-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HhC+KjHbqRXWwr2JUm8zQsvqoVFpReuDLWqJEtrnNJ1vIKsyuF6ASXslYLv3xTJq u/sRks6wcVZWSLu+4GsbKw== 0001017062-01-000568.txt : 20010323 0001017062-01-000568.hdr.sgml : 20010323 ACCESSION NUMBER: 0001017062-01-000568 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20010322 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 20010322 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EDISON MISSION ENERGY CENTRAL INDEX KEY: 0000930835 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 954031807 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 000-24890 FILM NUMBER: 1575229 BUSINESS ADDRESS: STREET 1: 18101 VON KARMAN AVE STREET 2: STE 1700 CITY: IRVINE STATE: CA ZIP: 92612 BUSINESS PHONE: 9497525588 MAIL ADDRESS: STREET 1: 18101 VON KARMAN AVE STREET 2: STE 1700 CITY: IRVINE STATE: CA ZIP: 92612 FORMER COMPANY: FORMER CONFORMED NAME: MISSION ENERGY CO DATE OF NAME CHANGE: 19941003 8-K 1 0001.txt REPORT DATED 3/22/01 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 Date of Report (Date of Earliest Event Reported) March 22, 2001 Edison Mission Energy (Exact name of registrant as specified in its charter) California (State or other jurisdiction of incorporation or organization) 1-13434 95-4031807 (Commission File Number) (I.R.S. Employer Identification No.) 18101 Von Karman Avenue Irvine, California 92612 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (949) 752-5588 Not Applicable (Former name or former address, if changed since last report.) Items 1 through 6 and 8 are not included because they are not applicable. Item 7. Financial Statements, Pro Forma Financial Information and Exhibits. (a) Not applicable. (b) Not applicable. (c) Exhibits. 99.1 Certain information with respect to Edison Mission Energy to be disclosed to prospective private placement purchasers of senior notes not previously publicly reported. 2 Item 9. Regulation FD Disclosure. We are conducting a $500 million private placement of senior notes to repay short-term indebtedness, for development costs and for general corporate purposes. This private placement is permitted under Rule 144A of the Securities Act of 1933 and will be made only to qualified institutional buyers and to investors in transactions exempt from registration under Regulation S under the Securities Act. In connection with the private placement, we anticipate disclosing to prospective purchasers of the senior notes unaudited year-end earnings information and other information that has not been previously publicly reported. We have elected to provide this information, together with other information which has been previously publicly disclosed, in this Current Report on Form 8-K in the attached Exhibit 99.1 for informational purposes. Substantially all the information contained in this Current Report on Form 8-K will be reflected in our forthcoming Annual Report on Form 10-K for the year ended December 31, 2000. None of the information contained in this report or the exhibit hereto should be deemed to be filed under the Securities Exchange Act of 1934 or incorporated by reference into any other filings we have made or may make pursuant to the Securities Act or into any other documents unless such portion of this report is expressly and specifically identified in such filing as being incorporated by reference therein. No assurance can be made that the private placement of the senior notes will be completed. The private placement of the senior notes is presently expected to be completed in early April 2001. The senior notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements. This report is being furnished pursuant to the requirements of Regulation FD and does not constitute an offer to sell or the solicitation of an offer to buy any security and shall not constitute an offer, solicitation or sale of any securities in any jurisdiction in which such offer or sale would be unlawful. This report, together with the information attached as an exhibit hereto, includes "forward-looking statements," within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, reflecting management's current analysis and expectations, based on reasonable assumptions. Although we believe that our plans, intentions and expectations reflected in or suggested by such forward-looking statements are reasonable, actual results, including the timing of the 3 private placement and the proceeds anticipated therefrom, among others, could differ materially. These forward-looking statements are subject to various risks and uncertainties that may be outside our control, including, among other things: . the direct and indirect effects of the current California power crisis on us and our investments, as well as the measures adopted and being contemplated by federal and state authorities to address the crisis; . general political, economic and business conditions in the countries in which we do business; . governmental, statutory, regulatory or administrative changes or initiatives affecting us or the electricity industry generally; . political and business risks of international projects, including uncertainties associated with currency exchange rates, currency repatriation, expropriation, political instability, privatization efforts and other issues; . supply, demand and price for electric capacity and energy in the markets served by our generating units; . competition from other power plants, including new plants and technologies that may be developed in the future; . operating risks, including equipment failure, dispatch levels, availability, heat rate and output; . the cost, availability and pricing of fuel and fuel transportation services for our generating units; . our ability to complete the development or acquisition of current and future projects; . our ability to maintain an investment grade rating; and . our ability to refinance short-term debt or raise additional financing for our future cash requirements. We use words like "anticipate," "estimate," "project," "plan," "expect," "will," "believe" and similar expressions to help identify forward-looking statements in this report. This paragraph is included to provide safe harbor for forward-looking statements, which are not required to be publicly revised as circumstances change. 4 SIGNATURE 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 MISSION ENERGY (Registrant) By: /s/ Raymond W. Vickers ------------------------- Name: Raymond W. Vickers Title: Senior Vice President and General Counsel Date: March 22, 2001 5 EXHIBIT INDEX Number Exhibit - ------ ------- 99.1 Certain information with respect to Edison Mission Energy to be disclosed to prospective private placement purchasers of senior notes not previously publicly reported. 6 EX-99.1 2 0002.txt CERTAIN INFORMATION Exhibit 99.1 CERTAIN INFORMATION WITH RESPECT TO EDISON MISSION ENERGY TO BE DISCLOSED TO PROSPECTIVE PRIVATE PLACEMENT PURCHASERS OF SENIOR NOTES NOT PREVIOUSLY PUBLICLY REPORTED -i- The following summarizes certain information, including financial information, that we will disclose to prospective purchasers in connection with our proposed private placement of senior notes. The disclosures set forth below should be read in conjunction with our Annual Report on Form 10-K/A for the year ended December 31, 1999 and Quarterly Report on Form 10-Q for the nine months ended September 30, 2000. A. SUMMARY CONSOLIDATED FINANCIAL DATA FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998 The following table sets forth a summary of our consolidated financial data for the years ended December 31, 2000, 1999 and 1998. The summary consolidated financial data for the year ended December 31, 2000 were derived from the unaudited consolidated financial statements of Edison Mission Energy and our consolidated subsidiaries. The summary consolidated financial data for the years ended December 31, 1999 and 1998 were derived from the audited consolidated financial statements of Edison Mission Energy and our consolidated subsidiaries.
Years Ended December 31, -------------------------------- 2000 1999 1998 --------- --------- ---------- (in millions) Income Statement Data Operating revenues...... $ 3,241.0 $ 1,635.9 $ 893.8 Operating expenses...... 2,410.2 1,209.5 543.3 --------- --------- -------- Operating income........ 830.8 426.4 350.5 Interest expense........ (721.5) (375.5) (196.1) Interest and other income................. 74.0 55.8 50.9 Minority interest....... (3.2) (3.0) (2.8) --------- --------- -------- Income before income taxes.................. 180.1 103.7 202.5 Provision (benefit) for income taxes....... 72.5 (40.4) 70.4 --------- --------- -------- Income before accounting change and extraordinary loss..... 107.6 144.1 132.1 Cumulative effect on prior years of change in accounting for major maintenance costs, net of tax................. 17.7 -- -- Cumulative effect on prior years of change in accounting for start-up costs, net of tax.................... -- (13.8) -- Extraordinary loss on early extinguishment of debt, net of income tax benefit................ -- -- -- --------- --------- -------- Net income.............. $ 125.3 $ 130.3 $ 132.1 ========= ========= ======== As of December 31, -------------------------------- 2000 1999 1998 --------- --------- ---------- (in millions) Balance Sheet Data Assets.................. $15,017.1 $15,534.2 $5,158.1 Current liabilities..... 3,911.0 1,772.8 358.7 Long-term obligations... 5,334.8 7,439.3 2,396.4 Preferred securities of subsidiaries........... 326.8 476.9 150.0 Shareholder's equity.... 2,948.2 3,068.5 957.6 Years Ended December 31, -------------------------------- 2000 1999 1998 --------- --------- ---------- Other Data Ratio of earnings to fixed charges(1)....... 1.23 1.18 1.69
- ------- (1) For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. "Earnings" represents the aggregate of our income before income taxes (adjusted for the excess or shortfall of dividends or other distributions over equity in earnings of less than 50%- owned entities), amortization of previously capitalized interest and fixed charges (net of capitalized interest). "Fixed Charges" represents interest (whether expensed or capitalized), the amortization of debt discount and interest portion of rental expense. B. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Unless otherwise indicated, the information presented in this section is with respect to Edison Mission Energy and our consolidated subsidiaries. -ii- General We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States. We were formed in 1986 with two domestic operating projects. As of December 31, 2000, we owned interests in 33 domestic and 40 international operating power projects with an aggregate generating capacity of 28,036 MW, of which our share was 22,759 MW. At that date, one domestic and one international project, totaling 603 MW of generating capacity, of which our anticipated share will be approximately 462 MW, were in construction. At December 31, 2000, we had consolidated assets of $15.0 billion and total shareholder's equity of $2.9 billion. Our operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 91%, 83% and 74% of our total operating revenues during 2000, 1999 and 1998, respectively. Our consolidated operating revenues during those years also include equity in income from oil and gas investments, net losses from energy trading and price risk management activities and revenues attributable to operation and maintenance services. The financial data set forth in this section for the years ended December 31, 1999 and 1998 were derived from the audited consolidated financial statements of Edison Mission Energy and our consolidated subsidiaries, and the financial data for the year ended December 31, 2000 were derived from the unaudited consolidated financial statements of Edison Mission Energy and our consolidated subsidiaries. Acquisitions, Dispositions and Sale-Leaseback Transactions Acquisition of Sunrise Project On November 17, 2000, we completed a transaction with Texaco Inc. to purchase a proposed 560 MW gas fired combined cycle project to be located in Kern County, California, referred to as the Sunrise Project. The acquisition included all rights, title and interest held by Texaco in the Sunrise Project, except that Texaco has an option to repurchase a 50% interest in the project prior to its commercial operation. As part of this transaction, we also: (i) acquired from Texaco an option to purchase two gas turbines which we plan to utilize in the project, (ii) provided Texaco an option to purchase two of the turbines available to us under the Edison Mission Energy Master Turbine Lease and (iii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future power plant projects we designate. For more information on the Edison Mission Energy Master Turbine Lease, see "--Commitments and Contingencies-- Edison Mission Energy Master Turbine Lease." The Sunrise Project consists of two phases, with Phase I, construction of a single-cycle gas fired facility (320 MW), currently scheduled to be completed in August 2001, and Phase II, conversion to a combined-cycle gas fired facility (560 MW), currently scheduled to be completed in June 2003. In December 2000, we received the Energy Commission Certification and a permit to construct the Sunrise plant, which allowed us to commence construction of Phase I. We are negotiating with the California Department of Water Resources the detailed terms and conditions of a long-term cost-based-type rate power purchase agreement. We cannot assure you that we will be successful in reaching a final agreement. 14 The total purchase price of the Sunrise Project was $27 million. We funded the purchase with cash. The total estimated construction cost of this project is approximately $400 million. As of December 31, 2000, we had spent $17.8 million on construction costs for the Sunrise Project. Acquisition of Trading Operations of Citizens Power LLC On September 1, 2000, we completed a transaction with P&L Coal Holdings Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading operations of Citizens Power LLC and a minority interest in structured transaction investments relating to long-term power purchase agreements. The purchase price of $44.9 million was based on the sum of: (a) fair market value of the trading portfolio and the structured transaction investments at the date of the acquisition and (b) $25 million. The acquisition was funded with cash. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. By the end of the third quarter of 2000, the Citizens trading operations were merged into our own marketing operations under Edison Mission Marketing & Trading, Inc. Acquisition of Interest in Italian Wind On March 15, 2000, we completed a transaction with UPC International Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy. All the projects use wind to generate electricity from turbines which is sold under fixed-price, long-term tariffs. Assuming all the projects under development are completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW. The total purchase price is 90 billion Italian Lira (approximately $44 million at December 31, 2000), with equity contribution obligations of up to 33 billion Italian Lira (approximately $16 million at December 31, 2000), depending on the number of projects that are ultimately developed. As of December 31, 2000, our payments in respect of these projects included $27 million toward the purchase price and $13 million in equity contributions. Acquisition of Illinois Plants On December 15, 1999, we completed a transaction with Commonwealth Edison, a subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel power generating plants located in Illinois, which are collectively referred to as the Illinois Plants. These plants provide access to Mid-America Interconnected Network and the East Central Area Reliability Council. In connection with this transaction, we entered into power purchase agreements with Commonwealth Edison with terms of up to five years, pursuant to which Commonwealth Edison purchases capacity and has the right to purchase energy generated by the plants. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, LLC. Concurrently with the acquisition of the Illinois Plants, we assigned our right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating station located in Illinois, to third party lessors. After this assignment, we entered into leases of the Collins Station with terms of 33.75 years. The aggregate megawatts either purchased or leased as a result of these transactions with Commonwealth Edison and the third party lessors is 9,539 MW. Consideration for the Illinois Plants, excluding $860 million paid by the third party lessors to acquire the Collins Station, consisted of a cash payment of approximately $4.1 billion. The acquisition was funded primarily with a combination of approximately $1.6 billion of non-recourse debt secured by a pledge of the stock of specified subsidiaries, $1.3 billion of Edison Mission Energy's debt and $1.2 billion in equity contributions to us from Edison International. Acquisition of Ferrybridge and Fiddler's Ferry Plants On July 19, 1999, we completed a transaction with PowerGen UK plc to acquire the Ferrybridge and Fiddler's Ferry coal fired electric generating plants located in the U.K. Ferrybridge, located in West Yorkshire, and Fiddler's Ferry, located in Warrington, each has a generating capacity of approximately 2,000 MW. 15 Consideration for the purchase of the Ferrybridge and Fiddler's Ferry plants by our indirect subsidiary, Edison First Power, consisted of an aggregate of approximately $2.0 billion (1.3 billion pounds sterling at the time of the acquisition) for the two plants. The acquisition was funded primarily with a combination of net proceeds of 1.15 billion pounds sterling from the Edison First Power Limited Guaranteed Secured Variable Rate Bonds due 2019, a $500 million equity contribution to us from Edison International and cash. The Edison First Power Bonds were issued to a special purpose entity formed by Merrill Lynch International. Merrill Lynch International sold the variable rate coupons portion of the bonds to a special purpose entity that borrowed $1.3 billion (830 million pounds sterling at the time of the acquisition) under a term loan facility due 2012 to finance the purchase. Acquisition of Interest in Contact Energy On May 14, 1999, we completed a transaction with the New Zealand government to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of Contact Energy's shares were sold in an overseas public offering resulting in widespread ownership among the citizens of New Zealand and offshore investors. These shares are publicly traded on stock exchanges in New Zealand and Australia. During 2000, we increased our share of ownership in Contact Energy to 42%. Contact Energy owns and operates hydroelectric, geothermal and natural gas fired power generating plants primarily in New Zealand with a total current generating capacity of 2,449 MW. Consideration for Contact Energy consisted of a cash payment of approximately $635 million (1.2 billion New Zealand dollars at the time of the acquisition), which was financed by $120 million of preferred securities, a $214 million (400 million New Zealand dollars at the time of the acquisition) credit facility, a $300 million equity contribution to us from Edison International and cash. The credit facility was subsequently paid off with proceeds from the issuance of additional preferred securities. Acquisition of Homer City Plant On March 18, 1999, we completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to acquire the 1,884 MW Homer City Electric Generating Station. This facility is a coal fired plant in the mid-Atlantic region of the United States and has direct, high voltage interconnections to both the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly known as the NYISO, and the Pennsylvania-New Jersey- Maryland Power Pool, which is commonly known as the PJM. Consideration for the Homer City plant consisted of a cash payment of approximately $1.8 billion, which was partially financed by $1.5 billion of new loans, combined with our revolver borrowings and cash. Acquisition of Interest in EcoElectrica In December 1998, we acquired 50% of the 540 MW EcoElectrica liquefied natural gas combined-cycle cogeneration facility under construction in Penuelas, Puerto Rico for approximately $243 million. The project also includes a desalination plant and liquefied natural gas storage and vaporization facilities. Commercial operation commenced in March 2000. Accounting Treatment of Acquisitions Each of the acquisitions described above has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair market values. Amounts in excess of the fair value of the net assets acquired have been assigned to goodwill. Our consolidated statement of income reflects the operations of Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, EcoElectrica beginning March 1, 2000, the Homer City plant beginning March 18, 1999, Contact Energy beginning May 1, 1999, the Ferrybridge and Fiddler's Ferry plants beginning July 19, 1999, and the Illinois Plants beginning December 15, 1999. 16 Dispositions On August 16, 2000, we completed the sale of 30% of our interest in the Kwinana cogeneration plant to SembCorp Energy. We retain the remaining 70% ownership interest in the plant. Proceeds from the sale were $12 million. We recorded a gain on the sale of $8.5 million ($7.7 million after tax). On June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a gain on the sale of $17.0 million ($10.5 million after tax). Sale-Leaseback Transactions On August 24, 2000, we entered into a sale-leaseback transaction for the Powerton and Joliet power facilities located in Illinois to third party lessors for an aggregate purchase price of $1.367 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), our subsidiary makes semi-annual lease payments on each January 2 and July 2, beginning January 2, 2001. Edison Mission Energy guarantees the subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, we have a right of first refusal to acquire the interest at fair market value. Minimum lease payments during the next five years are $83.3 million for 2001, $97.3 million for 2002, $97.3 million for 2003, $97.3 million for 2004, and $141.1 million for 2005. At December 31, 2000, the total remaining minimum lease payments are $2.4 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain recognized on the sale of the power facilities has been deferred and is being amortized over the term of the leases. On July 10, 2000, one of our subsidiaries entered into a sale-leaseback of equipment, primarily Illinois peaker power units, to a third party lessor for $300 million. Under the terms of the 5-year lease, we have a fixed price purchase option at the end of the lease term of $300 million. We guarantee the monthly payments under the lease. In connection with the sale-leaseback, a subsidiary of ours purchased $255 million of notes issued by the lessor which accrue interest at LIBOR plus 0.65% to 0.95%, depending on our credit rating. The notes are due and payable in five years. The gain recognized on the sale of equipment has been deferred and is being amortized over the term of the lease. Results of Operations We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific, and Europe, Central Asia, Middle East and Africa. Operating revenues are derived from our majority-owned domestic and international entities. Equity in income from investments relates to energy projects where our ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which we have a significant influence but in which we do not have a controlling interest. With respect to entities accounted for under the equity method, we recognize our proportional share of the income or loss of such entities. 17 Americas
Years Ended December 31, ---------------------------- 2000 1999 1998 --------- -------- -------- (in millions) Americas Operating revenues............................. $ 1,571.0 $ 378.6 $ 29.9 Net losses from energy trading and price risk management.................................... (17.3) (6.4) -- Equity in income from investments.............. 257.2 224.8 184.6 --------- ------- ------- Total operating revenues..................... 1,810.9 597.0 214.5 Fuel and plant operations...................... 1,131.6 237.7 22.2 Depreciation and amortization.................. 191.2 52.5 9.8 Administrative and general..................... 21.1 -- -- --------- ------- ------- Operating Income............................... $ 467.0 $ 306.8 $ 182.5 ========= ======= =======
Operating Revenues Operating revenues increased $1.2 billion in 2000 compared to 1999, and increased $348.7 million in 1999 compared to 1998. The 2000 increase resulted from a full-year of electric revenues from the Illinois Plants acquired in December 1999 and the Homer City plant acquired in March 1999. The 1999 increase resulted from electric revenues from the Homer City plant. There were no comparable electric revenues for the Homer City plant for 1998. Electric power generated at the Illinois Plants is sold under three five- year power purchase agreements with Exelon Generation Company, terminating in December 2004. Exelon Generation is obligated to make capacity payments for the plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $1.1 billion for the year ended December 31, 2000. This represented 33% of our consolidated operating revenues in 2000. On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. Our energy trading activities are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Net gains from energy trading activities since the date of this acquisition were $62.2 million. Our price risk management activities included economic hedge transactions that required mark to market accounting. Total losses from price risk management activities were $79.5 million and $6.4 million in 2000 and 1999, respectively. The increase in losses was primarily due to realized and unrealized losses for a gas swap entered into as an economic hedge of a portion of our gas price risk related to our share of gas production in Four Star (an oil and gas company in which we have a minority interest and which we account for under the equity method). Although we believe the gas swap hedges our gas price risk, hedge accounting is not permitted for our investments accounted for on the equity method. Partially offsetting this loss in 2000 was a gain realized for calendar year 2001 financial options entered into beginning August 2000 as a hedge of our price risk associated with expected natural gas purchases at the Illinois Plants. During the fourth quarter, we determined that it was no longer probable that we would purchase natural gas at the Illinois Plants during 2001. This decision resulted from sustained gas prices far greater than were contemplated when we originally projected our 2001 gas needs and the fact that we can use fuel oil interchangeably with natural gas at some of the Illinois Plants. At the time we made our revised determination, the fair value of our financial option was $38 million. This gain is being deferred as required by hedge accounting and will be recognized upon either purchasing natural gas in 2001 or determining that it is probable we will not purchase natural gas in 2001. Subsequent to our revised determination, we settled the option for a 18 $56 million gain. Accordingly, $18 million of gain was recognized in the fourth quarter. Concurrent with our revised determination of our 2001 natural gas requirements at the Illinois Plants, we entered into some additional fuel contracts to offset our financial option and economically hedge the price risk associated with fuel oil. We recognized a $12 million loss at December 31, 2000 on these additional fuel contracts. Equity in income from investments rose 14% in 2000 over 1999, and 22% in 1999 over 1998. The 2000 increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing and higher revenues from oil and gas investments due to higher oil and gas prices. The 1999 increase was primarily the result of higher revenues from several cogeneration projects due to a final settlement on energy prices tied to short-run avoided cost with the applicable public utilities and, second, from one cogeneration project as a result of a gain on termination of a power sales agreement. In addition, the 1999 increase resulted from higher revenues from oil and gas investments primarily due to higher oil and gas prices. Many of the domestic energy projects in which our ownership interest is 50% or less rely on one power sales contract with a single electric utility customer for the majority, and in some cases all, of their power sales revenues over the life of the power sales contract. The primary power sales contracts for four of our operating projects in 2000 and 1999 and five of our operating projects in 1998 are with Southern California Edison. Our share of equity in earnings from these projects accounted for 5% in 2000, 8% in 1999 and 13% in 1998 of our consolidated revenues for the respective years. For more information on these projects and other projects in California, see "-- Commitments and Contingencies--California Power Crisis." Due to warmer weather during the summer months, electric revenues generated from the Homer City plant and the Illinois Plants are usually higher during the third quarter of each year. In addition, our third quarter equity in income from investments in energy projects is materially higher than other quarters of the year due to higher summer pricing for our West Coast power investments. Operating Expenses Fuel and plant operations increased $893.9 million in 2000 compared to 1999, and increased $215.5 million in 1999 compared to 1998. The 2000 increase resulted from a full year of expenses at the Illinois Plants and the Homer City plant. The 1999 increase in fuel and plant operations resulted from having no comparable expenses for the Homer City plant and the Illinois Plants for 1998. Depreciation and amortization expense increased $138.7 million in 2000 compared to 1999, and increased $42.7 million in 1999 compared to 1998. The 2000 increase was primarily due to a full year of depreciation and amortization expense related to the Illinois Plants. The 1999 increase in depreciation and amortization compared to 1998 resulted primarily from the 1999 acquisition of the Homer City plant. Administrative and general expenses for 2000 consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts from September 1, 2000, the acquisition date of Citizens Power LLC, through December 31, 2000. Prior to September 1, 2000, administrative and general expenses incurred by our own marketing operations were reflected in Corporate/Other administrative and general expenses. Operating Income Operating income increased $160.2 million in 2000 compared to 1999, and increased $124.3 million in 1999 compared to 1998. The 2000 increase was primarily due to operating income from the Illinois Plants, the Homer City plant and equity in income from investments in oil and gas. The 1999 increase resulted from operating income from the Homer City plant and equity in income from investments in energy projects. 19 Asia Pacific
Years Ended December 31, -------------------------- 2000 1999 1998 -------- -------- -------- (in millions) Asia Pacific Operating revenues............................... $ 184.2 $ 213.6 $ 205.1 Equity in income from investments................ 14.6 18.1 1.3 -------- -------- -------- Total operating revenues....................... 198.8 231.7 206.4 Fuel and plant operations........................ 61.5 73.8 69.6 Depreciation and amortization.................... 35.0 40.5 31.6 -------- -------- -------- Operating Income................................. $ 102.3 $ 117.4 $ 105.2 ======== ======== ========
Operating Revenues Operating revenues decreased $29.4 million in 2000 compared to 1999, and increased $8.5 million in 1999 compared to 1998. The 2000 decrease was attributable to lower electric revenues from our Loy Yang B plant. During May 2000, we experienced a major outage due to damage to the generator at one of our two 500 MW units at the Loy Yang B power plant complex in Australia. The unit was restored to operation in September 2000. Under our insurance program, we are obligated for the property damage insurance deductible of $2 million and for loss of profits during the first 15 days following the insurable event. The repair costs in excess of the deductible amount together with the loss of profits after the first 15 days and until the unit was back in operation were partially recovered from insurance as of December 31, 2000. The 1999 increase was primarily due to higher electric revenues from the Loy Yang B plant due to increased generation in 1999; as compared to 1998, when the plant experienced longer planned outages. Equity in income from investments decreased $3.5 million in 2000 compared to 1999, and increased $16.8 million in 1999 compared to 1998. The 2000 decrease is primarily due to lower profitability of our interest in Contact Energy resulting from lower electricity prices caused by milder winter weather conditions. The 1999 increase reflects the purchase of our 40% ownership interest in Contact Energy in May 1999. Operating Expenses Fuel and plant operations decreased $12.3 million in 2000 compared to 1999, and increased $4.2 million in 1999 compared to 1998. The 2000 decrease resulted primarily from lower fuel costs at the Loy Yang B plant due to the major outage at one of its two 500 MW units. The 1999 increase in fuel expense and plant operations resulted from higher fuel costs from the Loy Yang B plant due to increased production in 1999; as compared to 1998, when the plant had lower fuel expenses and longer planned outages. Depreciation and amortization expense decreased $5.5 million in 2000 compared to 1999, and increased $8.9 million in 1999 compared to 1998. The 2000 decrease was primarily due to favorable changes in foreign exchange rates. The 1999 increase in depreciation and amortization expense related to the acquisition of our interest in 1999 in the Contact Energy project. Operating Income Operating income decreased $15.1 million in 2000 compared to 1999, and increased $12.2 million in 1999 compared to 1998. The 2000 decrease was due to lower operating income from the Loy Yang B plant resulting from the major outage at one of its two 500 MW units and a decrease in the value of the Australian dollar compared to the U.S. dollar. We recorded pre-tax losses of $8.4 million in 2000 related to this outage. The 1999 increase resulted from the acquisition of Contact Energy. 20 Europe, Central Asia, Middle East and Africa
Years Ended December 31, --------------------------- 2000 1999 1998 --------- ---------------- (in millions) Europe, Central Asia, Middle East and Africa Operating revenues............................... $ 1,236.3 $ 805.8 $ 469.4 Equity in income (loss) from investments......... (5.0) 1.4 3.5 --------- ------- ------- Total operating revenues..................... 1,231.3 807.2 472.9 Fuel and plant operations........................ 730.1 456.6 241.3 Depreciation and amortization.................... 144.8 88.3 40.3 --------- ------- ------- Operating Income................................. $ 356.4 $ 262.3 $ 191.3 ========= ======= =======
Operating Revenues Operating revenues increased $430.5 million in 2000 compared to 1999, and increased $336.4 million in 1999 compared to 1998. The 2000 increase resulted from a full year of electric revenues from the Ferrybridge and Fiddler's Ferry plants acquired in July 1999 and the Doga project, which commenced commercial operation in May 1999. Despite the overall increase in operating revenues in 2000 which resulted from the inclusion of a full year of operations of these projects, electric revenues from Ferrybridge and Fiddler's Ferry in 2000 were adversely affected by lower energy prices during the year, primarily due to increased competition, warmer-than-average weather and uncertainty surrounding planned changes in electricity trading arrangements described below under "-- Market Risk Exposures--United Kingdom." The time weighted average System Marginal Price dropped from 22.39 pounds sterling/MWh in 1999 to 18.75 pounds sterling/MWh in 2000. We have entered into electricity rate price swaps for the majority of our forecasted generation through the winter 2000/2001, and accordingly, have mitigated the downside risks to further decreases in energy prices during this period. Despite improvement in capacity prices during August, September and early October 2000, and a slight firming of forward prices, the short-term prices for energy continue to be below the prices in prior years. As a result of the foregoing, we continue to expect lower revenues from our Ferrybridge and Fiddler's Ferry plants in 2001. The 1999 increase as compared to 1998 was primarily due to inclusion of electric revenues from the Ferrybridge and Fiddler's Ferry plants and the Doga project. There were no comparable electric revenues for the Ferrybridge and Fiddler's Ferry plants and the Doga project for 1998. The First Hydro plants, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants are expected to provide for higher electric revenues during the winter months. Equity in income from investments decreased $6.4 million in 2000 compared to 1999, and decreased $2.1 million in 1999 compared to 1998. The 2000 decrease reflects losses from initial commercial operation of the ISAB project in April 2000. We had no comparable results for the ISAB project in 1999. Operating Expenses Fuel and plant operations increased $273.5 million in 2000 compared to 1999, and increased $215.3 million in 1999 compared to 1998. The 2000 increase resulted from a full year of expenses at the Ferrybridge and Fiddler's Ferry plants and the Doga project, partially offset by lower fuel expense at the First Hydro plant. Fuel expense at First Hydro decreased primarily due to a drop in energy prices throughout the year and lower pumping costs. The 1999 increase in fuel expense and plant operations resulted from having no comparable expenses for the Ferrybridge and Fiddler's Ferry plants and the Doga project for 1998. Depreciation and amortization expense increased $56.5 million in 2000 compared to 1999, and increased $48 million in 1999 compared to 1998. The 2000 increase was primarily due to a full year of depreciation and amortization expense associated with the Ferrybridge and Fiddler's Ferry plants. The 1999 increase in depreciation and amortization resulted primarily from the 1999 acquisition of the Ferrybridge and Fiddler's Ferry plants. 21 Operating Income Operating income increased $94.1 million in 2000 compared to 1999, and increased $71 million in 1999 compared to 1998. The 2000 increase was primarily due to operating income from the Ferrybridge and Fiddler's Ferry plants, the Doga project and higher operating income from the First Hydro plant. The 1999 increase resulted from the inclusion of operating income from the Ferrybridge and Fiddler's Ferry plants and the Doga project. Corporate/Other
Years Ended December 31, --------------------------- 2000 1999 1998 -------- -------- -------- (in millions) Corporate/Other Depreciation and amortization.................. $ 11.1 $ 8.9 $ 5.6 Long-term incentive compensation............... (56.0) 136.3 39.0 Administrative and general..................... 139.8 114.9 83.9 ------- -------- -------- Operating Loss................................. $ (94.9) $ (260.1) $ (128.5) ======= ======== ========
Long-term incentive compensation expense consists of charges related to our now terminated phantom option plan. Long-term incentive compensation expenses decreased $192.3 million in 2000 compared to 1999, and increased $97.3 million in 1999 compared to 1998. The 2000 decrease was due to the absence of new accruals, as the plan had been terminated, and to a reduction in the liability for previously accrued incentive compensation by approximately $60 million resulting from the lower valuation, compared to the value previously accrued, implicit in the August 2000 exchange offer pursuant to which the phantom option plan was terminated. The 1999 increase was primarily due to the impact of the 1999 acquisitions of the Illinois Plants, the Ferrybridge and Fiddler's Ferry plants, the Homer City plant and a 40% interest in Contact Energy. No further phantom option plan grants were made in 2000 and, since the plan and all of the outstanding phantom stock options have been terminated, no further phantom stock options will be granted or exercised. Administrative and general expenses increased $24.9 million in 2000 compared to 1999, and increased $31 million in 1999 compared to 1998. The increases in both periods were primarily due to additional salaries and facilities costs incurred to support the 1999 acquisitions. We recorded a pretax charge of approximately $9 million against earnings for severance and other related costs, which contributed to the 2000 increase. The charge resulted from a series of actions undertaken by us designed to reduce administrative and general operating costs, including reductions in management and administrative personnel. Other Income (Expense) On August 16, 2000, we completed the sale of 30% of our interest in the Kwinana cogeneration plant to SembCorp Energy. We retain the other 70% ownership interest in the plant. Proceeds from the sale were $12 million. We recorded a gain on the sale of $8.5 million ($7.7 million after tax). On June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a gain on the sale of $17.0 million ($10.5 million after tax). During the fourth quarter of 1999, we completed the sale of 31.5% of our 50.1% interest in Four Star Oil & Gas for $34.2 million in cash and a 50% interest in the acquirer, Four Star Holdings. Four Star Holdings financed the purchase of the interest in Four Star Oil & Gas from $27.5 million in loans from affiliates, including $13.7 million from us, and $13.7 million from cash. Upon completion of the sale, we continue to own an 18.6% direct interest in Four Star Oil & Gas and an indirect interest of 15.75% which is held through Four Star Holdings. As a result of this transaction, our total interest in Four Star Oil & Gas has decreased from 22 50.1% to 34.35%. Cash proceeds from the sale were $34.2 million ($20.5 million net of the loan to Four Star Holdings). The gain on the sale of the 31.5% interest in Four Star Oil & Gas was $11.5 million of which we deferred 50%, or $5.6 million, due to our equity interest in Four Star Holdings. The after-tax gain on the sale was approximately $30 million. Interest expense increased $336.2 million in 2000 compared to 1999, and increased $170.3 million in 1999 compared to 1998. The 2000 increase was primarily the result of additional debt financing associated with the acquisitions of the Illinois Plants, Ferrybridge and Fiddler's Ferry plants and the Homer City plant. The 1999 increase was also the result of debt financing of the Homer City plant, Ferrybridge and Fiddler's Ferry plants and the Illinois Plants acquisition. Dividends on mandatorily redeemable preferred securities increased $9.7 million in 2000 compared to 1999 and increased $9.2 million in 1999 compared to 1998. The 2000 and 1999 increases reflect the issuance of preferred securities in connection with the Contact Energy acquisition. Provision (Benefit) for Income Taxes We had effective tax provision (benefit) rates of 40.3%, (39.0)% and 34.8% in 2000, 1999 and 1998, respectively. Income taxes increased in 2000 principally due to a higher foreign income tax expense compared to 1999, nonrecurring 1999 tax benefits discussed below and higher state income taxes due to the Homer City plant and Illinois Plants. Income taxes decreased in 1999, principally due to lower pre-tax income and income tax benefits. In 1999, we recorded tax benefits associated with a capital loss attributable to the sale of a portion of our interest in Four Star Oil & Gas Company, refunds of advanced corporation tax payments from the United Kingdom and a reduction in deferred taxes in Australia as a result of a decrease in statutory rates. In addition, our effective tax rate has decreased as a result of lower foreign income taxes that result from the permanent reinvestment of earnings from foreign affiliates located in different foreign tax jurisdictions. The Australian corporate tax rate decreased from 36% to 34% effective in July 2000, and is scheduled to decrease from 34% to 30% effective in July 2001. The 1998 tax provision reflects a benefit from reductions in the U.K corporate tax rate from 33% to 31% effective in April 1997, and from 31% to 30% effective in April 1999. In accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the reductions in the Australia and U.K. income tax rates resulted in reductions in income tax expense of approximately $5.9 million and $11 million in 1999 and 1998, respectively. We are, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions we take in connection with the filing of our tax returns. Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in our opinion, it is unlikely that the resolution of any such matters will have material adverse effect upon our financial condition or results of operations. Cumulative Effect of Change in Accounting Principle Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as the "accrue in advance" accounting method). The accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the Securities and Exchange Commission issued a letter to the Accounting Standards Executive Committee, stating its position that the Securities and Exchange Commission staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance costs. The Accounting Standards Executive Committee agreed to add accounting for major maintenance costs as part of an existing project and to issue authoritative guidance by August 2001. Due to the position taken by the Securities and Exchange Commission staff, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. Such change in accounting policy is considered preferable based on the recent guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we have recorded a $17.7 million, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000. 23 In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities," which became effective in January 1999. The Statement requires that specified costs related to start-up activities be expensed as incurred and that specified previously capitalized costs be expensed and reported as a cumulative change in accounting principle. The reduction to our net income that resulted from adopting SOP 98-5 was $13.8 million, after tax. Liquidity and Capital Resources At December 31, 2000, we had cash and cash equivalents of $962.9 million and had available a total of $41 million of borrowing capacity under a $500 million revolving credit facility that expires on October 11, 2001 and a $300 million senior credit facility that expires on May 29, 2001. We also had available $127.3 million of borrowing capacity under a $700 million senior credit facility that is now scheduled to expire on May 29, 2001. The revolving credit facility provides credit available in the form of cash advances or letters of credit, and bears interest on advances under the London Interbank Offered Rate, LIBOR, which was 6.66% at December 31, 2000, plus the applicable margin as determined by our long-term credit ratings (0.175% margin at December 31, 2000). In addition to the interest component described above, we pay a facility fee as determined by our long-term credit ratings (0.09% at December 31, 2000) on the entire credit facility independent of the level of borrowings. Net working capital at December 31, 2000 was ($1,703.9) million compared to ($815.5) million at December 31, 1999. The decrease reflects the reclassification to current maturities of long-term obligations from long-term obligations at December 31, 2000 of indebtedness under the financing documents entered into to finance the acquisition of the Ferrybridge and Fiddler's Ferry plants in 1999. See "--Financing Plans" below for further discussion. Cash provided by operating activities is derived primarily from operations of the Illinois Plants and the Homer City plant, distributions from energy projects and dividends from investments in oil and gas. Net cash provided by operating activities increased $248.1 million in 2000 compared to 1999 and $150.6 million in 1999 compared to 1998. The 2000 increase primarily reflects higher pre-tax earnings from projects acquired in 1999 and higher dividends from oil and gas investments. The 1999 increase was primarily due to higher distributions from energy projects and higher dividends from oil and gas investments. Net cash used in financing activities totaled $783 million in 2000, compared to net cash provided by financing activities of $8,363.5 million and $17.9 million in 1999 and 1998, respectively. Payments made on our credit facilities totaling $1.4 billion, a $500 million payment on our floating rate notes and the redemption of the Flexible Money Market Cumulative Preferred Stock for $124.7 million were the primary contributors of the net cash used in financing activities during 2000. Edison Mission Energy used the proceeds from the August 2000 Powerton and Joliet sale-leaseback transaction for a significant portion of those payments on the credit facilities, commercial paper facilities and the floating rate notes. We also paid dividends of $88 million to Edison International. In 2000, we also had borrowings of $1.2 billion under our credit facilities and commercial paper facilities. In February 2000, Edison Mission Midwest Holdings Co. issued $1.7 billion of commercial paper under its credit facility and repaid a similar amount of its outstanding bank borrowings for the Illinois Plants. Subsequently, Edison Mission Midwest Holdings Co. repaid $769.3 million of commercial paper under its credit facility and issued a similar amount of its bank borrowings for the Illinois Plants in December 2000. In January 2000, one of our foreign subsidiaries borrowed $242.7 million from Edison Capital, an indirect affiliate. In 1999, financings related to the acquisition of four new projects in 1999 contributed to net cash provided by financing activities. A term loan facility of $1.3 billion related to the Ferrybridge and Fiddler's Ferry plants, senior secured bonds totaling $830 million related to the Homer City plant, $120 million Flexible Money Market Cumulative Preferred Stock and $125 million Retail Redeemable Preference Shares and $84 million Class A Redeemable Preferred Shares related to Contact Energy and credit facilities totaling $1.7 billion related to the Illinois Plants. In addition, our financings in connection with the aforementioned acquisitions consisted of floating rate notes of $500 million, borrowings of $215 million under our revolving credit facility and commercial paper facilities totaling $1.2 billion. In addition, we also received 24 $2.0 billion in equity contributions from Edison International, which amount was 100% financed in the capital markets, to finance our 1999 acquisitions. In June 1999, we issued $600 million of 7.73% Senior Notes due 2009. As of December 31, 2000, we had recourse debt of $2.1 billion, with an additional $5.9 billion of non-recourse debt (debt which is recourse to specific assets or subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet. Net cash provided by investing activities totaled $718.1 million in 2000, compared to net cash used in investing activities of $8,837.8 million and $408.2 million in 1999 and 1998, respectively. In 2000, net cash provided by investing activities was primarily due to proceeds of $1.367 billion and $300 million received from the sale leaseback transactions with respect to the Powerton and Joliet power facilities in August 2000 and the Illinois peaker power units in July 2000, respectively. In connection with the Illinois peaker power units transaction, we purchased $255 million of notes issued by the lessor. In 2000, $27 million was paid toward the purchase price and $13 million in equity contributions for the Italian Wind projects, $44.9 million for the Citizens trading operations and structured transaction investments, and $27 million for the acquisition of the Sunrise project. In addition, $33.5 million, $21.2 million and $20 million was made in equity contributions for the EcoElectrica project (June 2000), the Tri Energy project (July 2000) and the ISAB project (September 2000), respectively. In 1999, cash used in investing activities was primarily due to the purchase of the Homer City plant, Ferrybridge and Fiddler's Ferry generating facilities, the Illinois Plants and the 40% interest in Contact Energy. We invested $352.3 million, $216.4 million and $73.4 million in 2000, 1999 and 1998, respectively, in new plant and equipment principally related to the Homer City plant and Illinois Plants in 2000, the Homer City plant and Ferrybridge and Fiddler's Ferry plants in 1999, and the Doga project in 1998. Credit Ratings On January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions to isolate ourselves from the credit downgrades and potential bankruptcies of Edison International and Southern California Edison and to facilitate our ability and the ability of our subsidiaries to maintain their respective investment grade ratings. These ring- fencing provisions are intended to preserve us as a stand-alone investment grade rated entity despite the current credit difficulties of Edison International and Southern California Edison. These provisions require the unanimous approval of our board of directors, including at least one independent director, before we can do any of the following: . declare or pay dividends or distributions unless: . we then have an investment grade rating and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or . the dividends do not exceed $32.5 million in any fiscal quarter and we meet an interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters. We currently meet this interest coverage ratio; . institute or consent to bankruptcy, insolvency or similar proceedings or actions; or . consolidate or merge with any entity or transfer substantially all our assets to any entity, except to an entity that is subject to similar restrictions. We cannot assure you that these measures will effectively isolate us from the credit downgrades or the potential bankruptcies of Edison International and Southern California Edison. In January 2001, Standard & Poor's and Moody's lowered our credit ratings. Our senior unsecured credit ratings were downgraded to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's. Our credit ratings remain investment grade. Both Standard & Poor's and Moody's have indicated that the ratings outlook for us is stable. We cannot assure you that Standard & Poor's and Moody's will not downgrade us below investment grade, whether as a result of the California power crisis or otherwise. If we are downgraded, we could be required to, among other things: . provide additional guarantees, collateral, letters of credit or cash for the benefit of counterparties in our trading activities, 25 . post a letter of credit or cash collateral to support our $58.5 million equity contribution obligation in connection with our acquisition in February 2001 of a 50% interest in the CBK project in the Philippines, and . repay a portion of the preferred shares issued by our subsidiary in connection with our 1999 acquisition of a 40% interest in Contact Energy Limited, a New Zealand power company, which, based on their value at March 20, 2001, would require a payment of approximately $19 million. Our downgrade could result in a downgrade of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below its current credit rating, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, limit the ability of Midwest Generation to use excess cash flow to make distributions. A downgrade in our credit rating below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries. Restricted Assets of Subsidiaries Each of our direct or indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Assets of our subsidiaries may not be available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours. Financing Plans Corporate Financing Plans - We have three corporate credit facilities that are scheduled to expire in May 2001 (in a total amount of $1 billion) and October 2001 (in an amount of $500 million). As of March 16, 2001, we have borrowed or issued letters of credit aggregating $1.49 billion under these credit facilities and have an unused capacity of approximately $10 million. If this offering is not consummated as anticipated, we will need to obtain additional debt to meet our short-term capital needs. We plan to refinance our corporate credit facilities through modifications to our existing credit facilities or by entering into new short-term facilities prior to their expiration. Our corporate cash requirements in 2001 are expected to exceed cash distributions from our subsidiaries. Our corporate cash requirements in 2001 include: . debt service under our senior notes and intercompany notes resulting from sale-leaseback transactions which aggregate $149 million; . capital requirements for projects in development and under construction of $251 million; and . development costs, general and administrative expenses. We plan to finance these activities through new short-term facilities and through the use of project or subsidiary financings or capital markets debt, depending on market conditions. However, while we cannot assure you that we will be able to enter into modifications to our existing credit facilities or obtain additional debt to finance our needs or that the credit facilities can be modified or obtained under similar terms and rates as our agreements, we believe our corporate financing plans will be successful in meeting our cash requirements in 2001. In addition, to reduce debt and to provide additional liquidity, we may sell our interest in individual projects in our project portfolio. Under one of our credit facilities, we are required to use 50% of the net proceeds from the sale of assets and 75% of the net proceeds from the issuance of capital markets debt to repay senior bank indebtedness, in each case in excess of $300 million in the aggregate. There is no assurance that we will be able to sell assets on favorable terms or that the sale of individual assets will not result in a loss. Subsidiary Financing Plans - During 2001, the estimated capital expenditures of our subsidiaries is $262 million, including environmental expenditures disclosed under "--Environmental Matters and Regulations." These capital expenditures are planned to be financed by existing subsidiary credit agreements 26 and cash generated from their operations. Other than as described below under "Commitments and Contingencies," we do not plan to make additional capital contributions to our subsidiaries. One of our subsidiaries, Edison First Power, has defaulted on its financing documents related to the acquisition of the Fiddler's Ferry and Ferrybridge power plants. The financial performance of these plants has not matched our expectations, largely due to lower energy power prices resulting primarily from increased competition, warmer-than-average weather and uncertainty surrounding the new electricity trading arrangements. See "--Market Risk Exposures--United Kingdom." As a result, Edison First Power has decided to defer some environmental capital expenditures originally planned to increase plant utilization and therefore is currently in breach of milestone requirements for the implementation of the capital expenditures program set forth in the financing documents relating to the acquisition of these plants. In addition, due to this reduced financial performance, Edison First Power's debt service coverage ratio during 2000 declined below the threshold set forth in the financing documents. Edison First Power is currently in discussions with the relevant financing parties to revise the required capital expenditure program, to waive (i) the breach of the financial ratio covenant for 2000, (ii) a technical breach of requirements for the provision of information that was delayed due to uncertainty regarding capital expenditures, and (iii) other related technical defaults. Edison First Power is in the process of requesting the necessary waivers and consents to amendments from the financing parties. There can be no assurance that these waivers and consents to amendments will be forthcoming. The financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing parties are entitled to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite the breaches under the financing documents, Edison First Power's debt service coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service payments, Edison First Power utilized 37 million pounds sterling from its debt service reserve to meet its debt service requirements in 2000. Another of our subsidiaries, EME Finance UK Limited, is the borrower under a facility made available for the purposes of funding coal and capital expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At December 31, 2000, 58 million pounds sterling was outstanding for coal purchases and zero was outstanding to fund capital expenditures under this facility. EME Finance UK Limited on-lends any drawings under this facility to Edison First Power. The financing parties of this facility have also issued letters of credit directly to Edison First Power to support their obligations to lend to EME Finance UK Limited. EME Finance UK Limited's obligations under this facility are separate and apart from the obligations of Edison First Power under the financing documents related to the acquisition of these plants. We have guaranteed the obligations of EME Finance UK Limited under this facility, including any letters of credit issued to Edison First Power under the facility, for the amount of 359 million pounds sterling, and our guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents. In addition, Edison Mission Energy may provide guarantees in support of bilateral contracts entered into by Edison First Power under the new electricity trading arrangements. Edison Mission Energy has provided guarantees totalling 19 million pounds sterling relating to these contracts at March 20, 2001. In accordance with SFAS No. 121, "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed", we have evaluated impairment of the Ferrybridge and Fiddler's Ferry power plants. The undiscounted projected cash flow from these power plants exceeds the net book value at December 31, 2000, and, accordingly, no impairment of these power plants is permitted under SFAS No. 121. As a result of the change in the prices of power in the U.K., we are considering the sale of Ferrybridge and Fiddler's Ferry power plants. Management has not made a decision whether or not the sale of these power plants will ultimately occur and, accordingly, these assets are not classified as held for sale. However, if a decision to sell the Ferrybridge and Fiddler's Ferry power plants were made, it is likely that the fair value of the assets would be substantially below their book value at December 31, 2000. Our net investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry power plants and related debt was $918 million at December 31, 2000. 27 Commitments and Contingencies Capital Commitments The following table summarizes our consolidated capital commitments as of December 31, 2000. Details regarding these capital commitments are discussed in the sections referenced.
Type of U.S. Time Commitment Estimated Period Discussed Under ---------- --------- ------ --------------- (in millions) New Gas-Fired Generation $250 by 2003 Illinois Plants--Power Purchase Agreements New Gas-Fired Generation 346 2001-2003 Acquisition of Sunrise Project New Gas-Fired Generation 986* 2001-2004 Edison Mission Energy Master Turbine Lease Environmental Improvements at our Project Subsidiaries 557 2001-2005 Environmental Matters and Regulations Project Acquisition for the Italian Wind 17 2001-2002 Firm Commitment for Asset Purchase Equity Contribution for the Italian Wind 3 2001-2002 Firm Commitments to Contribute Project Equity
- -------- * Represents the total estimated costs related to four projects using the Siemens Westinghouse turbines procured under the Edison Mission Energy Master Turbine Lease. One of these projects may be used to meet the new gas fired generation commitments resulting from the acquisition of the Illinois Plants. See "Illinois Plants--Power Purchase Agreements." In addition, in February 2001, we purchased a 50% interest in the CBK project for $20 million. Financing for this $460 million project will require equity contributions of $117 million, of which our share is $58.5 million. See "Recent Developments." California Power Crisis We have partnership interests in eight partnerships which own power plants in California which have power purchase contracts with Pacific Gas and Electric and/or Southern California Edison. Three of these partnerships have a contract with Southern California Edison, four of them have a contract with Pacific Gas and Electric, and one of them has contracts with both. In 2000, our share of earnings before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at December 31, 2000 was $345 million. As a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities has failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the eight power plants which are owned by partnerships in which we have a partnership interest. Southern California Edison did not pay any of the amounts due to the partnerships in January, February and March of 2001 and may continue to miss future payments. Pacific Gas and Electric made its January payment in full but thus far has paid only a small portion of the amounts due to the partnerships in February and March and may not pay all or a portion of its future payments. The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay could have an adverse impact on the operations of our California qualifying facilities. Provisions in the partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be taken through the non-affiliated partner in the partnership. Therefore, partnership actions concerning the enforcement of rights under each qualifying facility's power purchase agreement with Southern California Edison in response to Southern California Edison's suspension of payments under that power purchase agreement are to be taken through the non-Edison Mission Energy affiliated partner in the partnership. Some of the partnerships have sought to minimize their exposure to 28 Southern California Edison by reducing deliveries under their power purchase agreements. It is unclear at this time what additional actions, if any, the partnerships will take in regard to the utilities' suspension of payments due to the qualifying facilities. As a result of the utilities' failure to make payments due under these power purchase agreements, the partnerships have called on the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours have made equity contributions totaling approximately $103 million to meet capital calls by the partnerships. Our subsidiaries and the other partners may be required to make additional capital contributions to the partnerships. Southern California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. Pacific Gas and Electric has taken a different approach and is seeking to invoke force majeure provisions under its power purchase agreements to excuse its failure to pay. In either case, it is possible that the utilities will not pay all their obligations in full. In addition, it is possible that Southern California Edison and/or Pacific Gas and Electric could be forced into bankruptcy proceedings. If this were to occur, payments to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, could be subject to significant delays associated with the lengthy bankruptcy court process and may not be paid in full. At February 28, 2001, accounts receivable due to these partnerships from Southern California Edison and Pacific Gas & Electric were $437 million; our share of these receivables was $217 million. Furthermore, Southern California Edison's and Pacific Gas and Electric's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court. While we believe that the generation of electricity by the qualifying facilities, including those owned by partnerships in which we have a partnership interest, is needed to meet California's power needs, we cannot assure you either that these partnerships will continue to generate electricity without payment by the purchasing utility, or that the power purchase agreements will not be adversely affected by a bankruptcy or contract renegotiation as a result of the current power crisis. A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. A proposed order of the California Public Utilities Commission would place price caps on energy delivered by qualifying facilities after the effective date of the order, and if adopted, such order may have a negative impact on our current power purchase agreements. Many of these activities are ongoing. These activities may result in a restructuring of the California power market. At this time, these activities are in their preliminary stages, and it is not possible to estimate their likely ultimate outcome. Credit Support for Trading and Price Risk Management Activities Our trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc., which is currently rated investment grade ("BBB-" by Standard and Poor's). As part of obtaining an investment grade rating for this subsidiary, we have entered into a support agreement, which commits us to contribute up to $300 million in equity to Edison Mission Marketing & Trading, if needed to meet cash requirements. An investment grade rating is an important benchmark used by third parties when deciding whether or not to enter into master contracts and trades with us. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. If Edison Mission Marketing & Trading does not maintain its investment grade rating or if other events adversely affect its financial position, a third party could request Edison Mission Marketing & Trading to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, additional guarantees, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against Edison Mission Marketing & Trading for any losses. The California power crisis has adversely affected the liquidity of West Coast trading markets, and to a lesser extent, other regions in the United States. Our trading and price risk management activity has been reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our 29 affiliate, Southern California Edison. It is not certain that resolution of the California power crisis will occur in 2001 or that, if resolved, we will be able to conduct trading and price risk management activities in a manner that will be favorable to us. Paiton The Paiton project is a 1,230 MW coal fired power plant in operation in East Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a $490 million investment in the project at December 31, 2000. The project's tariff under the power purchase agreement with PT PLN is higher in the early years and steps down over time. The tariff for the Paiton project includes costs relating to 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, PT PLN. Payments are in Indonesian Rupiah, with the portion of the payments intended to cover non-Rupiah project costs, including returns to investors, adjusted to account for exchange rate fluctuations between the Indonesian Rupiah and the U.S. dollar. The project received substantial finance and insurance support from the Export-Import Bank of the United States, the Japan Bank for International Cooperation (formerly known as The Export-Import Bank of Japan), the U.S. Overseas Private Investment Corporation and the Ministry of Economy, Trade and Industry of Japan (formerly known as the Ministry of International Trade and Industry). PT PLN's payment obligations are supported by the Government of Indonesia. 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 Paiton project's senior debt ratings have been reduced from investment grade to speculative grade based on the rating agencies' determination that there is increased risk that PT PLN might not be able to honor the power purchase agreement with P.T. Paiton Energy, the project company. The Government of Indonesia has arranged to reschedule sovereign debt owed to foreign governments and has entered into discussions about rescheduling sovereign debt owed to private lenders. In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the Paiton project had achieved commercial operation under the terms of the power purchase agreement and, in July 1999, that the second 615 MW unit of the plant had similarly achieved commercial operation. Because of the economic downturn, PT PLN was then experiencing low electricity demand and PT PLN, through February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a lawsuit contesting the validity of its agreement to purchase electricity from the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in connection with this withdrawal, the parties entered into an interim agreement for the period through December 31, 2000, under which dispatch levels and fixed and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made all fixed payments due under the interim agreement totaling $115 million and all payments due for energy delivered by the plant to PT PLN. As part of the continuing negotiations on a long-term restructuring of the tariff, Paiton Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provides for fixed monthly payments aggregating $108 million over its six month duration and for the payment for energy delivered to PT PLN from the plant during this period. Paiton Energy and PT PLN intend to complete the negotiations of the future phases of a new long-term tariff during the six month duration of the Phase I Agreement. To date, PT PLN has made all fixed and energy payments due under the Phase I Agreement. Events, including those discussed above, have occurred which may mature into defaults of the project's debt agreements following the passage of time, notice or lapse of waivers granted by the project's lenders. On October 15, 1999, the project entered into an interim agreement with its lenders pursuant to which the lenders waived defaults during the term of the agreement and effectively agreed to defer payments of principal until July 31, 2000. In July, the lenders agreed to extend the term of the lender interim agreement through December 31, 2000. In December 2000, the lenders agreed to an additional extension of the lender interim agreement through December 31, 2001. Paiton Energy has received lender approval of the Phase I Agreement. Under the terms of the power purchase agreement, PT PLN has been required to pay for capacity and fixed operating costs once each unit and the plant achieved commercial operation. As of December 31, 2000, PT PLN 30 had not paid invoices amounting to $814 million for capacity charges and fixed operating costs under the power purchase agreement. All arrears under the power purchase agreement continue to accrue, minus the fixed monthly payments actually made under the year 2000 interim agreement and under the recently agreed Phase I Agreement, with the payment of these arrears to be dealt with in connection with the overall long-term restructuring of the tariff. In this regard, under the Phase I Agreement, Paiton Energy has agreed that, so long as the Phase I Agreement is complied with, it will seek to recoup no more than $590 million of the above arrears, the payment of which is to be dealt with in connection with the overall tariff restructuring. Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new long-term tariff could require a renegotiation of the Paiton project's debt agreements. The impact of any such renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is uncertain at this time; however, we believe that we will ultimately recover our investment in the project. Brooklyn Navy Yard Brooklyn Navy Yard is a 286 MW gas fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. At this time, we cannot reasonably estimate the amount that would be due, if any, related to this litigation. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the power plant would be accounted for as an additional part of its power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of up to $10 million over an initial amount, including legal fees, payable from its management and royalty fees. At December 31, 2000, no accrual had been recorded in connection with this litigation. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations. Homer City Edison Mission Energy has guaranteed to the bondholders, banks and other secured parties which financed the acquisition of the Homer City plant the performance and payment when due by Edison Mission Holdings Co. of its obligations in respect of specified senior debt, up to $42 million. This guarantee will be available until December 31, 2001, after which time Edison Mission Energy will have no further obligations under this guarantee. To satisfy the requirements under the Edison Mission Holdings Co. bond financing to have a debt service reserve account balance in an amount equal to six months' debt service projected to be due following the payment of a distribution, Edison Mission Energy agreed to guarantee the payment and performance of the obligations of Edison Mission Holdings, in the amount of approximately $35 million, pursuant to a debt service reserve guarantee. In addition, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $3 million to the lenders involved in the bank financing. As a result of Edison Mission Energy's downgrade in January 2001, Edison Mission Holdings is in the process of finalizing the arrangement of a letter of credit of approximately $35 million to replace the bond debt service reserve guarantee. Preferred Shares of Edison Mission Energy Taupo Limited In connection with the preferred shares issued by Edison Mission Energy Taupo Limited to partially finance the acquisition of the 40% interest in Contact Energy, Edison Mission Energy provided a guaranty of 31 Edison Mission Energy Taupo Limited's obligation to pay a minimum level of non- cumulative dividends on the preferred shares through June 30, 2002, including NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts required to ensure that Edison Misison Energy Taupo Limited will satisfy two financial ratio covenants on specified dates. The first financial ratio, called a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is based on historical and projected dividends received from Contact Energy and the dividends payable to preferred shareholders. The second financial ratio, called a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based on the fair value of our Contact Energy shares and the outstanding preferred shares. If, however, Edison Mission Energy's senior unsecured credit rating by Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be called to perform on its guaranty of Edison Mission Energy Taupo Limited's financial covenants before the specified calculation dates. Based on the fair value of our ownership in Contact Energy at March 20, 2001, had Edison Mission Energy been required to perform on its guarantee of the debt to valuation ratio as of that date, Edison Mission Energy's obligation would have been approximately $19 million. Edison Mission Energy Master Turbine Lease In December 2000, we entered into a master lease and other agreements for the construction of new projects using nine turbines that are being procured from Siemens Westinghouse. The aggregate total construction cost of these projects is estimated to be approximately $986 million. Under the terms of the master lease, the lessor, as owner of the projects, is responsible for the development and construction costs of the new projects using these turbines. We have agreed to supervise the development and construction of the projects as the agent of the lessor. Upon completion of construction of each project, we have agreed to lease the projects from the lessor. In connection with the lease, we have provided a residual value guarantee to the lessor at the end of the lease term. We are required to deposit treasury notes equal to 103% of the construction costs as collateral for the lessor which can only be used under circumstances involving our default of the obligations we have agreed to perform during the construction of each project. Lease payments are scheduled to begin in November 2003. Minimum lease payments under this agreement are $3.1 million in 2003, $27.7 million in 2004, and $50.2 million in 2005. The term of the master lease ends in 2010. The master lease grants us, as lessee, a purchase option based on the lease balance which can be exercised at any time during the term. Sale-Leaseback Commitments At December 31, 2000, we had minimum lease payments related to purchased power generation assets from Commonwealth Edison that were leased back to us in three separate transactions. In connection with the 1999 acquisition of the Illinois Plants, we assigned the right to purchase the Collins gas and oil- fired power plant to third party lessors. The third party lessors purchased the Collins Station for $860 million and leased the plant to us. During 2000, we entered into sale-leaseback transactions for equipment, primarily the Illinois peaker power units, and for two power facilities, the Powerton and Joliet coal fired stations located in Illinois, to third-party lessors. Total minimum lease payments during the next five years are $146.6 million in 2001, $168.6 million in 2002, $168.6 million in 2003, $168.8 million in 2004, and $191.4 million in 2005. At December 31, 2000, the total remaining minimum lease payments were $3.9 billion. Illinois Plants--Power Purchase Agreements During 2000, 33% of our electric revenues were derived under power purchase agreements with Exelon Generation Company, a subsidiary of Exelon Corporation, entered into in connection with our December 1999 acquisition of the Illinois Plants. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major utilities located in Illinois and Pennsylvania. Electric revenues attributable to sales to Exelon Generating Company are earned from capacity and energy provided by the Illinois Plants under three five-year power purchase agreements. If Exelon Generation were to fail to or became unable to fulfill its obligations under these power purchase agreements, we may not be able to find another customer on similar terms for the output of our power generating assets. Any material failure by Exelon Generation to make payments under these power purchase agreements could adversely affect our results of operations and liquidity. 32 Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas- fired power plants having an additional gross dependable capacity of 500 MWs at existing or adjacent power plant site in Chicago. The acquisition documents require that commercial operations of this project be completed by December 15, 2003. The estimated cost to complete the construction of this 500 MW gas-fired power plant is approximately $250 million. Fuel Supply Contracts At December 31, 2000, we had contractual commitments to purchase and/or transport coal and fuel oil. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses in some cases, these minimum commitments are currently estimated to aggregate $2.4 billion in the next five years summarized as follows: 2001--$838 million; 2002--$653 million; 2003--$386 million; 2004--$308 million; 2005--$241 million. Firm Commitment for Asset Purchase
Project Local Currency U.S. ($ in millions) - ------- -------------- -------------------- Italian Wind Projects (/1/)....... 36 billion Italian Lira $17
- -------- (1) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Purchase payments will continue through 2002, depending on the number of projects that are ultimately developed. Firm Commitments to Contribute Project Equity
Projects Local Currency U.S. ($ in millions) - -------- -------------- -------------------- Italian Wind Projects (/1/)......... 6 billion Italian Lira $3
- -------- (1) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Equity will be contributed depending on the number of projects that are ultimately developed. Firm commitments to contribute project equity could be accelerated due to certain events of default as defined in the non-recourse project financing facilities. Management does not believe that these events of default will occur to require acceleration of the firm commitments. Contingent Obligations to Contribute Project Equity
Projects Local Currency U.S. ($ in millions) - -------- -------------- -------------------- Paiton (/1/)....................... -- $39 ISAB (/2/)......................... 90 billion Italian Lira 44
- -------- (1) Contingent obligations to contribute additional project equity will be based on events principally related to insufficient cash flow to cover interest on project debt and operating expenses, project cost overruns during plant construction, specified partner obligations or events of default. Our obligation to contribute contingent equity will not exceed $141 million, of which $102 million has been contributed as of December 31, 2000. As of March 16, 2001, $5 million of this amount remains to be funded. For more information on the Paiton project, see "--Paiton" above. (2) ISAB is a 512 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 49% interest. Commercial operations commenced in April 2000. Contingent obligations to contribute additional equity to the project relate specifically to an agreement to provide equity assurances to the project's lenders depending on the outcome of the contractor claim arbitration. We are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions to be made by us to meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "--California Power Crisis" above for further discussion. 33 Subsidiary Indemnification Agreements Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these indemnification agreements as of December 31, 2000, if payment were required, would be $256 million. We have no reason to believe that the projects will either terminate their performance or reduce their electric power producing capability during the term of the power contracts. Other In support of the businesses of our subsidiaries, we have made, from time to time, guarantees, and have entered into indemnity agreements with respect to our subsidiaries' obligations like those for debt service, fuel supply or the delivery of power, and have entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We may incur additional guaranty, indemnification, and reimbursement obligations, as well as obligations to make equity and other contributions to projects in the future. Market Risk Exposures Our primary market risk exposures arise from changes in interest rates, changes in oil and gas prices and electricity pool pricing and fluctuations in foreign currency exchange rates. We manage these risks in part by using derivative financial instruments in accordance with established policies and procedures. Interest Rate Risk Interest rate changes affect the cost of capital needed to finance the construction and operation of our projects. We have mitigated the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps or other hedging mechanisms for a number of our project financings. Interest expense included $16.1 million, $25.2 million and $22.8 million for the years 2000, 1999 and 1998, respectively, as a result of interest rate hedging mechanisms. We have entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt. A 10% increase in market interest rates at December 31, 2000 would result in a $17.2 million increase in the fair value of our interest rate hedge agreements. A 10% decrease in market interest rates at December 31, 2000 would result in a $17.1 million decline in the fair value of our interest rate hedge agreements. We had short-term obligations of $883.4 million consisting of commercial paper and bank borrowings at December 31, 2000. The fair values of these obligations approximated their carrying values at December 31, 2000, and would not have been materially affected by changes in market interest rates. The fair market value of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of our total long-term obligations (including current portion) was $6,999.8 million at December 31, 2000. A 10% increase in market interest rates at December 31, 2000 would result in a decrease in the fair value of total long-term obligations by approximately $96 million. A 10% decrease in market interest rates at December 31, 2000 would result in an increase in the fair value of total long-term obligations by approximately $104 million. Commodity Price Risk Electric power generated at our uncontracted plants is generally sold under bilateral arrangements with utilities and power marketers under short-term contracts with terms of two years or less, or, in the case of the Homer City plant, to the PJM or the NYISO. We have developed risk management policies and procedures which, among other things, address credit risk. When making sales under negotiated bilateral contracts, it is our policy to deal with investment grade counterparties or counterparties that provide equivalent credit support. Exceptions to the policy are granted only after thorough review and scrutiny by Edison Mission Energy's Risk Management Committee. Most entities that have received exceptions are organized power pools and 34 quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants, whose output is not committed to be sold under long-term contracts, in order to lock in desirable outcomes. When appropriate, we manage the spread between electric prices and fuel prices, and use forward contracts, swaps, futures, or options contracts to achieve those objectives. Our electric revenues were increased by $47.5 million, $60.9 million and $108.4 million in 2000, 1999 and 1998, respectively, as a result of electricity rate swap agreements and other hedging mechanisms. A 10% increase in pool prices would result in a $130.8 million decrease in the fair market value of electricity rate swap agreements. A 10% decrease in pool prices would result in a $130.5 million increase in the fair market value of electricity rate swap agreements. An electricity rate swap agreement is an exchange of a fixed price of electricity for a floating price. As a seller of power, we receive the fixed price in exchange for a floating price, like the index price associated with electricity pools. A 10% increase in electricity prices at December 31, 2000 would result in a $1.8 million decrease in the fair market value of forward contracts entered into by the Loy Yang B plant. A 10% decrease in electricity prices at December 31, 2000 would result in a $1.8 million increase in the fair market value of forward contracts entered into by Loy Yang B plant. A 10% increase in fuel oil, natural gas and electricity forward prices at December 31, 2000 would result in a $15.7 million decrease in the fair market value of energy contracts utilized by our domestic trading operations in energy trading and price risk management activities. A 10% decrease in fuel oil, natural gas and electricity forward prices at December 31, 2000 would result in a $15.7 million increase in the fair market value of energy contracts utilized by our domestic trading operations in energy trading and price risk management activities. Americas -------- On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. Our energy trading and price risk management activities give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. Market risks are actively monitored to ensure compliance with the risk management policies of Edison Mission Energy. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the reasons for the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, we supplement this approach with industry "best practice" techniques including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits. Electric power generated at the Homer City plant is sold under bilateral arrangements with domestic utilities and power marketers under short-term contracts with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets, which establish an hourly clearing price. The Homer City plant is situated in the PJM control area and is physically connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City plant can also transmit power to the midwestern United States. Electric power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company, in which Exelon Generation Company purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for Exelon Generation Company to make capacity payments for the plants under contract and energy payments for the electricity produced by these plants and taken by Exelon Generation Company. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production. If Exelon Generation Company does not fully dispatch the plants under contract, the Illinois Plants may sell, subject to specified conditions, the 35 excess energy at market prices to neighboring utilities, municipalities, third party electric retailers, large consumers and power marketers on a spot basis. A bilateral trading infrastructure already exists with access to the Mid- America Interconnected Network and the East Central Area Reliability Council. United Kingdom -------------- Our plants in the U.K. currently sell their electrical energy and capacity through a centralized electricity pool, which establishes a half-hourly clearing price, also referred to as the pool price, for electrical energy. This system has been in place since 1989 but is due to be replaced on March 27, 2001 with a bilateral physical trading system referred to as the new electricity trading arrangements. The new electricity trading arrangements are the direct result of an October 1997 request by the Minister for Science, Energy and Industry who asked the U.K. Director General of Electricity Supply to review the operation of the pool pricing system. In July 1998 the Director General proposed that the current structure of contracts for differences and compulsory trading via the pool at half-hourly clearing prices bid a day ahead be abolished. The U.K. Government accepted the proposals in October 1998 subject to reservations. Following this, further proposals were published by the Government and the Director General in July and October 1999. The proposals include, among other things, the establishment of a spot market or voluntary short-term power exchanges operating from 24 to 3 1/2-hours before a trading period; a balancing mechanism to enable the system operator to balance generation and demand and resolve any transmission constraints; a mandatory settlement process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance; and a Balancing and Settlement Code Panel to oversee governance of the balancing mechanism. Contracting over time periods longer than the day-ahead market are not directly affected by the proposals. Physical bilateral contracts will replace the current contracts for differences, but will function in a similar manner. However, it remains difficult to evaluate the future impact of the proposals. A key feature of the new electricity trading arrangements is to require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery, against their contracted positions or face assessment of energy imbalance penalty charges by the system operator. A consequence of this should be to increase greatly the motivation of parties to contract in advance and develop forwards and futures markets of greater liquidity than at present. Recent experience has been that the new electricity trading arrangements have placed a significant downward pressure on forward contract prices. Furthermore, another consequence may be that counterparties may require additional credit support, including parent company guarantees or letters of credit. Legislation in the form of the Utilities Act, which was approved July 28, 2000, allows for the implementation of new electricity trading arrangements and the necessary amendments to generators' licenses. Various key documents were designated by the Secretary of State and signed by participants on August 14, 2000 (the Go-Active Date); however, due to difficulties encountered during testing, implementation of the new electricity trading arrangements has been delayed from November 21, 2000 until March 27, 2001. The Utilities Act sets a principal objective for the Government and the Director General to "protect the interests of consumers . . . where appropriate by promoting competition . . .". This represents a shift in emphasis toward the consumer interest. But this is qualified by a recognition that license holders should be able to finance their activities. The Act also contains new powers for the Government to issue guidance to the Director General on social and environmental matters, changes to the procedures for modifying licenses and a new power for the Director General to impose financial penalties on companies for breach of license conditions. We will be monitoring the operation of these new provisions. See "--Financing Plans." Asia Pacific ------------ Australia The Loy Yang B plant sells its electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the 36 pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant 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 was 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, 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. The parties to the vesting contracts make payments, which are 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. Vesting contracts were sold in various structures and accounted for as electricity rate swap agreements. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2001 to July 2014, approximately 77% of the plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant entered into a number of fixed forward electricity contracts commencing January 1, 2001, which expire either on January 1, 2002 or January 1, 2003, and which will further mitigate against the price volatility of the electricity pool. New Zealand The New Zealand Government has been undergoing a steady process of electric industry deregulation since 1987. Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity distribution and provided for competition in the retail electric supply function. The New Zealand Energy Market, established in 1996, is a voluntary competitive wholesale market which allows for the trading of physical electricity on a half-hourly basis. The Electricity Industry Reform Act, which was passed in July 1998, was designed to increase competition at the wholesale generation level by splitting up Electricity Company of New Zealand Limited, the large state-owned generator, into three separate generation companies. The Electricity Industry Reform Act also prohibits the ownership of both generation and distribution assets by the same entity. The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. This Inquiry Board's report was presented to the government in mid 2000. The main focus of the report was on the monopoly segments of the industry, transmission and distribution, with substantial limitations being recommended in the way in which these segments price their services in order to limit their monopoly power. Recommendations were also made with respect to the retail customer in order to reduce barriers to customers switching. In addition, the Board made recommendations in relation to the wholesale market's governance arrangements with the purpose of streamlining them. The recommended changes are now being progressively implemented. Foreign Exchange Rate Risk Fluctuations in foreign currency exchange rates can affect, on a United States dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. As we continue to expand into foreign markets, fluctuations in foreign currency exchange rates can be expected to have a greater impact on our results of operations in the future. At times, we have hedged a portion of our current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to United States dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, we have used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We cannot assure you, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or forecasted relationships. Foreign exchange considerations for three major international projects, other than Paiton which was discussed earlier, are discussed below. 37 The First Hydro, Ferrybridge and Fiddler's Ferry plants in the U.K. and the Loy Yang B plant in Australia have been financed in their local currency, pounds sterling and Australian dollars, respectively, thus hedging the majority of their acquisition costs against foreign exchange fluctuations. Furthermore, we have evaluated the return on the remaining equity portion of these investments with regard to the likelihood of various foreign exchange scenarios. These analyses use market derived volatilities, statistical correlations between specified variables, and long-term forecasts to predict ranges of expected returns. Foreign currencies in the U.K., Australia and New Zealand decreased in value compared to the U.S. dollar by 7%, 15% and 15%, respectively (determined by the change in the exchange rates from December 31, 1999 to December 31, 2000). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $157.3 million during 2000. A 10% increase or decrease in the exchange rate at December 31, 2000 would result in foreign currency translation gains or losses of $196.7 million. In December 2000, we entered into foreign currency forward exchange contracts in the ordinary course of business to protect ourselves from adverse currency rate fluctuations on anticipated foreign currency commitments with varying maturities ranging from January 2001 to July 2002. The periods of the forward exchange contracts correspond to the periods of the hedged transactions. At December 31, 2000, the outstanding notional amount of the contracts totaled $91 million, consisting of contracts to exchange U.S. dollars to pound sterling. A 10% fluctuation in exchange rates would change the fair value of the contracts at December 31, 2000 by approximately $6 million. We will continue to monitor our foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future. Other The electric power generated by some of our investments in domestic operating projects, excluding the Homer City plant and the Illinois Plants, is sold to electric utilities under long-term contracts, typically with terms of 15 to 30-years. We structure our long-term contracts so that fluctuations in fuel costs will produce similar fluctuations in electric and/or steam revenues and enter into long-term fuel supply and transportation agreements. The degree of linkage between these revenues and expenses varies from project to project, but generally permits the projects to operate profitably under a wide array of potential price fluctuation scenarios. Environmental Matters and Regulations We are subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over projects located outside the United States. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings which may be taken by environmental authorities, could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. We cannot assure you that we would be able to recover these increased costs from our customers or that our financial position and results of operations would not be materially adversely affected. Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. We expect that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in increased capital expenditures and operating expenses. For example, we expect to spend approximately $67 million in 2001 to install upgrades to the environmental 38 controls at the Homer City plant to control sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental controls at the Illinois Plants to control nitrogen oxide emissions to result in expenditures of approximately $61 million, $67 million, $130 million, $123 million and $57 million for 2001, 2002, 2003, 2004 and 2005, respectively. Provisions related to nonattainment, air toxins, permitting of new and existing units, enforcement and acid rain may affect our domestic plants; however, final details of all these programs have not been issued by the United States Environmental Protection Agency and state agencies. In addition, at the Ferrybridge and Fiddler's Ferry plants we anticipate environmental costs arising from plant modification of approximately $52 million for the 2001-2005 period. We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoElectrica a notice of violation and a compliance order alleging violations of the federal Clean Air Act primarily related to start-up activities. Representatives of EcoElectrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoElectrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action will be taken by the Environmental Protection Agency. On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's "new source review" requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's new source review requirements. To date, one utility, the Tampa Electric Company, has reached a formal agreement with the United States to resolve alleged new source review violations. Two other utilities, the Virginia Electric & Power Company and Cinergy Corp., have reached agreements in principle with the Environmental Protection Agency. In each case, the settling party has agreed to incur over $1 billion in expenditures over several years for the installation of additional pollution control, the retirement or repowering of coal fired generating units, supplemental environmental projects and civil penalties. These agreements provide for a phased approach to achieving required emission reductions over the next 10-15 years. The settling utilities have also agreed to pay civil penalties ranging from $3.5 million to $8.5 million. Prior to our purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. Other than with respect to the Homer City plant, no proceedings have been initiated or requests for information issued with respect to any of our United States facilities. However, we have been in informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. We cannot assure you that we will reach a satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the proceedings, we could be required to invest in additional pollution control requirements, over and above the upgrades we are planning to install, and could be subject to fines and penalties. A new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been 39 identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the EPA to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard on our facilities is uncertain at this time. On December 20, 2000, the Environmental Protection Agency issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum available control technology" standards will be developed. Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by us or our affiliates in the United States. This section of the Clean Air Act provides only for technology-based standards, and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and we cannot evaluate the potential impact on the operations of our facilities. Since the adoption of the United Nations Framework on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton Administration participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels. However, because of opposition to the treaty in the United States Senate, the Kyoto Protocol has not been submitted to the Senate for ratification. Although legislative developments at the federal and state level related to controlling greenhouse gas emissions are beginning, we are not aware of any state legislative developments in the states in which we operate. If the United States ratifies the Kyoto Protocol or we otherwise become subject to limitations on emissions of carbon dioxide from our plants, these requirements could have a significant impact on our operations. The Comprehensive Environmental Response, Compensation, and Liability Act, which is also known as CERCLA, and similar state statutes, require the cleanup of sites from which there has been a release or threatened release of hazardous substances. We are unaware of any material liabilities under this act; however, we can not assure you that we will not incur CERCLA liability or similar state law liability in the future. New Accounting Standards Effective January 1, 2001, Edison Mission Energy adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings. Effective January 1, 2001, we will record all derivatives at fair value unless the derivatives qualify for the normal sales and purchases exception. We expect that the portion of our business activities related to physical 40 sales and purchases of power or fuel and those similar business activities of our affiliates will qualify for this exception. We expect the majority of our risk management activities will qualify for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income. In the United Kingdom, we expect that the majority of our activities related to the Fiddler's Ferry, Ferrybridge and First Hydro power plants will not qualify for either the normal purchases and sales exception or as cash flow hedges. Accordingly, we expect the majority of these contracts will be recorded at fair value, with subsequent changes in fair value recorded through the income statement. As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under our prior accounting policy. The cumulative effect on prior years' net income resulting from the change in accounting for derivatives in accordance with SFAS No. 133 is expected to be less than $10 million, net of tax. Recent Developments In February 2001, we completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25- year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project has been completed with equity contributions of $117 million (our 50% share is $58.5 million) required to be made upon completion of the rehabilitation and expansion, currently scheduled for 2003, and debt financing has been arranged for the remainder of the cost for this project. 41 -----END PRIVACY-ENHANCED MESSAGE-----