible restructuring costs would be addressed in a separate application later this year. 5
Note 2. Contingencies In addition to the matters disclosed in these notes, Edison International is involved in legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these proceedings will not materially affect its results of operations or liquidity. 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 49 identified sites is $169 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 $285 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 generation 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 $87 million of its 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; and 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 $137 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. Recorded costs for the twelve-month period ended March 31, 1999 were $9 million. 6
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 $9.8 billion. SCE and other owners of the San Onofre and Palo Verde nuclear plants 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 $88 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 $175 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 also has 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 $22 million per year. Insurance premiums are charged to operating expense. Spent Nuclear Fuel Federal law requires the Department of Energy (DOE) to select and develop repositories for, and oversee disposal of, spent nuclear fuel and high-level radioactive waste. The law requires the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from nuclear generation stations beginning January 31, 1998. However, the DOE did not meet its obligation. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or from other nuclear power plants. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983, (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to one mill per kilowatt-hour of nuclear-generated electricity sold after April 6, 1983. SCE has primary responsibility for the interim storage of its spent nuclear fuel at San Onofre. Current capability to store spent fuel is estimated to be adequate through 2005. Meeting spent-fuel storage requirements beyond that period could require new and separate interim storage facilities, the costs for which have not been determined. Extended delays by the DOE could lead to consideration of costly alternatives involving siting and environmental issues. 7
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2002 for Units 1 and 2, and until 2003 for Unit 3. Arizona Public Service Company, operating agent for Palo Verde, is constructing an interim fuel storage facility that is expected to be completed in 2002. SCE and other owners of nuclear power plants may be able to recover interim storage costs arising from DOE delays in the acceptance of utility spent nuclear fuel by pursuing relief under the terms of the contracts, as directed by the courts, or through other court actions. 8
EDISON INTERNATIONAL Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition RESULTS OF OPERATIONS First Quarter 1999 vs. First Quarter 1998 Earnings Edison International's basic earnings per share were 41(cent) per share for the first quarter of 1999, compared to 39(cent) for the first quarter of 1998. Southern California Edison's (SCE) earnings were 22(cent) per share, compared to 27(cent) for the first quarter of 1998. The decrease in SCE's earnings was mainly due to the scheduled refueling outage at San Onofre Nuclear Generating Station Unit 2. Edison Mission Energy (EME) and Edison Capital had combined earnings of 24(cent) per share, compared to 15(cent) in 1998. The increase was primarily due to infrastructure investments and the closing of two affordable housing syndications at Edison Capital, as well as higher earnings from existing energy projects at EME. Edison Enterprises (Edison Source, Edison Select and Edison Utility Services) and the Edison International parent company had combined net expenses of 5(cent) in 1999, compared with 3(cent) in 1998. The negative impact on earnings was primarily due to continued investment in Edison Enterprises' subsidiaries. Operating Revenue Electric utility revenue increased 3% during the first quarter of 1999, compared with the same period in 1998, due to a 3% increase in the retail sales volume of commercial customers. Over 99% of electric utility revenue was 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). Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is significantly higher than other quarters. Legislation enacted in September 1996 provided for, among other things, 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 Regulatory Environment below. Revenue from diversified operations increased 43% in 1999, primarily due to increases at: Edison Capital, related to additional lease transactions closed in 1998; Edison Enterprises, related to the Westec acquisition in 1998; and EME, related to a pricing settlement on four qualifying facility contracts. Operating Expenses Fuel expense decreased 32%, primarily due to the sale of SCE's gas- and oil-fueled generation plants in 1998. Since April 1, 1998, SCE has been required to sell all of its generated power through the power exchange (PX) and acquire all of its power from the PX to distribute to its retail customers. These transactions with the PX are reported as Purchased power - power exchange - net. SCE is continuing to purchase power from certain nonutility generators (known as qualifying facilities) and under existing contracts with other utilities. This purchased power is sold through the PX. Excluding the transactions with the PX, purchased-power expense increased for the three months ended March 31, 1999, compared to the same period last year, due to higher prices for required purchases from qualifying facilities. SCE is required under federal law to purchase power from certain qualifying facilities even though energy prices under these contracts are generally higher than other sources. For the twelve months ended March 31, 1999, SCE paid about $1.5 9
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 primarily due to overcollections related to the difference between generation-related revenue and generation-related costs. These overcollections were almost completely offset by undercollections related to the rate-making treatment of the rate reduction notes and the administration of public-purpose funds. This rate-making treatment has allowed for the deferral of the recovery of a portion of the transition-related costs, from a four-year period to a 10-year period. Other operating expenses increased 49%, primarily due to must-run reliability services, direct access activities, and PX and independent system operator (ISO) costs incurred by SCE. Also, other operating expenses increased at Edison Enterprises, related to the Westec acquisition in 1998; at EME, related to higher project development/acquisition costs; and at Edison Capital, related to additional reserves for two affordable housing syndications. Maintenance expense decreased 13%, mainly due to lower expenses incurred at SCE's distribution facilities. Income taxes decreased 37%, primarily due to lower pre-tax income, as well as additional amortization at SCE related to the competition transition charge (CTC) mechanism. Net loss (gain) on sale of utility plant increased due to the loss on sale of one plant at SCE during first quarter 1998. Gains were used to reduce SCE's stranded costs. Losses will be recovered from SCE's customers over the transition period. Other Income and Deductions Interest and dividend income decreased 34%, reflecting lower investment balances at SCE during the first quarter of 1999, as well as slightly lower interest rates. Also, contributing to the decrease were lower international and domestic cash balances at EME. Other nonoperating deductions for first quarter 1999 included the write-off of start-up costs at EME partially offset by the gains on sales of equity investments at SCE. EME was required to write off these previously capitalized start-up costs due to an accounting rule which became effective in January 1999. Other nonoperating deductions for first quarter 1998 included regulatory accruals at SCE. Interest and Other Expenses Interest and amortization on long-term debt decreased 15% for the quarter ended March 31, 1999, compared to the same period in 1998, mainly due to an adjustment of accrued interest at SCE in first quarter 1998 related to the rate reduction notes issued in December 1997, and the maturity of $320 million of debt in the second half of 1998. Interest on the rate reduction notes was $35 million for the quarter ended March 31, 1999, compared to $38 million for the same period last year. Other interest expense increased substantially mostly due to higher short-term debt levels at SCE arising from an additional dividend payment to Edison International during the first quarter of 1999, as well as higher short-term debt levels at EME related to the recently completed Homer City acquisition. Capitalized interest increased due to EME's increased investment in its Paiton and EcoElectrica projects. Financial Condition Edison International's liquidity is primarily affected by debt maturities, dividend payments, capital expenditures, and investments in partnerships and unconsolidated subsidiaries. Capital resources include cash from operations and external financings. 10
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 repurchased approximately 101 million shares ($2.4 billion) between January 1995 and March 31, 1999, funded by dividends from its subsidiaries and the issuance of the rate reduction notes. On March 18, 1999, Edison International increased its quarterly common stock dividend from $1.04 to $1.08, a 3.8% increase. For the first quarter of 1999, Edison International's cash flow coverage of dividends was 5.1 times compared to 5.2 times for the year-earlier period. Edison International's dividend payout ratio for the twelve-month period ended March 31, 1999, was 55%. Cash Flows from Operating Activities Net cash provided by operating activities totaled $470 million in the first quarter of 1999, compared to $493 million in the first quarter of 1998. Cash from operations exceeded capital requirements for both periods presented. Cash Flows from Financing Activities At March 31, 1999, 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 $800 million for general purpose short-term debt and $500 million for the long-term refinancing of its variable-rate pollution-control bonds. The parent company had total lines of credit of $500 million, with $400 million available. The nonutility companies had total lines of credit of $800 million, with $500 million available to finance general cash requirements. These unsecured lines of credit are at negotiated or bank index rates with various expiration dates. SCE's short-term debt is used to finance fuel inventories 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 March 31, 1999, SCE could issue approximately $12.6 billion of additional first and refunding mortgage bonds and $3.8 billion of preferred stock at current interest and dividend rates. EME has firm commitments of $234 million to make equity and other contributions, primarily for the ISAB project in Italy, the Paiton project in Indonesia, the EcoElectrica project in Puerto Rico, the Tri Energy project in Thailand, and the Doga project in Turkey. EME also has contingent obligations to make additional contributions of $206 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. Edison Capital has firm commitments of $272 million to fund affordable housing, and energy and infrastructure investments. California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At March 31, 1999, SCE had the capacity to pay $700 million in additional dividends and continue to maintain its authorized capital structure. These restrictions are not expected to affect Edison International's ability to meet its cash obligations. In December 1997, SCE Funding LLC, a special purpose entity, 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 11
(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 SCE Funding LLC 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. In spite of the legal sale of the transition property by SCE to SCE Funding LLC, the amounts reflected as assets on SCE's balance sheet have not been reduced by the amount of the transition property sold to SCE Funding LLC, and the liabilities of SCE Funding LLC for the rate reduction notes are for accounting purposes reflected as long-term liabilities on the consolidated balance sheets of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities. The outstanding rate reduction notes have maturities ranging from one to nine years, and bear interest at rates ranging from 6.14% to 6.42%. The rate reduction notes are secured solely by the transition property and certain other assets of SCE Funding LLC, and there is no recourse to SCE or Edison International. Although SCE Funding LLC is consolidated with SCE in the financial statements, as required by generally accepted accounting principles, SCE Funding LLC is legally separate from SCE, the assets of SCE Funding LLC are not available to creditors of SCE or Edison International, and the transition property is legally not an asset of SCE or Edison International. Cash Flows from Investing Activities Cash flows from investing activities are affected by additions to property and plant, the nonutility companies' investments in partnerships and unconsolidated subsidiaries, proceeds from the sale of assets (see discussion in Regulatory Environment below), 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 $8.6 billion through 2060 to decommission its nuclear facilities. This estimate is based on SCE's current-dollar decommissioning costs ($1.9 billion), escalated at rates ranging from 0.3% to 10.0% (depending on the cost element) annually. These costs are expected to be funded from independent decommissioning trusts, which currently receive SCE contributions of approximately $100 million per year. However, SCE has requested the CPUC to authorize a reduction in the annual contributions to the decommissioning trusts beginning in 2000. The plan to begin decommissioning San Onofre Unit 1 in 2000, which is pending CPUC approval, is not expected to affect SCE's annual contributions to the decommissioning trusts. Cash used for the nonutility subsidiaries' investing activities was $1.8 billion for the three-month period ended March 31, 1999, compared to $375 million for the same period in 1998. The increase is primarily due to EME's purchase of the Homer City Generating Station (further discussed under EME Acquisitions below). 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. As a result of the rate freeze established in the restructuring legislation, SCE's transition costs are recovered as the residual component of rates once the costs for distribution, transmission, public purpose programs, nuclear decommissioning and the cost of supplying power to its customers through the PX and ISO have already been recovered. Accordingly, more revenue will be available to cover transition costs when market prices in the PX and ISO are low than when PX and ISO prices are high. The PX and ISO market prices to date have generally been reasonable, although some irregular price spikes have occurred. 12
The ISO has responded to price spikes in the market for reliability services (referred to as ancillary services) by imposing a price cap of $250/MW on the market for such services until certain actions have been completed to improve the functioning of those markets. Similarly, the ISO currently maintains a cap of $250/MWh on its market for imbalance energy until adequate measures to improve the efficient operation of the market have been implemented. The caps in these markets mitigate the risk of costly price spikes that would reduce the revenue available to SCE to pay transition costs. During the upcoming year, the ISO will be considering raising these price caps, which could increase the risk of high market prices. SCE has entered into hedges against high natural gas prices, since increases in natural gas prices tend to raise the price of electricity purchased from the PX. SCE has also applied to the CPUC for approval to participate in forward purchases, through a PX forward market. Furthermore, SCE has requested permission from the CPUC to begin a pilot demand responsiveness program that would allow customers to be paid to curtail their load during times of very high prices. SCE is seeking approval for these high price mitigation measures prior to mid-1999. 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. Interest expense includes $6 million for both the three month periods ended March 31, 1999, and March 31, 1998, as a result of interest rate swap and collar agreements. 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 on the difference between the price in the contract and the pool price for the element of power under contract. These contracts are sold in various structures. 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. A proposal to replace the current structure of the forward-contracts market and the pool has been made by the Director General of Electricity Supply, at the request of the Minister of Science, Energy and Industry in the United Kingdom. The Minister has recommended that the proposal be implemented by April 2000. Further definition of the proposal will be required before the effects of the changes can be evaluated. Implementation of the proposal may also require legislation. 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, Australia (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 are sold in various structures. 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. 13
EME's electric revenue increased by $23 million for the three months ended March 31, 1999, compared to an increase of $51 million for the same period in 1998, as a result of electricity rate swap agreements. 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 nearing completion. 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 Indonesian Rupiah, with the portion of such payments intended to cover non-Rupiah project costs (including returns to investors) indexed to the Indonesian Rupiah/U.S. dollar exchange rate established at the time of the power purchase agreement in February 1994. The state-owned electricity company's payment obligations are supported by the Indonesian Government. 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. The Indonesian government has arranged to reschedule sovereign debt owed to foreign governments and has entered into discussions about rescheduling sovereign debt owed to private lenders. The state-owned electricity company has announced its intentions to commence discussions with independent power producers to renegotiate the power supply contracts, however, it is not yet known what form the renegotiation may take. The initial meeting on these renegotiations is scheduled during the second quarter of 1999. Any material modifications of the contract could also require a renegotiation of the Paiton project's debt agreement. The impact of any such renegotiations with the state-owned electricity company, the Indonesian government or the project's creditors on EME's expected return on its investment in Paiton is uncertain at this time, however, EME believes that it will ultimately recover its investment in the project. EME continues to monitor the situation closely. Projected Capital Requirements Edison International's projected construction expenditures for the next five years are: 1999-- $930 million; 2000-- $808 million; 2001-- $709 million; 2002-- $671 million; and 2003-- $623 million. Long-term debt maturities and sinking fund requirements for the five twelve-month periods following March 31, 1999, are: 2000 -- $1.2 billion; 2001 - -- $701 million; 2002 -- $535 million; 2003 -- $674 million; and 2004 -- $477 million. Preferred stock redemption requirements for the five twelve-month periods following March 31, 1999, are: 2000 through 2002-- zero; 2003-- $109 million; and 2004-- $9 million. EME Acquisitions In March 1999, EME completed the acquisition of the 1,884-MW Homer City Generating Station for approximately $1.8 billion. Homer City was jointly owned by subsidiaries of GPU, Inc. and New York State 14
Electric & Gas Corporation. The coal-fired facility has the rights to direct, high-voltage interconnections to both the New York Power Pool and the Pennsylvania-New Jersey-Maryland Power Pool. The plant is located near Pittsburgh, Pennsylvania. EME will operate the plant, which is one of the lowest-cost generation facilities in the region. EME financed the acquisition with a combination of debt secured by the project, EME corporate debt, cash and EME corporate revolving debt. The acquisition is expected to have little effect on 1999 earnings and a positive effect on earnings in 2000 and beyond. In March 1999, EME entered into agreements to acquire the fossil-fuel generating assets of Commonwealth Edison Company (ComEd) for approximately $5 billion. The coal-, gas-, and oil-fired generating facilities have a total capacity of 9,772 MW. In conjunction with the acquisition, EME, who will own and operate the facilities, will invest additional capital in the plants to upgrade pollution controls, extend plant life, improve reliability and reduce generation cost. The transaction is expected to close by year-end 1999 and is expected to have an immaterial effect on earnings in 1999, 2000 and 2001, as a result of transition contracts in which ComEd will retain power purchase agreements with EME, enabling ComEd access to certain amounts of plant output for the next five years to serve its customers. Also in March 1999, EME entered into an agreement to acquire a 40% interest in New Zealand government-owned Contact Energy Ltd. for approximately $625 million. The acquisition is conditional on the New Zealand government completing an initial public offering of the remaining 60% interest in Contact Energy. This public offering is planned for May 1999. Contact Energy owns and operates hydroelectric, geothermal and natural gas-fired generating plants in New Zealand with a total generating capacity of 2,371 MW. Contact Energy also supplies gas and electricity to customers in New Zealand and has minority interests in two power projects in Australia. The transaction is expected to close after the completion of the public offering and is expected to have an immaterial effect on earnings through 2001. In April 1999, EME entered into an agreement to acquire two electric generating plants from PowerGen, a United Kingdom (U.K.) utility, for approximately $2 billion. Each of the plants has a generating capacity of about 2,000 MW. EME will also invest $325 million to upgrade the plants' pollution controls, which will make the plants among the lowest emitters of sulfur dioxide and nitrogen oxides of the U.K. coal-fired power plants. The acquisition is expected to receive regulatory approval from the U.K. and close within the next three months. When the acquisition is completed, it is expected to have a positive effect on 1999 earnings. EME plans to finance each of the above acquisitions with debt secured by the project, EME corporate debt, cash and funding from Edison International. Regulatory 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 as a result of a 1995 CPUC decision on restructuring and state legislation enacted in 1996. The Statute substantially adopted the CPUC's 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. 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 mandated other rates to remain frozen at June 1996 levels (system average of 10.1(cent) per kilowatt-hour), including those for large commercial and industrial customers, and included 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 (see detailed discussion below) that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. The new market structure began on April 1, 1998. 15
Revenue and Cost-Recovery Mechanisms In 1999, revenue is being determined by various mechanisms depending on the utility operation. Revenue related to distribution operations is being determined through a performance-based rate-making mechanism (PBR) and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return. The distribution-only PBR will extend through December 2001. Transmission revenue is being determined through FERC-authorized rates and transmission assets earn a 9.43% return. These rates are subject to refund. Key elements of PBR include: transmission and distribution (T&D) rates indexed for inflation based on the Consumer Price Index less a productivity factor; 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. SCE's transition costs 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 1995 restructuring decision date. SCE has estimated its transition costs to be approximately $10.6 billion (1998 net present value) from 1998 through 2030. This estimate was based on incurred costs, forecasts of future costs and assumed market prices. However, changes in the assumed market prices could materially affect these estimates. 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 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 (which reflects the 1998 sale of SCE's gas- and oil-fueled generation plants) from costs pertaining to certain generating assets 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 Nuclear Generating Station units, and certain other costs. During 1998, SCE sold all of its gas- and oil-fueled generation plants for $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. If events occur during the restructuring process that result in all or a portion of the transition costs being improbable of recovery, SCE could have write-offs associated with these costs if they are not recovered through another regulatory mechanism. Revenue from generation-related operations is being determined through the competitive market and the CTC mechanism, which now includes the nuclear rate-making agreements. 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. SCE's costs associated with its hydroelectric plants are being recovered through a performance-based 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. In 1999, fossil and hydroelectric generation assets will earn a 7.22% return. The CPUC authorized revised rate-making plans for SCE's nuclear facilities, which call for the accelerated recovery of the 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. 16
The changes in revenue from the regulatory mechanisms discussed above, excluding the effects of other rate actions, are expected to have an approximately $20 million negative impact on 1999 earnings. The CPUC is considering unbundling SCE's cost of capital by authorizing separate rates of return for generation, transmission, and distribution operations. In May 1998, SCE filed an application on this issue and hearings were completed in October 1998. On April 22, 1999, a proposed decision, which would reduce SCE's return on common equity to 10.6% from the current rate of 11.6%, and an alternate decision which would keep the rate at 11.6%, were issued. If the 10.6% rate is adopted, it would have a negative impact of approximately 7(cent) per share on 1999 earnings. A final CPUC decision is expected in May. Restructuring Implementation Costs The ISO assumed operational control of the transmission system after the ISO and PX had begun accepting bids and schedules for electricity purchases on March 31, 1998. 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. In May 1998, SCE filed an application with the CPUC to identify the categories of such costs (including costs related to the implementation of direct access) and to establish the reasonableness of those costs incurred in 1997. The CPUC split the application into two phases. Two proposed decisions on Phase 1, which addressed the eligibility of the implementation costs, were issued on March 11, 1999. Both of these proposed decisions reject SCE's request for a determination of eligibility for several major categories of such costs. These proposed decisions further state that even for the cost categories they approve for eligibility, costs incurred in those categories after December 31, 1998, would not be eligible. Instead, these proposed decisions would have SCE recover many of the costs identified in its application from market revenue, although the decisions fail to identify the market and no specific mechanism or authority to recover such costs from any market has yet been established. SCE disagrees with much of the conclusions reached in these proposed decisions and has filed comments to that effect with the CPUC. A final CPUC decision is expected later this year. Under both of the proposed decisions, the reasonableness of 1997 and 1998 expenditures for eligible restructuring costs would be addressed in a separate application later this year. Accounting for Generation-Related Assets If the CPUC's electric industry restructuring plan continues as described above, SCE would be allowed to recover its transition costs 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). In 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities based on new accounting guidance. The financial reporting effect of this discontinuance was to segregate these assets on the balance sheet; the new guidance did not require SCE to write off any of its generation-related assets, including related regulatory assets. However, the new guidance did not specifically address the application of asset impairment standards to these assets. SCE has retained these assets on its balance sheet because the Statute 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 new accounting guidance 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 related to the application of asset impairment standards to these assets. Using this guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6 billion (as of June 30, 1998) 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. 17
If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets (approximately $2.7 billion, after tax, at March 31, 1999) as a one-time, non-cash charge against earnings. At this time, SCE cannot predict what other revisions will ultimately be made during the restructuring process in subsequent proceedings or the effect, after the transition period, that competition will have on its results of operations or financial position. Environmental Protection Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. 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 49 identified sites is $169 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 $285 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 $87 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 $137 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 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 18
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 $900 million for the 1999-2003 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 in 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. A favorable or decreasing trend in degradation was observed during inspection in the scheduled refueling outage in January 1999. The results of the January 1999 inspection are being analyzed to determine if there is a need for a mid-cycle inspection outage in early 2000. With the results from the January 1999 outage, 7.5% of the tubes have now been removed from service. In September 1998, San Onofre Unit 2 experienced a small amount of leakage from a steam generator tube plug which required an 11-day outage to repair. 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 were conducted during the scheduled refueling outage in April 1999. These inspections also indicated the erosion has stabilized. A complete inspection of the steam generator tubes was conducted. Results obtained were within expectations. To date, 5.4% 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. New Accounting Rules A recently issued accounting rule requires that costs related to start-up activities be expensed as incurred, effective January 1, 1999. Although this new accounting rule did not materially affect Edison International's results of operations or financial position, EME wrote off approximately $14 million in previously capitalized start-up costs in first quarter 1999. 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 19
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 the existing computer systems at Edison International were originally programmed to represent any date by using six digits (e.g., 12/31/99) rather than eight digits (e.g., 12/31/1999). Accordingly, such programs, if not appropriately addressed, could fail or create erroneous results when attempting to process information containing dates after December 31, 1999. This situation has been referred to generally as the Year 2000 Issue. Edison International has a comprehensive program in place to address potential Year 2000 impacts. Edison International provides overall coordination of this effort, working with its affiliates and their departments. Edison International divides Year 2000 activities into five phases: inventory, impact assessment, remediation, testing and implementation. Edison International's objective for the Year 2000 readiness of critical systems is to be 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 health and safety of the public and/or personnel, the revenue stream, or regulatory compliance. Edison International met its first goal to be 75% complete by year-end 1998 and is on track to meets its July 1999 goal. A system, application or physical asset is deemed to be Year 2000-ready if it is determined by Edison International to be suitable for continued use through 2028 (or through the last year of the anticipated life of the asset, whichever occurs first), even though it may not be fully Year 2000-compliant. A system, application, or physical asset is deemed to be Year 2000-compliant if it accurately processes date/time data. Edison International has structured the scope of the program to focus on three principal categories: mainframe computing, distributed computing and physical assets (also known as embedded processors). The mainframe and distributed computing assets consist of computer application systems (software). Physical assets include information technology infrastructure (hardware, operating system software) and embedded processor technology in generation, transmission, distribution, and facilities components. Year 2000-readiness preparations for SCE's mainframe financial systems were completed in the fourth quarter of 1997, and preparations for SCE's material management system were completed in the second quarter of 1998. SCE's customer information and billing system is being replaced by a new Customer Service System designed and constructed to be Year 2000-ready. SCE's distributed computing assets include operations and business information systems. SCE's critical operations information systems include outage management, power management, and plant monitoring and access retrieval systems. SCE's critical business information systems include a data acquisition system for billing, the computer call center support system, credit support and maintenance management. EME has essentially completed all phases of the project and is going through the final review and approval process. Edison Capital has completed the inventory and impact assessment phases; remediation, testing and implementation activities are in progress for each of the three categories with completion scheduled by July 1, 1999. All project phases are underway at Edison Enterprises with completion scheduled by July 1, 1999. Ongoing efforts in 1999 will continue to focus on guarding against reintroduction of components that are not Year 2000-ready into Year 2000-ready systems. Also, business acquisitions routinely involve an analysis of Year 2000 readiness and are incorporated into the overall program as necessary. The other essential component of the Edison International Year 2000 program is to identify and assess vendor products and business partners for Year 2000 readiness, as these external parties may have the potential to impact Edison International's Year 2000 readiness. Edison International has implemented, 20
through its affiliates and their departments, a process to identify and contact vendors and business partners to determine their Year 2000 status. Evaluation of responses and other follow-up activities are continuing. Edison International's general policy requires that all newly purchased products and services be Year 2000-ready or otherwise designed to allow Edison International to determine whether such products and services present Year 2000 issues. SCE is also working to address Year 2000 issues related to all ISO and PX interfaces, as well as joint ownership facilities. SCE and other Edison International affiliates exchange Year 2000-readiness information (including, but not limited to, test results and related data) with one another and certain external parties as part of their Year 2000-readiness efforts. Edison International's current estimate of the costs to complete these modifications, including the cost of new hardware and software application modification, is $74 million, about 40% of which is expected to be capital costs. Edison International's Year 2000 costs expended through March 31, 1999, were $46 million. SCE expects current rate levels for providing electric service to be sufficient to provide funding for utility-related modifications. Although Edison International expects that its critical facilities, systems, information technology infrastructure and physical assets will be fully Year 2000-ready prior to year-end 1999, there can be no assurance that the facilities, systems, infrastructure and physical assets of other companies on which the systems and operations of Edison International rely will be converted on a timely basis. Edison International believes that prudent business practices call for development of contingency plans. These plans include provisions for monitoring, validating and managing the continued performance of Edison International Year 2000-sensitive systems and assets during critical transition periods, development of work-arounds and expedited fix-on-failure strategies. Where appropriate, contingency plans include scheduling of key personnel, identification of alternate suppliers, and securing adequate on-site supplies of critical materials. Edison International has implemented a Year 2000 Contingency Planning Process as a part of its Year 2000 Remediation Program. As part of this process, SCE, Edison Mission Energy, Edison Enterprises, and Edison Capital are required to assess the Year 2000 risks, including both internal and external risks and dependencies, associated with critical systems and assets, that are date aware or date sensitive. This includes assessment of Year 2000 risks for all indispensable or critical business processes and key facilities. Where appropriate, the SCE plans utilize or supplement the existing Corporate Emergency Response and Recovery Plan, and Information Technology disaster recovery plan, for identified Year 2000-related events. The SCE Year 2000 contingency plans are being developed to coordinate and interface with the ISO and PX and to satisfy Western System Coordinating Council (WSCC) and North America Electric Reliability Council (NERC) recommendations and Nuclear Energy Institute guidelines. SCE is working with these industry groups, as well as the Electric Power Research Institute, in the development of contingency plans. These plans are in the final stages of completion and are expected to be ready by June 30, 1999. SCE will be reporting on its contingency plans to the CPUC by July 1, 1999. Contingency plans will be used in conducting SCE and electric industry drills throughout the rest of 1999. However, it is expected that contingency plans will continue to be revised and enhanced as 2000 approaches. Although the SCE Year 2000 contingency plans are being developed using risk-based methods the plans are being evaluated against the NERC/WSCC suggested "more probable" and "credible worst case scenarios." SCE believes that the most likely worst case scenario would be small, localized interruptions of service which would be restored in a timeframe that is within normal service levels. The EME Year 2000 contingency plans for EME-operated generating plants are being developed using risk-based methods and following the Edison International Year 2000 guidelines and procedures. Year 2000 contingency plans have been developed, to date, for more than 70 % of EME-operated generating plants. The EME Year 2000 Contingency Planning Program, which includes development of contingency plans, allocations of resources and plan testing, is expected to be completed by October 1, 1999. The Year 2000 contingency plans for the EME generating plants that are owned or owned in part and not operated by EME are being developed and are also expected to be ready by October 1, 1999. Contingency plans will be 21
developed for generating plants and plant systems under construction and expected to be in service in 1999. The Edison Enterprises Year 2000 contingency plans for Edison Enterprises companies, including Edison Select, Edison Source and Edison Utility Services, are being developed using risk-based methods and following the Edison International Year 2000 guidelines and procedures. Draft Year 2000 Contingency Plans have been developed, to date, for Edison Enterprises' corporate center and for Edison Select. The Edison Enterprises Year 2000 Contingency Planning Program is expected to be completed by October 1, 1999. The Edison Capital Year 2000 contingency plan is being developed using risk-based methods and following the Edison International Year 2000 guidelines and procedures. The Edison Capital Year 2000 Contingency Planning Program is expected to be completed by October 1, 1999. 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, and despite the adoption of contingency plans, 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. 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 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; and other unforeseen events. 22
PART II -- OTHER INFORMATION Item 1. Legal Proceedings Edison International Geothermal Generators' Litigation Edison International, The Mission Group, and Mission Power Engineering Company, have been named as defendants in a lawsuit more fully described under "Southern California Edison Company - Geothermal Generators' Litigation below." Edison Mission Energy PMNC Litigation In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County, entitled The Parsons Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P. (Brooklyn Navy Yard), Mission Energy New York, Inc. and B-41 Associates, L.P., in which plaintiffs assert general monetary claims under the construction turnkey agreement in the amount of $136.8 million. In addition to defending this action, Brooklyn Navy Yard has also filed an action in the Supreme Court of the State of New York, Kings County 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, 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 and PMNC subsequently attached three Brooklyn Navy Yard bank accounts, located in California, in the amount of $0.5 million. Brooklyn Navy Yard is appealing the attachment order. On the same day, the court stayed all proceedings in the California action pending an order by the New York Appellate Court of the appeal by PMNC of a denial of its motion to dismiss the New York action. That appeal was denied following a hearing on September 29, 1998. On March 9, 1999, Brooklyn Navy Yard filed a partial Motion for Summary Judgment in the New York action. Southern California Edison Company Geothermal Generators' Litigation 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 (Coso parties). SCE alleges that in order to avoid power production plant shutdowns caused by excessive noncondensable gas in the geothermal field brine, the Coso parties 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 parties of their obligations under their contracts with SCE and applicable law. The complaint sought termination of the contracts and damages for excess power purchase payments made to the Coso parties. The Coso parties' motion to transfer venue to Inyo County Superior court was granted on August 31, 1997. On June 1, 1998, the court struck SCE's request for termination of the contracts, leaving SCE with its claim for damages and other relief. On February 16, 1999, the court denied the Coso Parties' motion for judgment on the pleadings directed to SCE's first amended complaint. The Coso parties have also asserted various claims against SCE, The Mission Group, and Mission Power Engineering Company (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 parties in Inyo County Superior Court. In November 1997, the court struck all but two causes of action asserted in the separate action on the 23
grounds that they should have been raised as part of the Coso parties' cross-complaint, and ordered the remaining two causes of action consolidated for all purposes with the action filed by SCE. The Coso parties subsequently filed second and third amended cross-complaints. The third amended cross-complaint names SCE, the Mission parties and Edison International. As against SCE, the third amended cross-complaint purports to state causes of action for declaratory relief, breach of the covenant of good faith and fair dealing; inducing breach of agreements between the Coso parties and their former employees; breach of an earlier settlement agreement between the Mission parties and the Coso parties; slander and disparagement, injunctive relief and restitution for unfair business practices; anticipatory breach of the contracts; and violations of Public Utilities Code ss.ss. 453, 702 and 2106. As against the Mission parties, the third amended cross-complaint seeks damages for breach of warranty of authority with respect to the settlement agreement, and for equitable indemnity. The Coso parties voluntarily dismissed Edison International from the third amended cross-complaint on December 4, 1998. As against SCE, the third amended cross-complaint seeks restitution, compensatory damages in excess of $115 million, punitive damages in an amount not less than $400 million, interest, attorney's fees, declaratory relief, and injunctive relief. On September 21, 1998, SCE filed an answer to the third amended cross-complaint generally denying the allegations contained therein and asserting affirmative defenses. In addition, SCE filed a cross-complaint for reformation of the contracts alleging that if they are not susceptible to SCE's interpretation, they should be reformed to reflect the parties' true intention. SCE subsequently voluntarily filed a first amended cross-complaint. The Coso defendants demurred to SCE's first amended cross-complaint and, in January 1999, their demurrer was sustained with leave to amend. On February 26, 1999, SCE filed a second amended cross-complaint for reformation. Following various pre-trial motions filed by the Mission parties and Edison International, the Coso Parties purported to file a fourth amended cross-complaint on December 23, 1998, against the Mission Parties only. The Mission Parties' demurrer to and motion to strike directed to the fourth amended cross-complaint was heard and taken under submission on March 10, 1999. On December 15, 1998, the Court granted the Coso parties leave to file a second amended complaint in the separately filed (now consolidated) action. The second amended complaint, which names SCE and Edison International, alleges that SCE engaged in anti-competitive conduct, false advertising, and conduct proscribed by Public Utilities Code ss. 2106, and seeks injunctive relief, restitution, and punitive damages. On January 20, 1999, SCE filed three motions to strike several portions of the second amended complaint on the grounds, among others, that the CPUC or FERC have either exclusive or primary jurisdiction over the matters asserted therein, and that SCE's alleged conduct was in furtherance of constitutionally protected rights of free speech and petition and therefore not actionable. These matters were heard on February 22, 1999, and taken under submission at that time. Edison International also filed a demurrer and motion to strike the second amended complaint. The Court denied the motion to strike and overruled the demurrer on March 22, 1999. On April 1, 1999, the Court signed a stipulation and order submitted by the parties staying all proceedings to allow the parties to engage in settlement discussions. The stay is in effect for a period of 60 days through and including May 29, 1999, subject to the right of any party to terminate the stay on or after April 30, 1999. As a result of the stay, all discovery has been suspended. Furthermore, during the period of the stay, the Court will not issue orders or rulings on matters taken under submission. The Court has set a trial date of March 1, 2000, but, in light of the stay currently in effect, has reserved jurisdiction to advance or to continue the trial date. The materiality of net final judgments against SCE in these actions would be largely dependent on the extent to which any damages or additional payments which might result therefrom are recoverable through rates. 24
San Onofre Personal Injury Litigation SCE is actively involved in three lawsuits claiming personal injuries allegedly resulting from exposure to radiation at San Onofre. On August 31, 1995, the wife and daughter of a former San Onofre security supervisor sued SCE and SDG&E in the U.S. District Court for the Southern District of California. Plaintiffs also named Combustion Engineering and the Institute of Nuclear Power Operations as defendants. All trial court proceedings were stayed pending ruling of the Ninth Circuit Court of Appeal, on an appeal of a lower court's judgment in favor of SCE in two earlier cases raising similar allegations. On May 28, 1998, the Court of Appeal affirmed these judgments. Pursuant to an agreement of the parties as described below, all proceedings in this matter have been stayed. 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. Plaintiffs also named Combustion Engineering. The trial in this case resulted in a jury verdict for both defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed an appeal of the trial court's judgment to the Ninth Circuit Court of Appeal. Briefing on the appeal was completed in January 1999 and the parties are awaiting a date for oral argument to be set by the court. A decision is not expected until early 2000. On November 28, 1995, a former contract worker at San Onofre, her husband, and her son, sued SCE in the U.S. District Court for the Southern District of California. Plaintiffs also named Combustion Engineering. On August 12, 1996, the Court dismissed the claims of the former worker and her husband with prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the parties as described below, all proceedings in this matter have been stayed. On November 20, 1997, a former contract worker at San Onofre and his wife sued SCE in the Superior Court of California, County of San Diego. The case was removed to the U.S. District Court for the Southern District of California. 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. Pursuant to a stipulation of the parties, the court, on January 4, 1999, dismissed the plaintiffs' complaint in this matter with prejudice. In March of 1999, SCE reached an agreement with the plaintiffs in both of the above cases currently pending at the U.S. District Court level to stay all proceedings including trial, pending the results of the case currently before the Ninth Circuit Court of Appeal. The parties agreed that if the plaintiffs/petitioners do not receive a favorable determination on appeal then the two cases at the District Court level will be dismissed. If, however, the plaintiffs/petitioners receive a favorable determination on appeal, then those two cases will be set for trial. On March 23, 1999, the District court approved the parties' stay agreement in both these cases. SCE was previously involved, along with other defendants, in two earlier cases raising allegations similar to those described above. Although SCE was successful in removing itself from those actions and is no longer actively involved in them, the impact on SCE, if any, from further proceedings in these cases against the remaining defendants can not be determined at this time. Mohave Generating Station Environmental Litigation On February 19, 1997, the Sierra Club and the Grand Canyon Trust filed suit in the U.S. District Court of Nevada against SCE and the other three co-owners of Mohave Generating Station. The lawsuit alleges that Mohave has been violating various provisions of the Clean Air Act (CAA), the Nevada state implementation plan, certain EPA 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 CAA, 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 pending the court's ruling on a motion to dismiss filed by the defendants. The plaintiffs filed an opposition to the defendants' motion to dismiss as well as a separate motion for partial summary judgment on May 8, 1998. The initial ruling by the court on the motions was (prior to the stay of proceedings described below) expected in early 1999. 25
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 as well as an additional plaintiff (National Parks and Conservation Association) to be added to the proceedings. On November 12, 1998, the court bifurcated the liability and damage phases of the case. On December 8, 1998, defendants filed a supplemental memorandum in support of defendants' opposition to plaintiffs' motion for partial summary judgment. On February 4, 1999, plaintiffs filed their first amended complaint to add the National Parks and Conservation Association as a plaintiff in the action. On March 10, 1999, defendants filed a motion for partial summary judgment. On March 11, 1999, plaintiffs filed a motion for partial summary judgment to establish emission limit violations as alleged in certain of the causes of action in their first amended complaint. On March 8, 1999, the parties filed a stipulated request for a 60-day stay which was granted and ordered by the court on March 9, 1999. Settlement discussions are ongoing. Item 4. Submission of Matters to a Vote of Security Holders Bylaw Amendment to Reduce Maximum and Minimum Board Size At Edison International's Annual Meeting of Shareholders on April 15, 1999 ("Annual Meeting"), shareholders approved a Bylaw Amendment to reduce the maximum and minimum Board size. The number of affirmative and negative votes, abstentions and broker non-votes with respect to the Bylaw Amendment were as follows: Broker Affirmative Negative Abstentions Non-votes ----------- -------- ----------- --------- Common Stock 289,420,032 4,644,612 4,499,563 0 Election of Directors At Edison International's Annual Meeting, shareholders also elected fourteen nominees to the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld from each Director-nominee were as follows: Number of Votes - ------------------------------------------------------------------------------- Name For Withheld - ------------------------------------------------------------------------------- John E. Bryson 291,896,834 6,667,373 Winston H. Chen 293,047,762 5,516,445 Warren Christopher 290,079,186 8,485,021 Stephen E. Frank 292,055,656 6,508,551 Joan C. Hanley 292,849,538 5,714,669 Carl F. Huntsinger 292,878,212 5,586,995 Charles D. Miller 292,567,880 5,996,327 Luis G. Nogales 292,581,207 5,983,000 Ronald L. Olson 290,946,572 7,617,635 James M. Rosser 292,715,933 5,848,274 Robert H. Smith 292,852,034 5,712,173 Thomas C. Sutton 292,994,605 5,569,002 Daniel M. Tellep 292,821,299 5,742,908 Edward Zapanta 292,582,254 5,981,953 26
Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 3.1 Restated Articles of Incorporation of Edison International dated May 7, 1998 (File No. 1-9936, Form 10-K for the year ended December 31, 1998)* 3.2 Certificate of Determination of Series A Junior participating Cumulative Preferred Stock of Edison International dated November 21, 1998 (Form 8-A dated November 21, 1998)* 3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on April 15, 1999 10.1 Form of Agreement for 1999 Employee Awards under the Equity Compensation Plan 10.2 Asset Purchase Agreement, dated August 1, 1998 between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., (incorporated by reference to Exhibit No. 10.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998, File No. 1-13434).* 10.3 Asset Sale Agreement, dated March 22, 1999 between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Fuel Generating Assets, (incorporated herein by reference to Exhibit No. 10.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998, File No. 1-13434.)* 11. Computation of Primary and Fully Diluted Earnings Per Share 27. Financial Data Schedule (b) Reports on Form 8-K: None - --------------------- * Incorporated by reference pursuant to Rule 12b-32. 27
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 THOMAS M. NOONAN ---------------------------------------- THOMAS M. NOONAN Vice President and Controller By KENNETH S. STEWART ---------------------------------------- KENNETH S. STEWART Assistant General Counsel and Assistant Secretary May 13, 1999