424B3 1 d424b3.txt EDISON MISSION ENERGY FILED PURSUANT TO RULE 424(b)(3) REGISTRATION NUMBER 333-59468 PROSPECTUS Offer to Exchange $600 Million 9.875% Senior Notes due April 15, 2011 for $600 Million 9.875% Senior Notes due April 15, 2011, which Have Been Registered Under the Securities Act of 1933, of [LOGO OF EDISON MISSION ENERGY] The exchange offer will expire at 5:00 P.M., New York City time, on June 6, 2001, unless extended. ---------------- Terms of the exchange offer: . The new notes are being registered with the Securities and Exchange Commission and are being offered in exchange for the original notes that were previously issued in an offering exempt from the Securities and Exchange Commission's registration requirements. The terms of the exchange offer are summarized below and more fully described in this prospectus. . We will exchange all original notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer. . You may withdraw tenders of original notes at any time prior to the expiration of the exchange offer. . We believe that the exchange of original notes will not be a taxable event for U.S. federal income tax purposes, but you should see "Material United States Federal Income Tax Considerations" on page 96 for more information. . We will not receive any proceeds from the exchange offer. . The terms of the exchange notes are substantially identical to the original notes, except that the exchange notes are registered under the Securities Act and the transfer restrictions and registration rights applicable to the original notes do not apply to the exchange notes. ---------------- See "Risk Factors" beginning on page 8 for a discussion of the risks that should be considered by holders prior to tendering their original notes.
=============================================================================== Principal Amount Annual Interest Rate Final Distribution Date ------------------------------------------------------------------------------- $600,000,000 9.875% April 15, 2011 ===============================================================================
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense. ---------------- The date of this prospectus is May 4, 2001. TABLE OF CONTENTS
Page ---- Forward-Looking Statements............................................... i Available Information.................................................... i Incorporation of Documents by Reference.................................. ii Notice to New Hampshire Residents........................................ ii Prospectus Summary....................................................... 1 Risk Factors............................................................. 8 Use of Proceeds.......................................................... 17 Capitalization........................................................... 17 Selected Consolidated Financial Data..................................... 18 The Exchange Offer....................................................... 19 Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 27 Business................................................................. 56 Management............................................................... 84 Description of the Notes................................................. 86 Exchange Offer; Registration Rights...................................... 95 Material United States Federal Income Tax Considerations................. 96 Plan of Distribution..................................................... 98 Legal Matters............................................................ 99 Experts.................................................................. 99
i FORWARD-LOOKING STATEMENTS This prospectus includes forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events based upon our knowledge of facts as of the date of this prospectus and our assumptions about future events. 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 on 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," "projected," "plan," "expect," "will," "believe," "intend," "may," "should" and similar expressions to help identify forward-looking statements in this prospectus. For additional factors that could affect the validity of our forward-looking statements, you should read "Risk Factors" beginning on page 8. In light of these and other risks, uncertainties and assumptions, actual events or results may be very different from those expressed or implied in the forward-looking statements in this prospectus, or may not occur. We have no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. AVAILABLE INFORMATION We are subject to the informational requirements of the Securities Exchange Act of 1934 and, in accordance with these requirements, file reports and information statements and other information with the Securities and Exchange Commission. These reports and information statements and other information filed by us with the SEC can be inspected and copied at the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the SEC located at Seven World Trade Center, 13th Floor, New York, New York 10048 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of this material can be obtained from the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a Web site that contains reports, proxy and information statements and other materials that are filed through the SEC's Electronic Data Gathering, Analysis and Retrieval (EDGAR) system. This Web site can be accessed at http://www.sec.gov. i This prospectus constitutes a part of a registration statement on Form S-4 filed by us with the SEC under the Securities Act. As permitted by the rules and regulations of the SEC, the prospectus does not contain all the information contained in the registration statement and the exhibits and schedules to the registration statement. Reference is made to the registration statement and its exhibits and schedules for further information with respect to us and the securities offered through this exchange offer. Statements contained in this prospectus concerning the provisions of any documents filed as an exhibit to the registration statement or otherwise filed with the SEC are not necessarily complete, and in each instance reference is made to the copy of the document so filed. Each of those statements is qualified in its entirety by reference to that document. INCORPORATION OF DOCUMENTS BY REFERENCE The following documents filed with the SEC are incorporated by reference into this prospectus: (i) Our Annual Report on Form 10-K for the year ended December 31, 2000; and (ii) Our Current Report on Form 8-K, dated March 22, 2001. All reports and other documents we subsequently file under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this prospectus and prior to the date on which the exchange offer described in this prospectus is terminated shall be deemed to be incorporated by reference into this prospectus and to be part of this prospectus from the date we subsequently file these reports and documents. Copies of our Annual Report on Form 10-K for the year ended December 31, 2000 and the Current Report on Form 8-K, dated March 22, 2001, are available, without charge, from us. You may request a copy of any of these filings, at no cost, by writing or telephoning us at the following address or phone number: Edison Mission Energy 18101 Von Karman Avenue, Suite 1700 Irvine, California 92612 (949) 752-5588 Attention: Corporate Secretary IN ORDER TO OBTAIN TIMELY DELIVERY, YOU MUST REQUEST THIS INFORMATION NO LATER THAN 5 BUSINESS DAYS BEFORE YOU MAKE YOUR INVESTMENT DECISION. Any statement contained in a document incorporated by reference in this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus modifies or supersedes this statement. Any statement so modified or superseded will not be deemed to constitute a part of this prospectus except as so modified or superseded. ---------------- NOTICE TO NEW HAMPSHIRE RESIDENTS NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH. ---------------- ii PROSPECTUS SUMMARY The following summary highlights selected information from this prospectus and may not contain all of the information that is important to you. This prospectus includes specific terms of the exchange notes we are offering, as well as information regarding our business and detailed financial data. We encourage you to read this prospectus in its entirety. You should pay special attention to the "Risk Factors" section beginning on page 8 of this prospectus. Summary of the Exchange Offer On April 5, 2001, we completed the private offering of $600 million aggregate principal amount of 9.875% Senior Notes due April 15, 2011. As part of that offering, we entered into a registration rights agreement with the initial purchasers of these original notes in which we agreed, among other things, to deliver this prospectus to you and to complete an exchange offer for the original notes. Below is a summary of the exchange offer. Securities Offered.................. Up to $600,000,000 aggregate principal amount of new 9.875% Senior Notes due April 15, 2011, which have been registered under the Securities Act. The form and terms of these exchange notes are identical in all material respects to those of the original notes. The exchange notes, however, will not contain transfer restrictions and registration rights applicable to the original notes. The Exchange Offer.................. We are offering to exchange new $1,000 principal amount of our 9.875% Senior Notes due April 15, 2011, which have been registered under the Securities Act, for $1,000 principal amount of our outstanding 9.875% Senior Notes due April 15, 2011. In order to be exchanged, an original note must be properly tendered and accepted. All original notes that are validly tendered and not withdrawn will be exchanged. As of the date of this prospectus, there are $600 million principal amount of original notes outstanding. We will issue exchange notes promptly after the expiration of the exchange offer. Resales............................. Based on interpretations by the staff of the SEC, as detailed in a series of no- action letters issued by the SEC to third parties, we believe that the exchange notes issued in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery requirements of the Securities Act as long as: . you are acquiring the exchange notes in the ordinary course of your business; . you are not participating, do not intend to participate and have no arrangement or understanding with any person to participate, in a distribution of the exchange notes; and . you are not an "affiliate" of ours.
1 If you are an affiliate of ours, are engaged in or intend to engage in or have any arrangement or understanding with any person to participate in the distribution of the exchange notes: (1) you cannot rely on the applicable interpretations of the staff of the SEC; and (2) you must comply with the registration requirements of the Securities Act in connection with any resale transaction. Each broker or dealer that receives exchange notes for its own account in exchange for original notes that were acquired as a result of market- making or other trading activities must acknowledge that it will comply with the registration and prospectus delivery requirements of the Securities Act in connection with any offer to resell, resale, or other transfer of the exchange notes issued in the exchange offer, including the delivery of a prospectus that contains information with respect to any selling holder required by the Securities Act in connection with any resale of the exchange notes. Furthermore, any broker-dealer that acquired any of its original notes directly from us: . may not rely on the applicable interpretation of the staff of the SEC's position contained in Exxon Capital Holdings Corp., SEC no- action letter (April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no- action letter (July 2, 1983); and . must also be named as a selling noteholder in connection with the registration and prospectus delivery requirements of the Securities Act relating to any resale transaction. Expiration Date.......................... 5:00 p.m., New York City time, on June 6, 2001 unless we extend the expiration date. Accrued Interest on the Exchange Notes and Original Notes ..................... The exchange notes will bear interest from the most recent date to which interest has been paid on the original notes. If your original notes are accepted for exchange, then you will receive interest on the exchange notes and not on the original notes. Conditions to the Exchange Offer ........ The exchange offer is subject to customary conditions. We may assert or waive these conditions in our sole discretion. If we materially change the terms of the exchange offer, we will resolicit tenders of the original notes. See "The Exchange Offer--Conditions to the Exchange Offer" for more information regarding conditions to the exchange offer. Procedures for Tendering Original Notes.. Except as described in the section titled "The Exchange Offer-- Guaranteed Delivery Procedures," a tendering holder must, on or prior to the expiration date: . transmit a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal, to United States Trust Company of New York at the address listed in this prospectus; or
2 . if original notes are tendered in accordance with the book-entry procedures described in this prospectus, the tendering holder must transmit an agent's message to the exchange agent at the address listed in this prospectus. See "The Exchange Offer--Procedures for Tendering." Special Procedures for Beneficial Holders............................ If you are the beneficial holder of original notes that are registered in the name of your broker, dealer, commercial bank, trust company or other nominee, and you wish to tender in the exchange offer, you should promptly contact the person in whose name your original notes are registered and instruct that person to tender on your behalf. See "The Exchange Offer--Procedures for Tendering." Guaranteed Delivery Procedures...... If you wish to tender your original notes and you cannot deliver your notes, the letter of transmittal or any other required documents to the exchange agent before the expiration date, you may tender your original notes by following the guaranteed delivery procedures under the heading "The Exchange Offer-- Guaranteed Delivery Procedures." Withdrawal Rights................... Tenders may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date. Acceptance of Original Notes and Delivery of Exchange Notes......... Subject to the conditions stated in the section "The Exchange Offer--Conditions to the Exchange Offer" of this prospectus, we will accept for exchange any and all original notes which are properly tendered in the exchange offer before 5:00 p.m., New York City time, on the expiration date. The exchange notes will be delivered promptly after the expiration date. See "The Exchange Offer--Terms of the Exchange Offer." Material United States Federal Income Tax Considerations.......... We believe that your exchange of original notes for exchange notes to be issued in connection with the exchange offer will not result in any gain or loss to you for U.S. federal income tax purposes. See "Material United States Federal Income Tax Considerations." Exchange Agent...................... United States Trust Company of New York is serving as exchange agent in connection with the exchange offer. The address and telephone number of the exchange agent are listed under the heading "The Exchange Offer--Exchange Agent." Use of Proceeds..................... We will not receive any proceeds from the issuance of exchange notes in the exchange offer. We will pay all expenses incident to the exchange offer. See "Use of Proceeds" and "--The Company--Recent Developments--Offering of Original Notes."
3 Summary of Terms of the Exchange Notes The form and terms of the exchange notes and the original notes are identical in all material respects, except that transfer restrictions and registration rights applicable to the original notes do not apply to the exchange notes. The exchange notes will evidence the same debt as the original notes and will be governed by the same indenture. Where we refer to "notes" in this document, we are referring to both original notes and exchange notes. Exchange Notes Offered.............. Up to $600 million principal amount of 9.875% Senior Notes due April 15, 2011. Maturity............................ April 15, 2011. Interest............................ Interest accrues on the principal amount of the notes at 9.875% per year. Interest is payable on the notes, and distributions will be made semi-annually in arrears on April 15 and October 15 of each year. The first payment will be made on October 15, 2001. Ranking............................. The notes are senior unsecured obligations of ours and rank equally with all of our senior unsecured indebtedness and rank senior to our subordinated indebtedness. All existing and future liabilities of our subsidiaries will be effectively senior to the notes. The indenture permits us to incur significant additional indebtedness. See "Description of the Notes." Ratings............................. The notes are currently rated "BBB-" by Standard & Poor's Ratings Services and "Baa3" by Moody's Investors Service, Inc. Optional Redemption................. We may redeem any or all of the notes at a redemption price equal to the greater of: . 100% of the principal amount of the notes being redeemed; or . the sum of the present values of the remaining scheduled payments on the notes being redeemed discounted at a rate based on the rates of U.S. Treasury securities with average lives comparable to the remaining lives of the notes plus 75 basis points; plus accrued and unpaid interest on the notes being redeemed.
4 The Company Edison Mission Energy 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 megawatts (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. Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities were the only producers of bulk electric power intended for sale to third parties in the United States. The Public Utility Regulatory Policies Act encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers, qualifying facilities, under certain conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent power producers, such as us, has developed in the United States since the enactment of the Public Utility Regulatory Policies Act. In 1998, utility deregulation in several states led utilities to divest generating assets, which has created new opportunities for growth of independent power in the United States. The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity in developing countries have also led to the development of significant new markets for independent power producers outside the United States. We believe that we are well-positioned to continue to realize opportunities in these new foreign markets. See "--Strategic Overview." Strategic Overview Our business goal is to be one of the leading owners and operators of electric generating assets in the world. We play an active role, as a long-term owner, in all phases of power generation, from planning and development through construction and commercial operation. We believe that this involvement allows us to better ensure, with our experienced personnel, that our projects are well-planned, structured and managed, thus maximizing value creation. We have separate strategies for developed and developing countries. In developed countries, our strategy focuses on enhancing the value of existing assets, expanding plant capacity at existing sites and developing new projects in locations where we have an established position or otherwise determine that attractive financial performance can be realized. In addition, because a number of our projects in developed countries, known as merchant plants, sell power into markets without the certainty of long-term contracts, we conduct power marketing, trading, and risk management activities to stabilize and enhance the financial performance of these projects. We also recognize that our principal customers are regulated utilities. We therefore strive to understand the regulatory and economic environment in which the utilities operate so that we may continue to create mutually beneficial relationships and business dealings. 5 In developing countries, our strategy focuses on investing with strategic partners, securing limited recourse financing based upon long-term power purchase agreements with state owned utilities and securing government financial support from organizations such as the Export-Import Bank of the United States, the U.S. Overseas Private Investment Corporation and the Japan Bank for International Cooperation. In addition, for some projects, we have obtained political risk insurance from private companies. In making investment decisions, we evaluate potential project returns against our internally generated rate of return guidelines. We establish these guidelines by identifying a base rate of return and adjusting the base rate by potential risk factors, such as risks associated with project location and stage of project development. We endeavor to mitigate these risks by (i) evaluating all projects and the markets in which they operate, (ii) selecting strategic partners with complementary skills and local experience, (iii) structuring investments through subsidiaries, (iv) managing up front development costs, (v) utilizing limited recourse financing and (vi) linking revenue and expense components where appropriate. In response to the increasing globalization of the independent power market, we have organized our operation and development activities into three geographic regions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia, Middle East and Africa. Each region is served by one or more teams consisting of business development, operations, finance and legal personnel, and each team is responsible for all our activities within a particular geographic region. Also, we mobilize personnel from outside a particular region when needed in order to assist in the development of specified projects. Recent Developments Offering of Original Notes On April 5, 2001, we issued and sold the original notes. We used a portion of the net proceeds of that offering, which were approximately $571 million, to repay indebtedness. See "Use of Proceeds." ---------------- We are incorporated under the laws of the State of California. Our headquarters and principal executive offices are located at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612, and our telephone number is (949) 752-5588. 6 Summary Consolidated Financial Data The following table sets forth a summary of our consolidated financial data for the periods indicated. The summary consolidated financial data were derived from the audited consolidated financial statements of Edison Mission Energy and our consolidated subsidiaries. This summary is qualified in its entirety by the more detailed information and financial statements, including the notes to that information and those financial statements, included in the documents incorporated by reference in this prospectus.
Years Ended December 31, -------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- (in millions) Income Statement Data Operating revenues......... $ 3,241.0 $ 1,635.9 $ 893.8 $ 975.0 $ 843.6 Operating expenses......... 2,410.2 1,209.5 543.3 581.1 476.5 --------- --------- -------- -------- -------- Operating income........... 830.8 426.4 350.5 393.9 367.1 Interest expense........... (721.5) (375.5) (196.1) (223.5) (164.2) Interest and other income.. 74.0 55.8 50.9 53.9 40.7 Minority interest.......... (3.2) (3.0) (2.8) (38.8) (69.5) --------- --------- -------- -------- -------- Income before income taxes..................... 180.1 103.7 202.5 185.5 174.1 Provision (benefit) for income taxes.............. 72.5 (40.4) 70.4 57.4 82.0 --------- --------- -------- -------- -------- Income before accounting change and extraordinary loss...................... 107.6 144.1 132.1 128.1 92.1 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................... -- -- -- (13.1) -- --------- --------- -------- -------- -------- Net income................. $ 125.3 $ 130.3 $ 132.1 $ 115.0 $ 92.1 ========= ========= ======== ======== ======== As of December 31, -------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- (in millions) Balance Sheet Data Assets..................... $15,017.1 $15,534.2 $5,158.1 $4,985.1 $5,152.5 Current liabilities........ 3,911.0 1,772.8 358.7 339.8 270.9 Long-term obligations...... 5,334.8 7,439.3 2,396.4 2,532.1 2,419.9 Preferred securities of subsidiaries.............. 326.8 476.9 150.0 150.0 150.0 Shareholder's equity....... 2,948.2 3,068.5 957.6 826.6 1,019.9 Years Ended December 31, -------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- Other Data Ratio of earnings to fixed charges(/1/).............. 1.23 1.18 1.69 1.64 1.42
-------- (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. 7 RISK FACTORS In addition to the information contained elsewhere in this prospectus, the following risk factors should be carefully considered in evaluating the exchange offer and an investment in the notes. The following risk factors, other than "--You may have difficulty selling the notes that you do not exchange," generally apply to the original notes as well as the exchange notes. The current California power crisis has had, and may continue to have, an adverse impact on us. Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of the three major utilities, Southern California Edison and Pacific Gas and Electric Co., have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers and others. On April 6, 2001, Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court. On April 9, 2001, Edison International and Southern California Edison signed a memorandum of understanding with the California Department of Water Resources which calls for legislation, regulatory action and definitive agreements to resolve important aspects of the energy crisis, and which the parties expect will help restore Southern California Edison's creditworthiness and liquidity. Nevertheless, given Southern California Edison's payment defaults, creditors of Southern California Edison could file an involuntary bankruptcy petition against it. For more information on the current regulatory situation in California, see "Business--Regulatory Matters--California Deregulation." For more information on how the current California power crisis affects our investments in energy projects in California, see "--The current California power crisis has had, and may continue to have, an adverse impact on our California partnership investments." Southern California Edison's current financial condition has had, and may continue to have, an adverse impact on Edison International's credit quality and, as previously reported by Edison International, has resulted in cross- defaults under Edison International's credit facilities. Both Standard & Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the credit ratings of Edison International and Southern California Edison to substantially below investment grade levels. The ratings remain under review for potential downgrade by both Standard & Poor's and Moody's. 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 our respective investment grade credit ratings, on January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity in spite of 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 either of the following are true: . we then have an investment grade credit 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 then 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. 8 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, after we implemented the ring- fencing amendments, 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 credit ratings outlook for us is stable. As a result of the downgrades, our cost of capital has increased. Future downgrades could further increase our cost of capital, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries. For more information on the effect of further downgrades, see "--Ratings of the notes and our credit ratings are subject to change, and a downgrade of our credit rating below investment grade could have an adverse impact on us." On March 15, 2001, the California Public Utilities Commission released a draft of a proposed order instituting an investigation into whether California's investor-owned utilities, including Southern California Edison, have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. The proposed order would reopen the past holding company decisions and initiate an investigation into the following matters: . whether the holding companies, including Edison International, violated requirements to give priority to the capital needs of their respective utility subsidiaries; . whether the ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries; . whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies; . any additional suspected violations of laws or Commission rules and decisions; and . whether additional rules, conditions, or other changes to the holding company decisions are necessary. A prehearing conference was held on April 20, 2001, at which the parties were asked to inform the Commission of their view of the impact of the recently signed memorandum of understanding among Southern California Edison, Edison International and the California Department of Water Resources on specified issues from the order, how to expedite resolution of those issues, and how to conduct the remainder of the investigation to the extent other issues and other parties are not affected. See "Business--Regulatory Matters-- California Deregulation--The Current Power Crisis in California." At this prehearing conference, no definitive rulings were made on any issue in the investigation, including the Commission's resolution of the investigation, as called for in the memorandum of understanding. Several parties, including Edison International, raised objections to the Commission's assertion of jurisdiction over utility holding companies. The Commission is expected to issue a further ruling concerning the scope and scheduling of the investigation and also to schedule a further prehearing conference. We cannot predict whether the Commission will institute this investigation or what effects any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us. The current California power crisis has had, and may continue to have, an adverse impact on our California partnership investments. 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. 9 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 amount due to the partnerships in January, February and March 2001 and may continue to miss future payments. However, on April 17, 2001, Southern California Edison made its April payment to the partnerships. Pacific Gas and Electric made its January payment in full and has paid for post-petition deliveries during the first half of April, but paid only a small portion of the amounts due to the partnerships in February and March and, as discussed below, may not pay all or a portion of its future payments. At March 31, 2001, accounts receivable due to these partnerships from Southern California Edison were $472 million and from Pacific Gas and Electric were $59 million. Our share of these receivables was $234 million and $29 million, respectively. On April 6, 2001, Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court. Although Pacific Gas and Electric has paid for post-petition deliveries during the first half of April, future payments by Pacific Gas and Electric to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, may be subject to significant delays associated with the bankruptcy court process and may not be paid in full. Furthermore, Pacific Gas and Electric's power purchase agreements with the qualifying facilities will be subject to review by the bankruptcy court. We cannot assure you that the partnerships with contracts with Pacific Gas and Electric will not be adversely affected by the bankruptcy proceeding. See "Business--Regulatory Matters-- California Deregulation--The Current Power Crisis in California." The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly 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 Southern California Edison by reducing deliveries under their power purchase agreements. Three of the partnerships have filed complaints requesting, among other things, a declaration that they are entitled to suspend delivery of capacity and energy to Southern California Edison, and to resell such capacity and energy to other purchasers, so long as Southern California Edison does not pay amounts due under its power purchase agreement and until Southern California Edison establishes that it is creditworthy and able to make future payments when due. 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 31, 2001, subsidiaries of ours have made equity contributions totaling approximately $115 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. However, it is possible that Southern California Edison will not pay all its obligations in full. In addition, it is possible that creditors of Southern California Edison could file an involuntary bankruptcy petition against Southern California Edison. 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. Furthermore, Southern California Edison's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court. 10 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. On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. As a result of this decision, Southern California Edison made its April payment in full, and Pacific Gas and Electric made its April payment in part and indicated that it intends to pay the remainder by the end of April. In addition, the decision modified the pricing formula for determining short run avoided costs for qualifying facilities subject to these provisions. Depending on the utilities' continued reaction to this order, the impact of this decision may be that the qualifying facilities subject to this pricing adjustment will be paid significantly reduced prices for their power. Furthermore, this decision called for further study of the pricing formula tied to short run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this recent decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001. 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. 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. For more information on the current regulatory situation in California, see "Business--Regulatory Matters--California Deregulation-- Deregulation Plan." The situation in California changes on an almost daily basis. You should monitor developments in California before investing in the exchange notes, as the discussion in this prospectus may be overtaken by events. We have a substantial amount of indebtedness, including a substantial amount of short-term indebtedness. As of December 31, 2000, we had $2.1 billion of debt which was recourse to Edison Mission Energy and $5.9 billion of debt which was non-recourse to Edison Mission Energy but was recourse to our subsidiaries appearing on our consolidated balance sheet. The indenture governing the notes does not impose limitations on our ability or the ability of our subsidiaries to incur additional indebtedness. Edison Mission Energy has a substantial amount of short-term debt that will need to be extended or refinanced. Edison Mission Energy has two credit facilities, in a total amount of $850 million, that are scheduled to expire in May 2001 and one credit facility, in the amount of $425 million, that is scheduled to expire in October 2001. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financing Plans." We cannot assure you that we will be able to extend our existing credit facilities or obtain new credit facilities to finance our needs, or that any new credit facility can be obtained under similar terms and rates as our existing credit facilities. If we cannot extend our existing credit facilities or obtain new credit facilities to finance our needs on similar terms and rates as our existing credit facilities, this could have a negative impact on our liquidity and on our ability to make debt service payments on the notes. 11 Our substantial amount of debt and financial obligations presents the risk that we might not have sufficient cash to service our indebtedness, including the notes, and that our existing corporate and project debt could limit our ability to finance the acquisition and development of additional projects, to compete effectively or to operate successfully under adverse economic conditions. See "Capitalization" and "Selected Consolidated Financial Data." Ratings of the notes and our credit ratings are subject to change, and a downgrade of our credit rating below investment grade could have an adverse impact on us. Standard & Poor's and Moody's have assigned ratings to the notes of "BBB-" and "Baa3", respectively. A rating is not a recommendation to purchase, hold or sell notes, because a rating does not address market price or suitability for a particular investor. We cannot assure you that a rating will remain for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. 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; . 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 Caliraya-Botocan-Kalayaan (CBK) hydroelectric project in the Philippines; and . repay a portion of the preferred shares issued by our subsidiary in connection with its 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, would 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. Furthermore, a downgrade in our credit rating could adversely affect our ability to make debt service payments on the notes. Our ability to meet cash requirements depends upon the performance of our subsidiaries. The notes are exclusively obligations of Edison Mission Energy and are not the obligations of any of our subsidiaries. Because substantially all our operations are conducted by our project subsidiaries, our cash flow and ability to service our indebtedness or otherwise meet our financial obligations, including our ability to pay the interest on, and principal of, the notes when due, are dependent upon the ability of our subsidiaries to pay dividends and make distributions to us. As mentioned above, the California power crisis has had, and may continue to have, an adverse impact on our California partnership investments and may adversely affect our ability to receive distributions from these investments. Financing agreements for our subsidiaries and affiliates generally place limitations on the ability of those subsidiaries and affiliates to pay dividends, make distributions or otherwise transfer funds to us. In addition, financing agreements for our subsidiaries and affiliates are generally secured and contain some representations, warranties, covenants and other agreements that, if not met, could lead to a default under those agreements. After a default under a project financing for any reason, project lenders may exercise rights and remedies typically granted to secured parties, including the ability to 12 take control of the project's collateral assets and/or our ownership interest in the project company. In addition, we own a minority interest in some of our projects, and so are unable unilaterally to cause dividends or distributions to be made to us from those projects. Lastly, many of our projects are located overseas and, therefore, distributions from foreign operations, if needed, would likely be subject to additional taxes in the United States upon repatriation. Accordingly, we cannot assure you that we will receive sufficient distributions from our subsidiaries to pay debt service on the notes when due. Any right of ours to receive any assets of any of our subsidiaries upon any liquidation or reorganization of a subsidiary, and the consequent right of holders of the notes to participate in the distribution of, or to realize proceeds from, those assets, will be effectively subordinated to the claims of the subsidiary's creditors, including trade creditors and holders of debt incurred by the subsidiary. One of our subsidiaries, Edison First Power, is not in compliance with a required financial ratio and other requirements under the financing documents related to the acquisition of the Fiddler's Ferry and Ferrybridge power plants. Edison First Power is currently in the process of requesting the necessary waivers and consents to amendments from the financing parties. We cannot assure you 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. Due to the timing of its cash flows and debt service payments, Edison First Power utilized (Pounds)37 million from its debt service reserve to meet its debt service requirements in 2000. Our net investment in our subsidiary that holds the Ferrybridge and Fiddlers' Ferry power plants and related debt was $918 million at December 31, 2000. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financing Plans." The indenture governing the notes imposes no limitations on the ability of our subsidiaries to permit contractual restrictions on their ability to make dividends or distributions. Some of our projects operate without long-term power purchase agreements and are or will be subject to market forces that affect the price of power. Some of our projects do not have long-term power purchase agreements. Also, projects which we may acquire or develop in the future may not have long-term power purchase agreements. Because their output is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the amount and price of power that they sell. We cannot assure you that these plants will be successful in selling power into their respective markets. If they are unsuccessful, they may not be able to generate enough cash to service their own debt or to make distributions to us. A substantial amount of our revenues are derived under power purchase agreements with a single customer, and we may be adversely affected if that customer fails to fulfill its obligations under those power purchase agreements. In 2000, 33% of our electric revenues were derived under power purchase agreements with Exelon Generation Company, LLC, 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 are earned from capacity and energy provided by the Illinois Plants under three five-year power purchase agreements. If Exelon Generation were to fail or become 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 generation assets. Any material failure by Exelon Generation to make payments under these power purchase agreements could adversely affect our results of operations and liquidity. The ability to amend or terminate the power purchase agreements is limited. However, the terms of the power purchase agreements do allow amendment or early termination under some limited circumstances. The 13 amendment or early termination of any power purchase agreement could adversely affect the revenues we receive and, therefore, our ability to make debt service payments on the notes. Our international projects are subject to risks of doing business in foreign countries. Our international projects are subject to political and business risks, including uncertainties associated with currency exchange rates, currency repatriation, expropriation, political instability and other issues that have the potential to impair the projects from making dividends or other distributions to us and against which we may not be fully capable of insuring. In particular, fluctuations in currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. At times, we have hedged a portion of our exposure to fluctuations in currency exchange rates. However, hedge contracts may involve risks, including default by the other party to the contract, and we cannot assure you that fluctuations in currency exchange rates will be fully offset by these hedges or that these hedges will be available throughout the term of the notes. Generally, the uncertainty of the legal structure in some foreign countries in which we may develop or acquire projects could make it more difficult to enforce our rights under agreements relating to the projects. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire. The economic crisis in Indonesia has raised concerns over the ability of PT PLN (Persero), formerly known as PT Perusahaan Listrik Negara, the state-owned utility, to meet its obligations under its power sales contract with our Paiton project and has negatively affected and may continue to negatively affect that project's dividends to us. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Commitments and Contingencies-- Paiton." Competition could adversely affect our business. The global independent power industry is characterized by numerous strong and capable competitors, some of which may have more extensive operating experience in the acquisition and development of power projects, larger staffs and greater financial resources than we do. Further, in recent years some power markets have been characterized by strong and increasing competition as a result of regulatory changes and other factors which have contributed to a reduction in market prices for power. These regulatory and other changes may continue to increase competitive pressures in the markets where we operate. Increased competition for new project investment opportunities may adversely affect our ability to develop or acquire projects on economically favorable terms. We are subject to extensive government regulation and our ability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, results of operations or financial conditions. Our operations are subject to extensive regulation by governmental agencies in each of the countries in which we conduct operations. See "Business-- Regulatory Matters." Our domestic projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of the projects. Our projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Our international projects are subject to the energy, environmental and other laws and regulations of the foreign jurisdictions in which these projects are located. The degree of regulation varies according to each country and may be materially different from the regulatory regimes in the United States. We cannot assure you that the introduction of new laws or other future regulatory developments in countries in which we conduct business will not have a material adverse effect on our business, results of operations or financial condition, nor can we assure you that we will be able to obtain and comply with all necessary licenses, permits and approvals for our proposed energy projects. If we cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected. 14 In addition, if any of our projects were to lose its status as a qualifying facility, eligible facility or foreign utility company under U.S. federal regulations, we could become subject to regulation as a "holding company" under the Public Utility Holding Company Act of 1935. If that were to occur, we would be required to divest all operations not functionally related to the operation of a single integrated utility system and would be required to obtain approval of the Securities and Exchange Commission for various actions. See "Business-- Regulatory Matters--U.S. Federal Energy Regulation." General operating risks and catastrophic events may adversely affect our projects. The operation of power generating plants involves many risks, including start-up problems, the breakdown or failure of equipment or processes, performance below expected levels of output, the inability to meet expected efficiency standards, operator error, strikes, work stoppages or labor disputes and catastrophic events such as earthquakes, landslides, fires, floods, explosions or similar calamities. The occurrence of any of these events could significantly reduce revenues generated by our projects or increase their generating expenses, thus diminishing distributions by the projects to us and, as a result, our ability to make payments under the notes. Equipment and plant warranties and insurance obtained by us may not be adequate to cover lost revenues or increased expenses and, as a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under a financing obligation of a project subsidiary could cause us to lose our interest in the project. Our future acquisitions and development projects may not be successful. Our strategy includes the development and acquisition of electric power generation facilities. The development projects and acquisitions in which we have invested, or in which we may invest in the future, including those described in this prospectus, may be large and complex, and we may not be able to complete the development or acquisition of any particular project. The development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether we will win a competitive bid, or whether a project is feasible, economically attractive or financeable. Moreover, our access to capital for future projects is uncertain. Furthermore, due to the effects of the California power crisis on Edison International, we do not expect to receive capital contributions from Edison International in the near future. We cannot assure you that we will be successful in obtaining financing for our projects or that we will obtain sufficient additional equity capital, project cash flow or additional borrowings to enable us to fund the equity commitments required for future projects. You may have difficulty selling the notes that you do not exchange. If you do not exchange your original notes for exchange notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your original notes described in the legend on your original notes. The restrictions on transfer of your original notes arise because we issued the original notes under exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. In general, you may only offer or sell the original notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not intend to register the original notes under the Securities Act. To the extent original notes are tendered and accepted in the exchange offer, the trading market, if any, for the original notes would be adversely affected. See "The Exchange Offer--Consequences of Exchanging or Failing to Exchange Original Notes." You may find it difficult to sell your notes because there is no existing trading market for the exchange notes. You may find it difficult to sell your notes because an active trading market for the notes may not develop. The exchange notes are being offered to the holders of the original notes. The original notes were issued on 15 April 5, 2001, primarily to a small number of institutional investors. After the exchange offer, the trading market for the remaining untendered original notes could be adversely affected. There is no existing trading market for the exchange notes. We do not intend to apply for listing or quotation of the exchange notes on any exchange, and so we do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Although Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Dusseldorf), the initial purchasers in the offering of the original notes, have informed us that they intend to make a market in the exchange notes, they are not obligated to do so, and any market-making may be discontinued at any time without notice. As a result, the market price of the exchange notes could be adversely affected. Broker-dealers or noteholders may become subject to the registration and prospectus delivery requirements of the Securities Act. Any broker-dealer that: . exchanges its original notes in the exchange offer for the purpose of participating in a distribution of the exchange notes; or . resells exchange notes that were received by it for its own account in the exchange offer, may be deemed to have received restricted securities and may be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that broker-dealer. Any profit on the resale of the exchange notes and any commission or concessions received by a broker-dealer may be deemed to be underwriting compensation under the Securities Act. In addition to broker-dealers, any noteholder that exchanges its original notes in the exchange offer for the purpose of participating in a distribution of the exchange notes may be deemed to have received restricted securities and may be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that noteholder. 16 USE OF PROCEEDS We will not receive any proceeds from the exchange offer. In consideration for issuing the exchange notes, we will receive in exchange original notes of like principal amount, the terms of which are identical in all material respects to the exchange notes. The original notes surrendered in exchange for exchange notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the exchange notes will not result in any increase in our indebtedness. We have agreed to bear the expenses of the exchange offer. No underwriter is being used in connection with the exchange offer. On April 5, 2001, we issued and sold the original notes. We used the proceeds of that offering, which were $600 million to: . repay $225 million under our credit facilities as required as a result of the issuance of the original notes; . pay down $346 million under our credit facilities, pending use of this amount for development costs or general corporate purposes; and . pay transaction costs totaling approximately $9 million, related to underwriting fees and legal, accounting and other costs incurred in connection with the offering of the original notes. We retained the remaining $20 million as cash. The interest rates on the credit facilities that we repaid averaged approximately 6.29% per annum as of the dates they were repaid. Two of these credit facilities are scheduled to expire in May 2001, and one credit facility is scheduled to expire in October 2001. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financing Plans-- Corporate Financing Plans." CAPITALIZATION The following table sets forth our consolidated capitalization as of December 31, 2000 and as adjusted to reflect the issuance of the original notes and application of the proceeds from the issuance of the original notes as discussed in "Use of Proceeds." The information in the table is qualified in its entirety by the more detailed information included in the documents incorporated by reference in this prospectus. See "Incorporation of Documents by Reference." Capitalization as of December 31, 2000
As Actual Adjusted(1) --------- ----------- (in millions) Short-Term Indebtedness............................. $ 2,651.2 $ 2,155.2 Long-Term Indebtedness.............................. 5,334.8 5,859.8 Preferred Securities................................ 326.8 326.8 --------- --------- Total Indebtedness................................ 8,312.8 8,341.8 Shareholder's Equity................................ 2,948.2 2,948.2 --------- --------- Total Capitalization.............................. $11,261.0 $11,290.0 ========= =========
-------- (1) Represents the capitalization at December 31, 2000, as adjusted for the net proceeds from the issuance of the original notes. 17 SELECTED CONSOLIDATED FINANCIAL DATA The following table sets forth our selected consolidated financial data for the periods indicated. The selected consolidated financial data were derived from the audited consolidated financial statements of Edison Mission Energy and our consolidated subsidiaries. These selected consolidated financial data are qualified in their entirety by the more detailed information and financial statements, including the notes to that information and those financial statements, included in the documents incorporated by reference in this prospectus.
Years Ended December 31, -------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- (in millions) INCOME STATEMENT DATA Operating revenues......... $ 3,241.0 $ 1,635.9 $ 893.8 $ 975.0 $ 843.6 Operating expenses......... 2,410.2 1,209.5 543.3 581.1 476.5 --------- --------- -------- -------- -------- Operating income........... 830.8 426.4 350.5 393.9 367.1 Interest expense........... (721.5) (375.5) (196.1) (223.5) (164.2) Interest and other income.. 74.0 55.8 50.9 53.9 40.7 Minority interest.......... (3.2) (3.0) (2.8) (38.8) (69.5) --------- --------- -------- -------- -------- Income before income taxes..................... 180.1 103.7 202.5 185.5 174.1 Provision (benefit) for income taxes.............. 72.5 (40.4) 70.4 57.4 82.0 --------- --------- -------- -------- -------- Income before accounting change and extraordinary loss...................... 107.6 144.1 132.1 128.1 92.1 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................... -- -- -- (13.1) -- --------- --------- -------- -------- -------- Net income................. $ 125.3 $ 130.3 $ 132.1 $ 115.0 $ 92.1 ========= ========= ======== ======== ======== As of December 31, -------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- (in millions) BALANCE SHEET DATA Assets..................... $15,017.1 $15,534.2 $5,158.1 $4,985.1 $5,152.5 Current liabilities........ 3,911.0 1,772.8 358.7 339.8 270.9 Long-term obligations...... 5,334.8 7,439.3 2,396.4 2,532.1 2,419.9 Preferred securities of subsidiaries.............. 326.8 476.9 150.0 150.0 150.0 Shareholder's equity....... 2,948.2 3,068.5 957.6 826.6 1,019.9 Years Ended December 31, -------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- OTHER DATA Ratio of earnings to fixed charges(/1/).............. 1.23 1.18 1.69 1.64 1.42
-------- (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. 18 THE EXCHANGE OFFER Terms of the Exchange Offer Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange original notes which are properly tendered on or before the expiration date and not withdrawn as permitted below. As used in this prospectus, the term "expiration date" means 5:00 p.m., New York City time, on June 6, 2001. However, if we, in our sole discretion, have extended the period of time for which the exchange offer is open, the term "expiration date" means the latest time and date to which we extend the exchange offer. The exchange offer, however, will not be in effect any longer than 45 business days from the date of this prospectus. As of the date of this prospectus, $600 million aggregate principal amount of the original notes is outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about May 4, 2001 to all holders of original notes known to us. Our obligation to accept original notes for exchange in the exchange offer is subject to the conditions described below under "--Conditions to the Exchange Offer." We reserve the right to extend the period of time during which the exchange offer is open. We would then delay acceptance for exchange of any original notes by giving oral or written notice of an extension to the holders of original notes as described below. During any extension period, all original notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any original notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer. Original notes tendered in the exchange offer must be in denominations of principal amount of $1,000 and any integral multiple of $1,000. We reserve the right to amend or terminate the exchange offer, and not to accept for exchange any original notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under "--Conditions to the Exchange Offer." We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the original notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the original notes, file a post-effective amendment to the prospectus and provide notice to the noteholders. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the noteholders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 a.m., New York City time on that date. Our acceptance of the tender of original notes by a tendering holder will form a binding agreement upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal. Procedures for Tendering Except as described below, a tendering holder must, on or prior to the expiration date: . transmit a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal, to United States Trust Company of New York at the address listed below under the heading "--Exchange Agent"; or . if notes are tendered in accordance with the book-entry procedures listed below, the tendering holder must transmit an agent's message to the exchange agent at the address listed below under the heading "-- Exchange Agent." 19 In addition: . the exchange agent must receive, on or before the expiration date, certificates for the original notes; or . a timely confirmation of book-entry transfer of the original notes into the exchange agent's account at the Depository Trust Company, the book- entry transfer facility, along with the letter of transmittal or an agent's message; or . the holder must comply with the guaranteed delivery procedures described below. The Depository Trust Company will be referred to as DTC in this prospectus. The term "agent's message" means a message, transmitted to DTC and received by the exchange agent and forming a part of a book-entry transfer, that states that DTC has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this holder. The method of delivery of original notes, letters of transmittal and all other required documents is at your election and risk. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. You should not send letters of transmittal or original notes to us. If you are a beneficial owner whose original notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in DTC's book-entry transfer facility system may make book-entry delivery of the original notes by causing DTC to transfer the original notes into the exchange agent's account. Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed unless the original notes surrendered for exchange are tendered: . by a registered holder of the original notes who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the letter of transmittal, or . for the account of an "eligible institution." If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an "eligible institution." An "eligible institution" is a financial institution--including most banks, savings and loan associations and brokerage houses--that is a participant in the Securities Transfer Agents Medallion Program, the New York Stock Exchange Medallion Signature Program or the Stock Exchanges Medallion Program. We will determine in our sole discretion all questions as to the validity, form and eligibility of original notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject any particular original note not properly tendered or any which acceptance might, in our judgment or our counsel's judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular original note either before or after the expiration date, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular original note either before or after the expiration date, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of original notes must be cured within a reasonable period of time. Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of original notes. Nor will we, the exchange agent or any other person incur any liability for failing to give notification of any defect or irregularity. 20 If the letter of transmittal is signed by a person other than the registered holder of original notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The original notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the original notes must be signed exactly as the name of any registered holder appears on the original notes. If the letter of transmittal or any original notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted. By tendering, each holder will represent to us that, among other things, . the exchange notes are being acquired in the ordinary course of business of the person receiving the exchange notes, whether or not that person is the holder and . neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the exchange notes. In the case of a holder that is not a broker-dealer, that holder, by tendering, will also represent to us that the holder is not engaged in and does not intend to engage in a distribution of the exchange notes. If any holder or other person is an "affiliate" of ours, as defined under Rule 405 of the Securities Act, or is engaged in, or intends to engage in, or has an arrangement or understanding with any person to participate in, a distribution of the exchange notes, that holder or other person can not rely on the applicable interpretations of the staff of the SEC and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. Each broker-dealer that receives exchange notes for its own account in exchange for original notes, where the original notes were acquired by it as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. See "Plan of Distribution." Acceptance of Original Notes for Exchange; Delivery of Exchange Notes Upon satisfaction or waiver of all of the conditions to the exchange offer, we will accept, promptly after the expiration date, all original notes properly tendered. We will issue the exchange notes promptly after acceptance of the original notes. See "--Conditions to the Exchange Offer" below. For purposes of the exchange offer, we will be deemed to have accepted properly tendered original notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice. For each original note accepted for exchange, the holder of the original note will receive an exchange note having a principal amount equal to that of the surrendered original note. The exchange notes will bear interest from the most recent date to which interest has been paid on the original notes. Accordingly, registered holders of exchange notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. Original notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Holders of original notes whose original notes are accepted for exchange will not receive any payment for accrued interest on the original notes otherwise payable on any interest payment date the record date for which occurs on or after completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the original notes. 21 In all cases, issuance of exchange notes for original notes will be made only after timely receipt by the exchange agent of: . certificates for the original notes, or a timely book-entry confirmation of the original notes, into the exchange agent's account at the book- entry transfer facility; . a properly completed and duly executed letter of transmittal; and . all other required documents. Unaccepted or non-exchanged original notes will be returned without expense to the tendering holder of the original notes. In the case of original notes tendered by book-entry transfer in accordance with the book-entry procedures described below, the non-exchanged original notes will be credited to an account maintained with the book-entry transfer facility, as promptly as practicable after the expiration or termination of the exchange offer. Book-Entry Transfer The exchange agent will make a request to establish an account for the original notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus. Any financial institution that is a participant in DTC's systems must make book-entry delivery of original bonds by causing DTC to transfer those original bonds into the exchange agent's account at DTC in accordance with DTC's procedure for transfer. This participant should transmit its acceptance to DTC on or prior to the expiration date or comply with the guaranteed delivery procedures described below. DTC will verify this acceptance, execute a book-entry transfer of the tendered original bonds into the exchange agent's account at DTC and then send to the exchange agent confirmation of this book-entry transfer. The confirmation of this book-entry transfer will include an agent's message confirming that DTC has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant. Delivery of exchange bonds issued in the exchange offer may be effected through book-entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent's message, with any required signature guarantees and any other required documents, must: (1) be transmitted to and received by the exchange agent at the address listed below under "--Exchange Agent" on or prior to the expiration date; or (2) comply with the guaranteed delivery procedures described below. Guaranteed Delivery Procedures If a registered holder of original notes desires to tender the original notes, and the original notes are not immediately available, or time will not permit the holder's original notes or other required documents to reach the exchange agent before the expiration date, or the procedure for book-entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if: . the tender is made through an eligible institution; . prior to the expiration date, the exchange agent received from an eligible institution a properly completed and duly executed letter of transmittal, or a facsimile of the letter of transmittal, and notice of guaranteed delivery, substantially in the form provided by us, by facsimile transmission, mail or hand delivery, (1) stating the name and address of the holder of original notes and the amount of original notes tendered, (2) stating that the tender is being made and 22 (3) guaranteeing that within three New York Stock Exchange trading days after the expiration date, the certificates for all physically tendered original notes, in proper form for transfer, or a book- entry confirmation, as the case may be, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and . the certificates for all physically tendered original notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the expiration date. Withdrawal Rights Tenders of original notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date. For a withdrawal to be effective, the exchange agent must receive a written notice of withdrawal at the address or, in the case of eligible institutions, at the facsimile number, indicated below under "--Exchange Agent" before 5:00 p.m., New York City time, on the expiration date. Any notice of withdrawal must: . specify the name of the person, referred to as the depositor, having tendered the original notes to be withdrawn; . identify the notes to be withdrawn, including the certificate number or numbers and principal amount of the original notes; . contain a statement that the holder is withdrawing his election to have the original notes exchanged; . be signed by the holder in the same manner as the original signature on the letter of transmittal by which the original notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the original notes register the transfer of the original notes in the name of the person withdrawing the tender; and . specify the name in which the original notes are registered, if different from that of the depositor. If certificates for original notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution unless this holder is an eligible institution. If original notes have been tendered in accordance with the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn original notes. We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal. Any original notes so withdrawn will be deemed not to have been validly tendered for exchange. No exchange notes will be issued unless the original notes so withdrawn are validly re-tendered. Any original notes that have been tendered for exchange, but which are not exchanged for any reason, will be returned to the tendering holder without cost to the holder. In the case of original notes tendered by book-entry transfer, the original notes will be credited to an account maintained with the book- entry transfer facility for the original notes. Properly withdrawn original notes may be re-tendered by following the procedures described under "-- Procedures for Tendering" above at any time on or before 5:00 p.m., New York City time, on the expiration date. 23 Conditions to the Exchange Offer Notwithstanding any other provision of the exchange offer, we shall not be required to accept for exchange, or to issue exchange notes in exchange for, any original notes, and may terminate or amend the exchange offer, if at any time before the acceptance of the original notes for exchange or the exchange of the exchange notes for the original notes, any of the following events shall occur: . there shall be threatened, instituted or pending any action or proceeding before, or any injunction, order or decree shall have been issued by, any court or governmental agency or other governmental regulatory or administrative agency or commission: (1) seeking to restrain or prohibit the making or completion of the exchange offer or any other transaction contemplated by the exchange offer, or assessing or seeking any damages as a result of this transaction, (2) resulting in a material delay in our ability to accept for exchange or exchange some or all of the original notes in the exchange offer; or any statute, rule, regulation, order or injunction shall be sought, proposed, introduced, enacted, promulgated or deemed applicable to the exchange offer or any of the transactions contemplated by the exchange offer by any governmental authority, domestic or foreign; or . any action shall have been taken, proposed or threatened, by any governmental authority, domestic or foreign, that in our sole judgment might directly or indirectly result in any of the consequences referred to in clauses (1) or (2) above or, in our sole judgment, might result in the holders of exchange notes having obligations with respect to resales and transfers of exchange notes which are greater than those described in the interpretation of the SEC referred to above, or would otherwise make it inadvisable to proceed with the exchange offer; or . there shall have occurred: (1) any general suspension of or general limitation on prices for, or trading in, securities on any national securities exchange or in the over-the-counter market; or (2) any limitation by a governmental authority which may adversely affect our ability to complete the transactions contemplated by the exchange offer; or (3) a declaration of a banking moratorium or any suspension of payments in respect of banks in the United States or any limitation by any governmental agency or authority which adversely affects the extension of credit; or (4) a commencement of a war, armed hostilities or other similar international calamity directly or indirectly involving the United States, or, in the case of any of the preceding events existing at the time of the commencement of the exchange offer, a material acceleration or worsening of these calamities; or . any change, or any development involving a prospective change, shall have occurred or be threatened in our business, financial condition, operations or prospects and those of our subsidiaries taken as a whole that is or may be adverse to us, or we shall have become aware of facts that have or may have an adverse impact on the value of the original notes or the exchange notes; which in our sole judgment in any case makes it inadvisable to proceed with the exchange offer and/or with such acceptance for exchange or with such exchange. These conditions to the exchange offer are to our sole benefit and we may assert them regardless of the circumstances giving rise to any of these conditions, or we may waive them in whole or in part in our sole discretion. If we do so, the exchange offer will remain open for at least 5 business days following any waiver of the preceding conditions. Our failure at any time to exercise any of the foregoing rights will not be deemed a waiver of any right. 24 In addition, we will not accept for exchange any original notes tendered, and no exchange notes will be issued in exchange for any original notes, if at this time any stop order is threatened or in effect relating to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939. Exchange Agent We have appointed United States Trust Company of New York as the exchange agent for the exchange offer. You should direct all executed letters of transmittal to the exchange agent at the address indicated below. You should direct questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery to the exchange agent addressed as follows: Delivery To: United States Trust Company of New York, Exchange Agent By Hand Before 4:30 p.m.: By Registered or Certified Mail: United States Trust Company of New York United States Trust Company of New York 30 Broad Street P.O. Box 112 B-Level Bowling Green Station New York, NY 10004 New York, NY 10274 Attention: Corporate Trust Services
By Hand or Overnight Delivery after 4:30 p.m. on the Expiration Date: United States Trust Company of New York 30 Broad Street, 14th Floor New York, NY 10004 For Information Call: (800) 548-6565 By Facsimile Transmission (for Eligible Institutions only): (212) 422-0183 Attention: Customer Service Confirm by Telephone: (800) 548-6565 If you deliver the letter of transmittal to an address other than any address indicated above or transmit instructions via facsimile other than any facsimile number indicated, then your delivery or transmission will not constitute a valid delivery of the letter of transmittal. Fees and Expenses We will not make any payment to brokers, dealers, or others soliciting acceptances of the exchange offer. The estimated cash expenses to be incurred in connection with the exchange offer will be paid by us. We estimate these expenses in the aggregate to be approximately $500,000. Accounting Treatment We will not recognize any gain or loss for accounting purposes upon the consummation of the exchange offer. We will amortize the expense of the exchange offer over the term of the exchange notes under generally accepted accounting principles. Transfer Taxes Holders who tender their original notes for exchange will not be obligated to pay any related transfer taxes, except that holders who instruct us to register exchange notes in the name of, or request that original 25 notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer taxes. Consequences of Exchanging or Failing to Exchange Original Notes Holders of original notes who do not exchange their original notes for exchange notes in the exchange offer will continue to be subject to the provisions in the indenture regarding transfer and exchange of the original notes and the restrictions on transfer of the original notes as described in the legend on the notes as a consequence of the issuance of the original notes under exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. In general, the original notes may not be offered or sold, unless registered under the Securities Act, except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. As discussed in "Exchange Offer; Registration Rights," we do not currently anticipate that we will register original notes under the Securities Act. Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties, we believe that exchange notes issued in the exchange offer in exchange for original notes may be offered for resale, resold or otherwise transferred by holders of the original notes, other than any holder which is an "affiliate" of ours within the meaning of Rule 405 under the Securities Act, without compliance with the registration and prospectus delivery provisions of the Securities Act, if the exchange notes are acquired in the ordinary course of the holders' business and the holders have no arrangement or understanding with any person to participate in the distribution of the exchange notes. However, the SEC has not considered the exchange offer in the context of a no-action letter. We cannot assure you that the staff of the SEC would make a similar determination with respect to the exchange offer as in the other circumstances. Each holder, other than a broker-dealer, must acknowledge that it is not engaged in, and does not intend to engage in, a distribution of exchange notes and has no arrangement or understanding to participate in a distribution of exchange notes. If any holder is an affiliate of ours, is engaged in or intends to engage in or has any arrangement or understanding with any person to participate in the distribution of the exchange notes to be acquired in the exchange offer, that holder: (1) could not rely on the applicable interpretations of the staff of the SEC; and (2) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. Each broker-dealer that receives exchange notes for its own account in exchange for original notes must acknowledge that the original notes were acquired by the broker-dealer as a result of market-making activities or other trading activities and that it will comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes. Furthermore, any broker-dealer that acquired any of its original notes directly from us: . may not rely on the applicable interpretation of the staff of the SEC's position contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983) and . must also be named as a selling noteholder in connection with the registration and prospectus delivery requirements of the Securities Act relating to any resale transaction. See "Plan of Distribution." In addition, to comply with state securities laws, the exchange notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the exchange notes to "qualified institutional buyers," as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of exchange notes in any state where an exemption from registration or qualification is required and not available. 26 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion contains forward-looking statements regarding Edison Mission Energy. These statements are based on our current plans and expectations that involve risks and uncertainties which could cause actual future activities and results of operations to be materially different from those presented in the forward-looking statements. Important factors that could cause actual results to differ include risks listed in "Risk Factors." Unless otherwise indicated, the information presented in this section is with respect to Edison Mission Energy and our consolidated subsidiaries. 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 three years ended December 31, 2000 were derived from the audited 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 exercised in late March 2001, (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. 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. 27 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. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation. Under these power purchase agreements, Exelon Generation purchases capacity and has the right to purchase energy generated by the plants. 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. 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 ((Pounds)1.3 billion sterling at the time of the acquisition) for the two plants. The acquisition was funded primarily with a combination of net proceeds of 28 (Pounds)1.15 billion 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. 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). 29 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 million ($10.5 million after tax). Sale-Leaseback Transactions On August 24, 2000, one of our subsidiaries 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 were $2.4 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain 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 of our subsidiary 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 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 those entities. Americas
Years Ended December 31, ------------------------ 2000 1999 1998 -------- ------ ------ (in millions) 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 ======== ====== ======
30 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, 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 $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. 31 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. Asia Pacific
Years Ended December 31, -------------------- 2000 1999 1998 ------ ------ ------ (in millions) 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 32 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. Europe, Central Asia, Middle East and Africa
Years Ended December 31, ----------------------- 2000 1999 1998 -------- ------ ------ (in millions) 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 and warmer-than-average weather. The time weighted average System Marginal Price dropped from (Pounds)22.39/MWh in 1999 to (Pounds)18.75/MWh in 2000. Despite improvement in capacity prices during August, 33 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. 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) 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. This decrease resulted from the lower valuation implicit in the August 2000 exchange offer pursuant to which the phantom option plan was terminated compared to the value previously accrued. The 1999 increase was primarily due to the impact of the 1999 acquisitions of the Illinois 34 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 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 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 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 35 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. This 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. 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" for further discussion. 36 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. On January 17, 2001, the subordinated financing was repaid with interest. 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 $2 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 37 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 either of the following are true: . 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 after we implemented the ring- fencing amendments, 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 credit 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; . 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 its 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, would limit the ability of Midwest Generation to use excess cash flow to make distributions. In March 2001, the California Public Utilities Commission released a draft of a proposed order instituting an investigation into whether California's investor-owned utilities, including Southern California Edison, have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. The proposed order would reopen the past holding company decisions and initiate an investigation into the following matters: . whether the holding companies, including Edison International, violated requirements to give priority to the capital needs of their respective utility subsidiaries; . whether the ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries; 38 . whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies; . any additional suspected violations of laws or Commission rules and decisions; and . whether additional rules, conditions, or other changes to the holding company decisions are necessary. A prehearing conference was held on April 20, 2001, at which the parties were asked to inform the Commission of their view of the impact of the recently signed memorandum of understanding among Southern California Edison, Edison International and the California Department of Water Resources on specified issues from the order, how to expedite resolution of those issues, and how to conduct the remainder of the investigation to the extent other issues and other parties are not affected. See "Business--Regulatory Matters--California Deregulation--The Current Power Crisis in California." At this prehearing conference, no definitive rulings were made on any issue in the investigation, including the Commission's resolution of the investigation, as called for in the memorandum of understanding. Several parties, including Edison International, raised objections to the Commission's assertion of jurisdiction over utility holding companies. The Commission is expected to issue a further ruling concerning the scope and scheduling of the investigation and also to schedule a further prehearing conference. We cannot predict whether the Commission will institute this investigation or what effects any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us. 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 $850 million) and October 2001 (in an amount of $425 million). As of April 23, 2001, we have borrowed or issued letters of credit aggregating $1.225 billion under these credit facilities and had an unused capacity of approximately $50 million. We plan to refinance these credit facilities through modifications to our existing credit facilities or by entering into new 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 $180 million; . capital requirements for projects in development and under construction of $251 million; and . development costs, general and administrative expenses. On April 5, 2001, we completed the offering of the original notes. We used the proceeds of this offering to repay indebtedness, including mandatory repayments of $225 million, which also reduced the amount available under the corporate facilities. While we cannot assure you that we will be able to enter into modifications of our existing credit facilities or obtain new facilities on similar terms and rates, we believe our corporate financing plans will be successful in meeting our cash and credit requirements in 2001. In addition, to reduce debt and to provide additional liquidity, we may sell our interest in individual projects in our project 39 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 until the aggregate commitment amount under the corporate facilities is reduced to $1 billion. 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 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 the Fiddler's Ferry and Ferrybridge power 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. We cannot assure you that 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 (Pounds)37 million 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 the 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, (Pounds)58 million 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 (Pounds)359 million, and our guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents. 40 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. 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.
U.S. Estimated Time Type of Commitment (in millions) Period Discussed Under ------------------ ------------- --------- --------------- 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 Caliraya- Botocan-Kalayaan 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 amount due to the partnerships in January, February and March 2001 and may continue to miss future payments. However, on April 17, 2001, Southern California 41 Edison made its April payment to the partnerships. Pacific Gas and Electric made its January payment in full and has paid for post-petition deliveries during the first half of April, but paid only a small portion of the amounts due to the partnerships in February and March and, as discussed below, may not pay all or a portion of its future payments. At March 31, 2001, accounts receivable due to these partnerships from Southern California Edison were $472 million and from Pacific Gas and Electric were $59 million. Our share of these receivables was $234 million and $29 million, respectively. On April 6, 2001, Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court. Although Pacific Gas and Electric has paid for post-petition deliveries during the first half of April, future payments by Pacific Gas and Electric to the qualifying facilities, including those owned by partnerships in which Edison Mission Energy has a partnership interest, may be subject to significant delays associated with the bankruptcy court process and may not be paid in full. Furthermore, Pacific Gas and Electric's power purchase agreements with the qualifying facilities will be subject to review by the bankruptcy court. We cannot assure you that the partnerships with contracts with Pacific Gas and Electric will not be adversely affected by the bankruptcy proceeding. See "Business--Regulatory Matters--California Deregulation--The Current Power Crisis in California." The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly 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 Southern California Edison by reducing deliveries under their power purchase agreements. Three of the partnerships have filed complaints requesting, among other things, a declaration that they are entitled to suspend delivery of capacity and energy to Southern California Edison, and to resell such capacity and energy to other purchasers, so long as Southern California Edison does not pay amounts due under its power purchase agreement and until Southern California Edison establishes that it is creditworthy and able to make future payments when due. 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 31, 2001, subsidiaries of ours have made equity contributions totaling approximately $115 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. However, it is possible that Southern California Edison will not pay all its obligations in full. In addition, it is possible that creditors of Southern California Edison could file an involuntary bankruptcy petition against Southern California Edison. 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. Furthermore, Southern California Edison'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 42 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. On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. As a result of this decision, Southern California Edison made its April payment in full, and Pacific Gas and Electric made its April payment in part and indicated that it intends to pay the remainder by the end of April. In addition, the decision modified the pricing formula for determining short run avoided costs for qualifying facilities subject to these provisions. Depending on the utilities' continued reaction to this order, the impact of this decision may be that the qualifying facilities subject to this pricing adjustment will be paid at significantly reduced prices for their power. Furthermore, this decision called for further study of the pricing formula tied to short run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this recent decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001. 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. 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. For more information on the current regulatory situation in California, see "Business--Regulatory Matters--California Deregulation-- Deregulation Plan." 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 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. 43 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 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 44 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. bank financing to have a debt service reserve account balance in an amount equal to six months' debt service, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $9 million to the lenders involved in the bank financing. 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 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 Mission 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, 45 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, 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 Generation 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. As part of the purchase of the generating assets from Commonwealth Edison, we committed to install one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MWs at an existing or adjacent power plant site in Chicago. The installation must be completed and the unit or units must be fully operational by December 15, 2003. The estimated cost to complete the construction of this 500 MW gas-fired power plant is approximately $250 million. 46 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; and 2005--$241 million. Firm Commitment for Asset Purchase
U.S. Projects Local Currency ($ in millions) -------- ----------------------- --------------- Italian Wind Projects(/1/).............. 36 billion Italian Lira $17
-------- (1) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Purchase payments will continue through 2002, depending on the number of projects that are ultimately developed. Firm Commitments to Contribute Project Equity
U.S. Projects Local Currency ($ 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 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
U.S. Projects Local Currency ($ 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 "Business--Recent Developments--The California Power Crisis" above for further discussion. 47 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 our Risk Management 48 Committee. Most entities that have received exceptions are organized power pools and 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, in which Exelon Generation 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 to make capacity payments for the plants under contract and energy payments for the electricity produced by these plants and taken by Exelon Generation. 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 does not fully dispatch the plants under contract, the 49 Illinois Plants may sell, subject to specified conditions, the 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 Since 1989, our plants in the U.K. have sold their electrical energy and capacity through a centralized electricity pool, which established a half- hourly clearing price, also referred to as the pool price, for electrical energy. On March 27, 2001, this system was replaced 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 to 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 counter parties 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; however, due to difficulties encountered during testing, implementation of the new electricity trading arrangements was 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 pool, determines a system marginal price each half-hour. To mitigate exposure to price 50 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. 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 51 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 the 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 52 environmental 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 53 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. The Kyoto Protocol was not submitted by the Clinton Administration to the Senate for ratification, and the Bush Administration has announced its opposition to the Kyoto Protocol. 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. Upon adoption of SFAS No. 133, 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 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 54 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 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. On April 18, 2001, Unit 6 at the Joliet Station (314 MW) was taken off line after a coal-dust explosion occurred in the building housing the unit. We are undertaking a review of the cause of the explosion and the extent of damage and will prepare a plan to return the unit to commercial operations on an expedited basis. The cost to repair the unit and the schedule to complete the repairs cannot be estimated at this time. 55 BUSINESS General Overview 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, 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. One domestic and one international project totaling 603 MW of generating capacity, of which our anticipated share will be approximately 462 MW, were then in construction stage. At December 31, 2000, we had consolidated assets of $15.0 billion and total shareholder's equity of $2.9 billion. Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities were the only producers of bulk electric power intended for sale to third parties in the United States. The Public Utility Regulatory Policies Act encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers, qualifying facilities, under certain conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent power producers, such as us, has developed in the United States since the enactment of the Public Utility Regulatory Policies Act. In 1998, utility deregulation in several states led utilities to divest generating assets, which has created new opportunities for growth of independent power in the United States. The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity in developing countries have also led to the development of significant new markets for independent power producers outside the United States. We believe that we are well-positioned to continue to realize opportunities in these new foreign markets. See "Strategic Overview" below. Recent Developments The California Power Crisis Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of the three major utilities, Southern California Edison and Pacific Gas and Electric, have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers and others. Pacific Gas and Electric filed for bankrutpcy on April 6, 2000. Given its payment defaults, creditors of Southern California Edison could file involuntary bankruptcy petitions against it. For more information on the current regulatory situation in California, see "-- Regulatory Matters--California Deregulation." For more information on how the current California power crisis affects our investments in energy projects in California, see "Risk Factors--The current California power crisis has had, and may continue to have, an adverse impact on our California partnership investments." Southern California Edison's current financial condition has had, and may continue to have, an adverse impact on Edison International's credit quality and, as previously reported by Edison International, has resulted in cross- defaults under Edison International's credit facilities. Both Standard & Poor's Ratings Services and 56 Moody's Investors Service, Inc. have lowered the credit ratings of Edison International and Southern California Edison to substantially below investment grade levels. The ratings remain under review for potential downgrade by both Standard & Poor's and Moody's. We have taken measures to isolate ourselves from the credit downgrades 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. For more information on our actions, see "Risk Factors--The current California power crisis has had, and may continue to have, an adverse impact on us." Strategic Overview Our business goal is to be one of the leading owners and operators of electric generating assets in the world. We play an active role, as a long-term owner, in all phases of power generation, from planning and development through construction and commercial operation. We believe that this involvement allows us to better ensure, with our experienced personnel, that our projects are well-planned, structured and managed, thus maximizing value creation. We have separate strategies for developed and developing countries. In developed countries, our strategy focuses on enhancing the value of existing assets, expanding plant capacity at existing sites and developing new projects in locations where we have an established position or otherwise determine that attractive financial performance can be realized. In addition, because a number of our projects in developed countries, known as merchant plants, sell power into markets without the certainty of long-term contracts, we conduct power marketing, trading, and risk management activities to stabilize and enhance the financial performance of these projects. We also recognize that our principal customers are regulated utilities. We therefore strive to understand the regulatory and economic environment in which the utilities operate so that we may continue to create mutually beneficial relationships and business dealings. In developing countries, our strategy focuses on investing with strategic partners, securing limited recourse financing based upon long-term power purchase agreements with state owned utilities and securing government financial support from organizations such as the Export-Import Bank of the United States, the U.S. Overseas Private Investment Corporation and the Japan Bank for International Cooperation. In addition, for some projects, we have obtained political risk insurance from private companies. In making investment decisions, we evaluate potential project returns against our internally generated rate of return guidelines. We establish these guidelines by identifying a base rate of return and adjusting the base rate by potential risk factors, such as risks associated with project location and stage of project development. We endeavor to mitigate these risks by (i) evaluating all projects and the markets in which they operate, (ii) selecting strategic partners with complementary skills and local experience, (iii) structuring investments through subsidiaries, (iv) managing up front development costs, (v) utilizing limited recourse financing and (vi) linking revenue and expense components where appropriate. In response to the increasing globalization of the independent power market, we have organized our operation and development activities into three geographic regions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia, Middle East and Africa. Each region is served by one or more teams consisting of business development, operations, finance and legal personnel, and each team is responsible for all our activities within a particular geographic region. Also, we mobilize personnel from outside a particular region when needed in order to assist in the development of specified projects. Below is a brief discussion of the current strategy for each of the three regions and a summary of our projects that are currently in the construction or early operations stage and other significant operating projects in each of the regions. For further information regarding our 33 domestic operating projects, see "--Our Operating Projects--Description of Domestic Operating Projects." For further information regarding our 40 international operating projects, see "-- Our Operating Projects--Description of International Operating Projects." 57 Americas Our Americas region is headquartered in Irvine, California with additional offices located in Chicago, Illinois; Boston, Massachusetts; and Washington, D.C. The strategy for the Americas region is (i) to manage our interest in operating and construction phase projects located throughout the United States, (ii) to expand our generation at existing sites, sometimes referred to as "brownfield" development, (iii) to pursue the development of new power projects throughout the region, sometimes referred to as "greenfield" development and (iv) to a lesser extent than we had in the past, to pursue the acquisition and development of existing generating assets from utilities, industrial companies and other independent power producers throughout the region. We currently have 33 operating projects in this region, all of which are presently located in the United States and its territories. In March 1999, we acquired 100% of the 1,884 MW Homer City Electric Generating Station for approximately $1.8 billion. 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. We operate the plant, which we believe is one of the lowest-cost generation facilities in the region. In December 1999, we acquired the fossil-fuel generating plants of Commonwealth Edison, a subsidiary of Exelon Corporation, which are collectively referred to as the Illinois Plants, totaling 6,841 MW of generating capacity, for approximately $4.1 billion. We operate these plants, which provide access to the 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 a term of up to five years. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation. Concurrently with this acquisition, 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 a lease of the Collins Station with a term of 33.75 years. The aggregate megawatts either purchased or leased as a result of these transactions is 9,539 MW. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Acquisitions, Dispositions and Sale-Leaseback Transactions--Sale-Leaseback Transactions" for a description of the Powerton and Joliet sale-leaseback transactions. In September 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. 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, we merged our own marketing operations with the Citizens trading operations under Edison Mission Marketing & Trading, Inc. In November 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 includes 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 exercised in late March 2000, (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 "Management's Discussion and Analysis of Financial Condition and Results of Operations--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 58 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. Asia Pacific Our Asia Pacific region is headquartered in Singapore with additional offices located in Australia, Indonesia and the Philippines. The strategy for this region is (i) to pursue projects in countries where there exist strong political commitment and the structural framework necessary for private power, (ii) to seek opportunities to employ indigenous fuels and (iii) to seek strategic, complimentary alliances with partners who bring value to a project by providing fuel, equipment and construction services. We currently have 14 operating projects in this region that are located in Australia, Indonesia, Thailand and New Zealand. 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 Paiton 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 electric 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, the U.S. Overseas Private Investment Corporation and the Ministry of Economy, Trade and Industry of Japan. 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 further 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 59 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 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 tariff 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 could require a renegotiation of the Paiton project's debt agreements. The impact of any 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. In May 1999, we completed a transaction with the government of New Zealand 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, of which our share is 940 MW. In addition, Contact Energy has expanded into the retail electricity and gas markets in New Zealand since 1998 through acquisition of regional electricity supply and retail gas supply businesses. See "--Regulatory Matters--Recent Foreign Regulatory Matters." 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 in 2003, and debt financing has been arranged for the remainder of the cost for this project. Europe, Central Asia, Middle East and Africa Our Europe, Central Asia, Middle East and Africa region is headquartered in London, England with additional offices located in Italy, Spain and Turkey. The London office was established in 1989. The region is characterized by a blend of both mature and developing markets. Our strategy for the region is to pursue the development and acquisition of medium to large scale power and cogeneration facilities with diversified fuel sources and generation technology. We currently have 26 operating projects in this region that are located in the U.K., Turkey, Spain and Italy. In July 1999, we acquired 100% of the Ferrybridge and Fiddler's Ferry coal fired power plants located in the U.K. with a total generating capacity of 3,984 MW from PowerGen UK plc for approximately $2.0 billion. Ferrybridge, located in West Yorkshire, and Fiddler's Ferry, located in Warrington, are in the middle of the order in which plants are called upon to dispatch electric power. The plants complement the pumped-storage hydroelectric power plants we already own in the U.K. 60 The electricity trading mechanism in the U.K. that provided for the sale of energy to a pool has recently been replaced with trading arrangements using bilateral contracts. Under the new trading arrangements, our U.K. subsidiary, Edison First Power Limited, is required to contract with specific purchasers for the sales of energy produced by its Ferrybridge and Fiddler's Ferry stations. Under the new system, a generator must deliver, and a consumer must take delivery, in accordance with their contracted agreements or face the volatility of market prices. Edison First Power believes that a consequence of this will be to increase greatly the motivation of parties to contract in advance in order to lock in an agreed upon price for, and quantity of, energy. The U.K. Utilities Act, which was approved on July 28, 2000, allowed for implementation of the new trading arrangements, which commenced on March 27, 2001. As a result of the introduction of the new electricity trading arrangements, forecasts of future electricity prices in the markets into which Edison First Power sells its power vary significantly. Recent experience by Edison First Power has shown that this arrangement has placed significant downward pressure on prices to be paid by purchasers of energy in the future, although it is uncertain how the new trading arrangements will affect prices in the long-term. The financial performance of the Fiddler's Ferry and Ferrybridge power plants has not matched our expectations, largely due to lower energy prices resulting primarily from increased competition, warmer-than-average weather and uncertainty surrounding the new electricity trading arrangements discussed above. 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 the 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. We cannot assure you that 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 (Pounds)37 million from its debt service reserve to meet its debt service requirements in 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. Another of our subsidiaries, EME Finance UK Limited, is the borrower under the 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, (Pounds)58 million 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 (Pounds)359 million, 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 totaling (Pounds)19 million relating to these contracts at March 20, 2001. 61 During October 1999, we completed the acquisition of the remaining 20% of the 220 MW natural gas fired Roosecote project located in England. Consideration for the remaining 20% consisted of a cash payment of approximately $16.0 million, or 9.6 million pounds sterling. In March 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. The electricity 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 was 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. Project Development The development of power generation projects, whether through new construction or the acquisition of existing assets, involves numerous elements, including evaluating and selecting development opportunities, evaluating regulatory and market risks, designing and engineering the project, acquiring necessary land rights, permits and fuel resources, obtaining financing, managing construction and, in some cases, obtaining power and steam sales agreements. We initially evaluate and select potential development projects based on a variety of factors, including the reliability of technology, the strength of the potential partners, the feasibility of the project, the likelihood of obtaining a long term power purchase agreement or profitably selling power without this agreement, the probability of obtaining required licenses and permits and the projected economic return. During the development process, we monitor the viability of our projects and make business judgments concerning expenditures for both internal and external development costs. Completion of the financing arrangements for a project is generally an indication that business development activities are substantially complete. Project Type The selection of power generation technology for a particular project is influenced by various factors, including regulatory requirements, availability of fuel and anticipated economic advantages for a particular application. We have ownership interests in operating projects that employ gas fired combustion turbine technology, predominantly through an application known as cogeneration. Cogeneration facilities sequentially produce two or more useful forms of energy, such as electricity and steam, from a single primary source of fuel, such as natural gas or coal. Many of our cogeneration projects are located near large, industrial steam users or in oil fields that inject steam underground to enhance recovery of heavy oil. The regulatory advantages for cogeneration facilities under the Public Utility Regulatory Policies Act of 1978, as amended, have become somewhat less significant because of other federal regulatory exemptions made available to independent power producers under the Energy Policy Act. Accordingly, we expect that the majority of our future projects will generate power without selling steam to industrial users. We also have ownership interests in projects that use renewable resources like hydroelectric energy and geothermal energy. Our hydroelectric projects, excluding First Hydro's plants, use run-of-the-river technology to generate electricity. The First Hydro plant utilizes pumped-storage stations that consume electricity when it is comparatively less expensive in order to pump water for storage in an upper reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is higher. This type of generation is characterized by its speed of response, its ability to work efficiently at wide variations of load and 62 the basic reliance of revenue on the difference between the peak and trough prices of electricity during the day. Our geothermal projects included as part of our Contact Energy investment use technologies that convert the heat from geothermal fluids and underground steam into electricity. We also have domestic and international ownership interests in operating projects and projects under construction and advanced development which are large scale, coal fired projects using pulverized coal and coal fired generation technology. In the United States, we have developed and acquired coal and waste coal fired projects that employ traditional pulverized coal and circulating fluidized bed technology, which allows for the use of lower quality coal and the direct removal of sulfur from the coal. We also have acquired ownership interests in gas-fired projects and have purchased gas-fired turbines for combined cycle gas turbines (commonly referred to as "F" technology), which are designed to increase efficiency of power generation due to higher firing temperatures. Long-Term Power and Steam Sales Contracts Many of our operating projects in the United States sell power and steam to domestic electric utilities and industrial steam users under long-term contracts. Electric power generated by several of our international projects is sold under long term contracts to electric utilities located in the country where the power project is located. These projects' revenues from power purchase agreements usually consist of two components: energy payments and capacity payments. Energy payments are made based on actual deliveries of electric energy, such as kilowatt hours, to the purchaser. Energy payments are usually indexed to specified variable costs that the purchaser avoids by purchasing this electric energy from our projects opposed to operating its own power plants to produce the same amount of electric energy. The variable components typically include fuel costs and selected operation and maintenance expenses. These costs may be indexed to the utility's cost of fuel and/or selected inflation indices. Capacity payments are based on a project's proven capability to reliably make electric capacity available, whether or not the project is called to deliver electric energy. Capacity payments compensate a project for specified fixed costs that are incurred independent of the amount of energy sold by the project. Such fixed costs include taxes, debt service and distributions to the project's owners. To receive capacity payments, there are typically minimum performance standards that must be met, and often there is a performance range that further influences the amount of capacity payments. Steam produced from our cogeneration facilities is sold to industrial steam users, such as petroleum refineries or companies involved in the enhanced recovery of oil through steam flooding of oil fields, under long term steam sales contracts. Steam payments are generally based on formulas that reflect the cost of water, fuel and capital to us. In some cases, we have provided steam purchasers with discounts from their previous costs for producing this steam and/or have partially indexed steam payments to other indices including specified oil prices. Sale of Power from Merchant Plants During 1999, we acquired a number of merchant plants, which sell capacity, energy and, in some cases, other services on a competitive basis under bilateral arrangements or through centralized power pools that provide an institutional framework for price setting, dispatch and settlement procedures. Electric power generated at the Homer City plant is sold under bilateral arrangements with 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. The majority of electric power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation in which Exelon Generation 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 63 five years, provide for Exelon Generation to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants. 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 does not fully dispatch the plants under contract, the Illinois Plants may sell, subject to specified conditions, the 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. 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 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. 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 has entered into a number of fixed forward electricity contracts with terms of up to two years, and which will further mitigate against the price volatility of the electricity pool. Power Marketing and Trading Activities When making sales under negotiated contracts, it is our policy to deal with investment grade counter parties or counter parties that provide equivalent credit support. Exceptions to the policy are granted only after thorough review and scrutiny by our Risk Management Committee. Most entities that have received exceptions are organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants in order to stabilize and enhance the operating revenues from merchant plants. When appropriate, we manage the "spark spread," or margin, which is the spread between electric prices and fuel prices and use forward contracts, swaps, futures, or options contracts to achieve those objectives. Our power marketing and trading organization, Edison Mission Marketing & Trading, is divided into front-, middle-, and back-office segments, with specified duties segregated for control purposes. The personnel of Edison Mission Marketing & Trading have a high level of knowledge of utility operations, fuel procurement, energy marketing and futures and options trading. We have systems in place which monitor real time spot and forward pricing and perform option valuations. We also have a wholesale power scheduling group that operates on a 24 hour basis. Edison Mission Marketing & Trading markets and trades electric power and energy related commodity products, including forwards, futures, options and swaps. It also provides services and price risk management capabilities to the electric power industry. Price risk management activities include the restructuring of power sales and power supply agreements. We generally balance forward sales and purchase contracts to mitigate market risk and secure cash flow streams. Energy trading and price risk management activities give rise to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored to ensure compliance with our risk management policies. 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 64 exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of 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. Fuel Supply Contracts We seek to enter into long term contracts to mitigate the risks of fluctuations in prices for coal, oil, gas and fuel transportation. We believe, however, that our financial condition will not be substantially adversely affected by these fluctuations for our non-merchant plants because our long term contracts to sell power and steam typically are structured so that fluctuations in fuel costs will produce similar fluctuations in electric energy and/or steam revenues. The degree of linkage between these revenues and expenses varies from project to project, but generally permits the projects with long term contracts to operate profitably under a wide array of potential price scenarios. Project Financing Each project we develop requires a substantial capital investment. Permanent project financing is often arranged immediately prior to the construction of the project. With limited exceptions, this debt financing is for approximately 50% to 80% of each project's costs and is structured on a basis that is non- recourse to us and our other projects. In addition, the collateral security for each project's financing generally has been limited to the physical assets, contracts and cash flow of that project and our ownership interests in that project. In general, each of our direct or indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Any asset of any of these subsidiaries may not be available to satisfy our obligations or those of any of our other subsidiaries. However, unrestricted cash or other assets that are available for distribution by a subsidiary may, subject to applicable law and the terms of financing arrangements of these subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us. The ability to arrange project financing and the cost of such financing are dependent upon numerous factors, including general economic and capital market conditions, the credit attributes of a project, conditions in energy markets, regulatory developments, credit availability from banks or other lenders, investor confidence in the industry, us and other project participants, the continued success of our other projects, and provisions of tax and securities laws that are conducive to raising capital. Our financial exposure in any equity investment is generally limited by contractual arrangement to our equity commitment, which is usually about 20% to 50% of our share of the aggregate project cost. In some cases, we provide additional credit support to projects in the form of debt service reserves, contingent equity commitments, revenue shortfall support or other arrangements designed to provide limited support. Permits and Approvals Because the process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking a year or longer, we seek to obtain all permits, licenses and other approvals required for the construction and operation of a project, including siting, construction and environmental permits, rights of way and planning approvals, early in the development process for a project. See "--Regulatory Matters-- General." Emission allowances were acquired by us as part of the acquisition of the Illinois Plants and the Homer City plant. Emission allowances are required by our facilities in order to be certified by the local environmental 65 authorities and are required to be maintained throughout the period of operation of those facilities located in Pennsylvania and Illinois. We purchase additional emission allowances when necessary to meet the environmental regulations. We also use forward sales and purchases of emission allowances, together with options, to achieve our objective of stabilizing and enhancing the operations from these merchant plants. Construction, Operations & Maintenance and Management In the project implementation stage, we often provide construction management, start up and testing services. The detailed engineering and construction of the projects typically are performed by outside contractors under fixed price, turnkey contracts. Under these contracts, the contractor generally is required to pay liquidated damages to us in the event of cost overruns, schedule delays or the project's failure to meet specified capacity, efficiency and emission standards. As a project goes into operation, operation and maintenance services are provided to the project by one of our operation and maintenance subsidiaries or another operation and maintenance contractor. The projects that we operated in 2000 achieved an average 82% availability. Availability is a measure of the weighted average number of hours each generator is available for generation as a percentage of the total number of hours in a year. An executive director generally manages the day-to-day administration of each project. Management committees comprised of the project's partners generally meet monthly or quarterly to review and manage the operating performance of the project. 66 Our Operating Projects Domestic Overview We currently own interests in 32 domestic operating projects in eight states and one project in the Commonwealth of Puerto Rico. These operating projects consist of 12 natural gas fired cogeneration projects, one coal fired cogeneration project, seven coal fired exempt wholesale generator projects, one waste coal project, one liquefied natural gas combined cycle cogeneration project and 11 gas fired exempt wholesale generator projects. All our domestic cogeneration projects, as well as the waste coal project, are qualifying facilities under the Public Utility Regulatory Policies Act. Our domestic operating projects have total generating capacity of 15,257 MW, of which our net ownership share is 13,231 MW. Description of Domestic Operating Projects We have ownership or leasehold interests in the following domestic operating projects:
Electric Ownership/ Capacity Primary Electric Leasehold Project Location (in MW) Purchaser(/2/) Type of Facility(/3/) Interest ------- ------------- -------- ---------------- ---------------- ---------- American Bituminous(/1/) West Virginia 80 MPC Waste Coal 50% Brooklyn Navy Yard New York 286 CE Cogeneration/EWG 50% Coalinga(/1/) California 38 PG&E Cogeneration 50% Commonwealth Atlantic Virginia 340 VEPCO EWG 50% EcoElectrica(/1/) Puerto Rico 540 PREPA Cogeneration 50% Gordonsville(/1/) Virginia 240 VEPCO Cogeneration/EWG 50% Harbor(/1/) California 80 Pool EWG 30% Homer City(/1/) Pennsylvania 1,884 Pool EWG 100% Hopewell Virginia 356 VEPCO Cogeneration 25% Illinois Plants (12 projects)(/1/) Illinois 9,539 EG EWG 100% James River Virginia 110 VEPCO Cogeneration 50% Kern River(/1/) California 300 SCE Cogeneration 50% March Point 1 Washington 80 PSE Cogeneration 50% March Point 2 Washington 60 PSE Cogeneration 50% Mid-Set(/1/) California 38 PG&E Cogeneration 50% Midway-Sunset(/1/) California 225 SCE Cogeneration 50% Nevada Sun-Peak Nevada 210 SPR EWG 50% Saguaro(/1/) Nevada 90 SPR Cogeneration 50% Salinas River(/1/) California 38 PG&E Cogeneration 50% Sargent Canyon(/1/) California 38 PG&E Cogeneration 50% Sycamore(/1/) California 300 SCE Cogeneration 50% Watson California 385 SCE Cogeneration 49%
-------- (1) Operated by subsidiaries or affiliates of Edison Mission Energy; all other projects are operated by unaffiliated third parties. (2) Electric purchaser abbreviations are as follows: CE Consolidated Edison Company of New York, Inc. EG Exelon Generation MPC Monongahela Power Company Pool Regional electricity trading market PG&E Pacific Gas & Electric Company PREPA Puerto Rico Electric Power Authority PSE Puget Sound Energy, Inc. SCE Southern California Edison Company SPR Sierra Pacific Resources VEPCO Virginia Electric & Power Company
67 (3) All the cogeneration projects are gas fired facilities, except for the James River project, which uses coal. All the exempt wholesale generator (EWG) projects are gas fired facilities, except for the Homer City plant and six of the Illinois Plants, which use coal. International Overview We own interests in 40 operating projects outside the United States. The total generating capacity of these facilities is 12,779 MW, of which our net ownership share is 9,528 MW. Description of International Operating Projects We have ownership interests in the following international operating projects:
Electric Primary Capacity Electric Ownership Project Location (in MW) Purchaser(/2/) Interest ------- ----------- -------- --------- --------- Contact (10 projects) New Zealand(/6/) 2,449 Pool 42% Derwent(/1/) England 214 SE(/3/) 33% Doga(/1/) Turkey 180 TEAS 80% Ferrybridge England 1,989 Pool 100% Fiddler's Ferry England 1,995 Pool 100% First Hydro (2 projects) Wales 2,088 Pool 100% Iberian Hy-Power I (5 projects) Spain 43 FECSA 100%(/7/) Iberian Hy-Power II (13 projects) Spain 43 FECSA 100% ISAB Italy 512 GRTN 49% Kwinana(/1/) Australia 116 WP 70% Loy Yang B Australia 1,000 Pool(/4/) 100% Paiton(/1/) Indonesia 1,230 PLN 40% Roosecote England 220 NORWEB(/5/) 100% TriEnergy Thailand 700 EGAT 25%
-------- (1) Operated by subsidiaries or affiliates of Edison Mission Energy; all other projects are operated by unaffiliated third parties. (2) Electric purchaser abbreviations are as follows: GRTN Gestore Rete Transmissione Nazionale EGAT Electricity Generating Authority of Thailand FECSA Fuerzas Electricas de Cataluma, S.A. NORWEB North Western Electricity Board WP Western Power Pool Electricity trading market for England, Wales, Australia and New Zealand PLN PT PLN SE Southern Electric plc. TEAS Turkiye Elektrik Urehm A.S.
(3) Sells to the pool with a long-term contract with SE. (4) Sells to the pool with a long-term contract with the State Electricity Commission of Victoria. (5) Sells to the pool with a long-term contract with NORWEB. (6) Minority interest in one project in Australia. (7) Minority interests are owned by third parties in three of the projects. Oil and Gas Investments In 1988, we formed a wholly-owned subsidiary, Mission Energy Fuel Company, to develop and invest in fuel interests. Since that time, Mission Energy Fuel has invested in a number of oil and gas properties and a production company. Oil and gas produced from the properties are generally sold at spot or short term market prices. 68 Four Star As of December 31, 2000, we owned 36% of the stock of Four Star Oil & Gas Company, a subsidiary of Texaco Inc. The underlying value of Four Star is attributable to the production of oil and gas from nine producing properties. Our proportionate interest in net quantities of proved reserves at December 31, 2000 totaled 180.6 billion cubic feet of natural gas and 10.4 million barrels of oil. In November 1999, we completed the sale of a portion of our interest in Four Star to a company in which we hold a 50% interest. Net proceeds from the sale were $20.5 million. We recorded an after-tax gain on the sale of our investment of approximately $30 million. Our net ownership interest in Four Star was reduced from 50% at December 31, 1998 to 34% as a result of the transaction. In December 1999 and May and July 2000, we purchased additional shares of stock of Four Star, increasing our ownership interest to 38%. On December 31, 2000, shares of convertible preferred shares were converted to common shares, reducing our net ownership interest to 36%. Competition We compete with many other companies, including multinational development groups, equipment suppliers and other independent power producers, including affiliates of utilities, in selling electric power and steam. We also compete with electric utilities in obtaining the right to install new generating capacity. Over the past decade, obtaining a power sales contract with a utility has generally become a progressively more difficult, expensive and competitive process. Many power sales contracts are now awarded by competitive bidding, which both increases the costs of obtaining these contracts and decreases the chances of obtaining these contracts. We evaluate each potential project in an effort to determine when the probability of success is high enough to justify expenditures in developing a proposal or bid for the project. Amendments to the Public Utility Holding Company Act of 1935 made by the Energy Policy Act have increased the number of competitors in the domestic independent power industry by reducing restrictions applicable to projects that are not qualifying facilities under the Public Utility Regulatory Policies Act. Retail wheeling of power, which is the offering by utilities of unbundled retail distribution service, could also lead to increased competition in the independent power market. See "--Regulatory Matters--Retail Competition." Tax Sharing Agreements We are included in the consolidated federal income tax and combined state franchise tax returns of Edison International. We calculate our income tax provision on a separate company basis under a tax sharing arrangement with The Mission Group, which in turn has an agreement with Edison International. Tax benefits generated by us and used in the Edison International consolidated tax return are recognized by us without regard to separate company limitations. Seasonality 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 revenues from energy projects are materially higher than other quarters of the year due to a significant number of our domestic energy projects located on the West Coast of the United States, which generally have power sales contracts that provide for higher payments during summer months. The First Hydro plants, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants provide for higher electric revenues during the winter months. Employees and Offices At December 31, 2000, we employed 3,391 people, all of whom were full time employees and approximately 639, 146 and 1,294 of whom were covered by collective bargaining agreements in the 69 United Kingdom, Australia and the United States, respectively. We have never experienced a work stoppage or strike. We believe we have good relations with our employees. However, the term of the collective bargaining agreement covering our employees at the Illinois Plants is currently in dispute, with the union maintaining that the agreement expired as early as March 31, 2001, while we maintain that the agreement remains in effect until June 2002. The dispute will be heard by an administrative law judge with the National Labor Relations Board. While no strike has been authorized or strike vote taken, the union has indicated that is one possibility. Midwest Generation has operational plans in place and intends to operate the Illinois Plants in the event of the strike if the current dispute is not resolved. Although we cannot predict the outcome of this dispute, we believe the impact on our operations will not be material. We lease our corporate headquarters in Irvine, California and our principal regional offices in London, Melbourne and Singapore. We also lease other smaller offices in the United States and certain foreign countries. Regulatory Matters General Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operations of a project and the ownership of a project. Our operations are subject to extensive regulation by governmental agencies in each of the countries in which we conduct operations. Our domestic projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of, and use of electric energy, capacity and related products, including ancillary services from, our projects. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non utility owned electric power plants. Energy producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy producing facility and that the facility then operate in compliance with these permits and approvals. While we believe the requisite approvals for our existing projects have been obtained and that our business is operated in substantial compliance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. Regulatory compliance for the construction of new facilities is a costly and time consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures and may create a significant risk of expensive delays or significant loss of value in a project if the project is unable to function as planned due to changing requirements or local opposition. Furthermore, each of our international projects is subject to the energy and environmental laws and regulations of the foreign country in which this project is located. The degree of regulation varies according to each country and may be materially different from the regulatory regime in the United States. U.S. Federal Energy Regulation The Federal Energy Regulatory Commission has ratemaking jurisdiction and other authority with respect to interstate sales and transmission of electric energy under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission has regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935. The enactment of the Public Utility Regulatory Policies Act of 1978 and the adoption of regulations thereunder by the Federal Energy Regulatory Commission provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and the Public 70 Utility Holding Company Act for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from the Public Utility Holding Company Act for exempt wholesale generators and foreign utility companies. A "qualifying facility" under the Public Utility Regulatory Policies Act is a cogeneration facility or a small power production facility that satisfies criteria adopted by the Federal Energy Regulatory Commission. In order to be a qualifying facility, a cogeneration facility must (i) sequentially produce both useful thermal energy, such as steam, and electric energy, (ii) meet specified operating standards, and energy efficiency standards when oil or natural gas is used as a fuel source and (iii) not be controlled, or more than 50% owned by one or more electric utilities (where "electric utility" is interpreted with reference to the Public Utility Holding Company Act definition of an "electric utility company"), electric utility holding companies (defined by reference to the Public Utility Holding Company Act definitions of "electric utility company" and "holding company") or affiliates of such entities. A small power production facility seeking to be a qualifying facility must produce power from renewable energy sources, such as geothermal energy, waste sources of fuel, such as waste coal, or any combination thereof and must meet the ownership restrictions discussed above. Before 1990, a small power production facility seeking to be a qualifying facility was subject to 30 MW or 80 MW size limits, depending upon its fuel source. In 1990, these limits were lifted for solar, wind, waste, and geothermal qualifying facilities, provided that applications for or notices of qualifying facility status were filed with the Federal Energy Regulatory Commission for these facilities on or before December 31, 1994, and provided, in the case of new facilities, the construction of these facilities commenced on or before December 31, 1999. An "exempt wholesale generator" under the Public Utility Holding Company Act is an entity determined by the Federal Energy Regulatory Commission to be exclusively engaged, directly or indirectly, in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail. A "foreign utility company" under the Public Utility Holding Company Act is, in general, an entity located outside the United States that owns or operates facilities used for the generation, distribution or transmission of electric energy for sale or the distribution at retail of natural or manufactured gas, but that derives none of its income, directly or indirectly, from such activities within the United States. Federal Power Act--The Federal Power Act grants the Federal Energy Regulatory Commission exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the Federal Energy Regulatory Commission to revoke or modify previously approved rates. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by Federal Energy Regulatory Commission to be workably competitive, may be market- based. As noted, most qualifying facilities are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the ratemaking jurisdiction of the Federal Energy Regulatory Commission thereunder, but the Federal Energy Regulatory Commission typically grants exempt wholesale generators the authority to charge market- based rates as long as the absence of market power is shown. In addition, the Federal Power Act grants the Federal Energy Regulatory Commission jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the Federal Energy Regulatory Commission typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates. Currently, in addition to the facilities owned or operated by us, a number of our operating projects, including the Homer City plant, the Illinois Plants, the Nevada Sun-Peak, Brooklyn Navy Yard, Commonwealth Atlantic and Harbor facilities, are subject to the Federal Energy Regulatory Commission ratemaking regulation under the Federal Power Act. Our future domestic non-qualifying facility independent power projects will also be subject to Federal Energy Regulatory Commission jurisdiction on rates. 71 The Public Utility Holding Company Act--Unless exempt or found not to be a holding company by the Securities and Exchange Commission, a company that falls within the definition of a holding company must register with the Securities and Exchange Commission and become subject to Securities and Exchange Commission regulation as a registered holding company under the Public Utility Holding Company Act. "Holding company" is defined in Section 2(a)(7) of the Public Utility Holding Company Act to include, among other things, any company that owns 10% or more of the voting securities of an electric utility company. "Electric utility company" is defined in Section 2(a)(3) of the Public Utility Holding Company Act to include any company that owns facilities used for generation, transmission or distribution of electric energy for resale. Exempt wholesale generators and foreign utility companies are not deemed to be electric utility companies and qualifying facilities are not considered facilities used for the generation, transmission or distribution of electric energy for resale. Securities and Exchange Commission precedent also indicates that it does not consider "paper facilities," such as contracts and tariffs used to make power sales, to be facilities used for the generation, transmission or distribution of electric energy for resale, and power marketing activities will not, therefore, result in an entity being deemed to be an electric utility company. A registered holding company is required to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. In addition, a registered holding company will require Securities and Exchange Commission approval for the issuance of securities, other major financial or business transactions (such as mergers) and transactions between and among the holding company and holding company subsidiaries. Because it owns Southern California Edison, an electric utility company, Edison International, our parent company, is a holding company. Edison International is, however, exempt from registration pursuant to Section 3(a)(1) of the Public Utility Holding Company Act, because the public utility operations of the holding company system are predominantly intrastate in character. Consequently, we are not a subsidiary of a registered holding company, so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another of the exemptions enumerated in Section 3(a). Nor are we a holding company under the Public Utility Holding Company Act, because our interests in power generation facilities are exclusively in qualifying facilities, exempt wholesale generators and foreign utility companies. All international projects and specified U.S. projects that we are currently developing or proposing to acquire will be non-qualifying facility independent power projects. We intend for each project to qualify as an exempt wholesale generator or as a foreign utility company. Loss of exempt wholesale generator, qualifying facility or foreign utility company status for one or more projects could result in our becoming a holding company subject to registration and regulation under the Public Utility Holding Company Act and could trigger defaults under the covenants in our project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and could cause certain of our project agreements and other contracts to be voidable. Public Utility Regulatory Policies Act of 1978--The Public Utility Regulatory Policies Act provides two primary benefits to qualifying facilities. First, as discussed above, ownership of qualifying facilities will not result in a company's being deemed an electric utility company for purposes of the Public Utility Holding Company Act. In addition, all cogeneration facilities and all small production facilities that generate power from sources other than geothermal and whose capacity exceeds 30 MWs that are qualifying facilities are exempt from most provisions of the Federal Power Act and regulations of the Federal Energy Regulatory Commission thereunder. Second, the Federal Energy Regulatory Commission regulations promulgated under the Public Utility Regulatory Policies Act require that electric utilities purchase electricity generated by qualifying facilities at a price based on the purchasing utility's avoided cost, and that the utilities sell back up power to the qualifying facility on a non discriminatory basis. The Federal Energy Regulatory Commission's regulations define "avoided cost" as the incremental cost to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, the utility would generate itself or purchase from another source. The Federal Energy Regulatory Commission's regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different than 72 the utility's avoided costs. While it has been common for utilities to enter into long term contracts with qualifying facilities in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions, increasing competition and the development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner. If one of the projects in which we have an interest were to lose its status as a qualifying facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation under the Public Utility Holding Company Act and the Federal Power Act. As a result, the project could become subject to rate regulation by the Federal Energy Regulatory Commission under the Federal Power Act, and we could inadvertently become a holding company under the Public Utility Holding Company Act. Under Section 26(b) of the Public Utility Holding Company Act, any project contracts that are entered into in violation of the Public Utility Holding Company Act, including contracts entered into during any period of non-compliance with the registration requirement, could be determined by the courts or the Securities and Exchange Commission to be void. If a project were to lose its qualifying facility status, we could attempt to avoid holding company status on a prospective basis by qualifying the project owner as an exempt wholesale generator. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from the Federal Energy Regulatory Commission would be required. In addition, the project would be required to cease selling electricity to any retail customers, in order to qualify for exempt wholesale generator status, and could become subject to additional state regulation. Loss of qualifying facility status by one project could also potentially cause other projects with the same partners to lose their qualifying facility status to the extent those partners became electric utilities, electric utility holding companies or affiliates of such companies for purposes of the ownership criteria applicable to qualifying facilities. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, we cannot assure you that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, our business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards for maintaining qualifying facility status or that eliminated or reduced the benefits, such as the mandatory purchase provisions of the Public Utility Regulatory Policies Act and exemptions currently enjoyed by qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties being levied against us, or claims by a utility customer for the refund of payments previously made. We endeavor to develop our qualifying facility projects, monitor regulatory compliance by these projects and choose our customers in a manner that minimizes the risks of losing these projects' qualifying facility status. However, some factors necessary to maintain qualifying facility status are subject to risks of events outside of our control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a qualifying facility could cause a facility to fail to meet the requirements regarding the minimum level of useful thermal energy output. Upon the occurrence of this type of event, we would seek to replace the thermal energy customer or find another use for the thermal energy that meets the requirements of the Public Utility Regulatory Policies Act. Natural Gas Act--Twenty-four of the domestic operating facilities that we own, operate or have investments in use natural gas as their primary fuel. Under the Natural Gas Act, the Federal Energy Regulatory Commission has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The Federal Energy Regulatory Commission has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce. 73 State Energy Regulation State public utility commissions have broad jurisdiction over non qualifying facility independent power projects, including exempt wholesale generators, which are considered public utilities in many states. This jurisdiction often includes the issuance of certificates of public convenience and necessity and/or other certifications to construct, own and operate a facility, as well as the regulation of organizational, accounting, financial and other corporate matters on an ongoing basis. Qualifying facilities may also be required to obtain these certificates of public convenience and necessity in some states. Some states that have restructured their electric industries require generators to register to provide electric service to customers. Many states are currently undergoing significant changes in their electric statutory and regulatory frameworks that result from restructuring the electric industries that may affect generators in those states. Although the Federal Energy Regulatory Commission generally has exclusive jurisdiction over the rates charged by a non-qualifying facility independent power project to its wholesale customers, a state's public utility commission has the ability, in practice, to influence the establishment of these rates by asserting jurisdiction over the purchasing utility's ability to pass through the resulting cost of purchased power to its retail customers. A state's public utility commission also has the authority to determine avoided costs for qualifying facilities and to regulate the retail rates charged by qualifying facilities. In addition, states may assert jurisdiction over the siting and construction of independent power projects and, among other things, the issuance of securities, related party transactions and the sale or other transfer of assets by these facilities. The actual scope of jurisdiction over independent power projects by state public utility commissions varies from state to state. In addition, state public utility commissions may seek to modify, suspend or terminate a qualifying facility's power sales contract under specified circumstances. This could occur if the state public utility commission were to determine that the pricing mechanism of the power sales contract is unfairly high in light of the current prevailing market cost of power for the utility purchasing the power. In this instance, the state public utility commission could attempt to alter the terms of the power sales contract to reflect more accurately market conditions for the prevailing cost of power. While we believe that these attempts are not common, and that the state public utility commission may not have any jurisdiction to modify the terms of the wholesale power sales, we cannot assure you that the power sales contracts of our projects will not be subject to adverse regulatory actions. The California Public Utilities Commission has authorized the electric utilities in California to "monitor" compliance by qualifying facilities with the Public Utility Regulatory Policies Act rules and regulations. However, the United States Court of Appeals for the Ninth Circuit found in 1994 that a California Public Utilities Commission program was preempted by the Public Utility Regulatory Policies Act, to the extent it authorized utilities to determine that a qualifying facility was not in compliance with the Public Utility Regulatory Policies Act rules and regulations, to then pay a reduced avoided cost rate and to take other action contrary to a facility's status as a qualifying facility. The court did, however, uphold reasonable monitoring of qualifying facility operating data. Other states, like New York and Virginia, have also instituted qualifying facility monitoring programs. We buy and transport the natural gas used at our domestic facilities through local distribution companies. State public utility commissions have jurisdiction over the transportation of natural gas by local distribution companies. Each state's regulatory laws are somewhat different. However, all generally require the local distribution companies to obtain approval from the relevant public utility commission for the construction of facilities and transportation services if the local distribution company's generally applicable tariffs do not cover the proposed transaction. Local distribution companies' rates are usually subject to continuing public utility commission oversight. California Deregulation Deregulation Plan--Efforts to restructure the California electric industry began in 1994 in response to high electricity prices. A final restructuring order was issued by the California Public Utility Commission in 74 December 1995, which led to the unanimous enactment of Assembly Bill 1890, the Restructuring Legislation, in September 1996 and its signature by the Governor of California at the time. The main points of this legislation included the following: . the creation of the California Independent System Operator and California Power Exchange by January 1998 and simultaneous initiation of direct access between electricity suppliers and end use customers; . the creation of the California Electricity Oversight Board; and . the adoption of a Competitive Transition Charge for the recovery of stranded costs. The state's utilities were authorized to divest much of their generation assets and apply the proceeds to their stranded costs resulting from deregulation of the retail markets. The restructuring also required that California investor-owned utilities sell into and purchase most of their power requirements from the California Power Exchange but did not permit them to hedge their risk through long-term forward contracts. Through this mechanism, a spot market was created that set the purchase price for power by establishing the highest bid as the market clearing price for all bidders. Additionally, the legislation provided for a limited transition period ending March 31, 2002, or an earlier date at which it is determined that a utility has recovered its stranded costs. During the transition period, there is a rate reduction of no less than 10% for residential and small commercial ratepayers. The rate reduction was financed through the issuance of rate reduction bonds. The rate reduction scheme capped retail electric rates at 1996 levels. The retail rate cap and bond offering were intended to assist utilities in the recovery of stranded costs incurred by their investments made prior to deregulation. At the conclusion of the transition period, the legislation anticipated that residential and small business purchasers of electricity would pay 20% less for electricity due to effective implementation of Assembly Bill 1890. The Current Power Crisis in California--Wholesale power prices rose significantly in California during 2000 and early 2001, we believe primarily as a result of supply shortages, high natural gas and petroleum prices and a variety of other factors. Unregulated wholesale rates rose above the fixed retail rates the California utilities were permitted to charge their customers. The inability of utilities to recover the full amount of wholesale prices has led to billions of dollars in unrecovered costs by the California utilities and to their current liquidity crisis. Ongoing legislative and regulatory efforts seek to address both market structure and supply problems. In September 2000, legislation was enacted in California seeking to accelerate the power plant siting approval process. Other initiatives may seek to stimulate entry into the market of new power generation capacity. In December 2000, the Federal Energy Regulatory Commission issued an order permitting California utilities to negotiate long-term supply contracts, and establishing a "soft-cap" limiting the wholesale price that could be charged without additional cost justification, as opposed to allowing the highest bid price to set the market clearing price for all generators. At that time, the Federal Energy Regulatory Commission refused to set a regional price cap for wholesale power prices as sought by state officials. On January 4, 2001, the California Public Utilities Commission authorized an interim surcharge on customers' bills, subject to refund, to be applied only to ongoing power procurement costs which was to result in rate increases of 7-15% during a 90-day period. On March 27, 2001, the California Public Utilities Commission made the interim surcharge permanent and authorized a rate increase of three cents per kilowatt-hour. Neither the interim surcharge nor the rate increase affected the retail rate freeze which has been in effect since deregulation began in 1998. On February 1, 2001, legislation was enacted in California that, among other things: authorized the California Department of Water Resources to enter into long-term power purchase contracts; authorized the Department of Water Resources to sell revenue bonds to finance electricity purchases; provided for rate recovery of the Department of Water Resources' costs through rate increases, subject to specified limits; authorized the Department of Water Resources to sell power at its costs to retail customers and, with specified 75 exceptions, to local publicly owned electric utilities; appropriated a total of $500 million toward additional spot market power purchases; and provided for suspension of the ability of customers to choose alternative energy providers while the Department of Water Resources is procuring power. Executive Orders promoting energy conservation measures were also signed by the Governor of California, including a mandatory requirement that retail businesses reduce outdoor retail lighting during non-business hours or face fines. In addition, on February 21, 2001, the California Senate approved formation of a California state power authority, which (if formed) will have the power to own and operate generation and transmission facilities in the state. The formation of the state power authority has not yet been approved by the California Assembly. The Governor of California has also proposed that the state acquire the transmission assets of the investor-owned utilities, including Southern California Edison, and that the proceeds from such sales be applied against the utilities' existing debts. As part of an investigation that the Federal Energy Regulatory Commission has been conducting on wholesale power prices in the California market, the Federal Energy Regulatory Commission ordered a number of power generators, not including Edison Mission Energy, to justify charges to California utilities during the months of January and February 2001 or refund such charges. The Federal Energy Regulatory Commission has further required a power generator and a marketer to justify their decision to bring plants off-line or refund to the California utilities the increased costs resulting from such shutdowns. Also, the Governor of California and other western states have petitioned the Federal Energy Regulatory Commission and the United States Congress for "cost-based" price caps for wholesale power rates on the spot market, permitting power generators to recover all their costs with a small level of profit. Further actions are anticipated as both the Federal and California state governments have intervened to address the short- and long-term issues associated with the power crisis. A recent Federal Energy Regulatory Commission report estimates that it could take up to 24 months to address these issues. On March 15, 2001, the California Public Utilities Commission released a draft of a proposed order instituting an investigation into whether California's investor-owned utilities, including Southern California Edison, have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. The proposed order would reopen the past holding company decisions and initiate an investigation into the following matters: . whether the holding companies, including Edison International, violated requirements to give priority to the capital needs of their respective utility subsidiaries; . whether the ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries; . whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies; . any additional suspected violations of laws or Commission rules and decisions; and . whether additional rules, conditions, or other changes to the holding company decisions are necessary. A prehearing conference was held on April 20, 2001, at which the parties were asked to inform the Commission of their view of the impact of the recently signed memorandum of understanding among Southern California Edison, Edison International and the California Department of Water Resources on specified issues from the order, how to expedite resolution of those issues, and how to conduct the remainder of the investigation to the extent other issues and other parties are not affected. See "Business--Regulatory Matters--California Deregulation--The Current Power Crisis in California." At this prehearing conference, no definitive rulings were made on any issue in the investigation, including the Commission's resolution of the investigation, as called for in the memorandum of understanding. Several parties, including Edison International, raised objections to the Commission's assertion of jurisdiction over utility holding companies. The Commission is expected to issue a further ruling concerning the scope and scheduling of the investigation and also to schedule a further prehearing conference. We cannot predict whether the Commission will institute this investigation or what effects any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us. 76 On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. As a result of this decision, Southern California Edison made its April payment in full, and Pacific Gas and Electric made its April payment in part and indicated that it intends to pay the remainder by the end of April. In addition, the decision modified the pricing formula for determining short run avoided costs for qualifying facilities subject to these provisions. Depending on the utilities' continued reaction to this order, the impact of this decision may be that qualifying facilities subject to this pricing adjustment will be paid significantly reduced prices for their power. Furthermore, this decision called for further study of the pricing formula tied to short run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this recent decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001. As previously disclosed by Edison International, on April 9, 2001, Edison International and Southern California Edison signed a Memorandum of Understanding with the California Department of Water Resources. The Memorandum calls for legislation, regulatory action and definitive agreements to resolve important aspects of the energy crisis, and which the parties expect will help restore Southern California Edison's creditworthiness and liquidity. Edison International filed a Form 8-K on April 10, 2001, which describes key elements of the Memorandum. Among other things, the Memorandum provides that we will execute a contract with the Department of Water Resources or another state agency for the provision of power from the Sunrise Project, our power project currently under development, to the State at cost-based rates for ten years. Edison International agreed that we will use all commercially reasonable efforts to place the first phase of the project into service before the end of Summer 2001. Edison International and Southern California Edison believe that the Memorandum is an important step toward an acceptable resolution of the major issues affecting Edison International and Southern California Edison as a result of the California energy crisis, but this result is not assured. The parties agreed in the Memorandum that each of its elements is part of an integrated package, and effectuation of each element will depend upon effectuation of the others. To implement the Memorandum, numerous actions must be taken by the parties and by other agencies of the State of California. Southern California Edison, Edison International and the Department of Water Resources committed to proceed in good faith to sponsor and support the required legislation and to negotiate in good faith the necessary definitive agreements. However, the California Legislature, the California Public Utilities Commission, the Federal Energy Regulatory Commission, and other governmental entities on whose part action will be necessary to implement the Memorandum are not parties to the Memorandum. Furthermore, the Memorandum may be terminated by either Southern California Edison or the California Department of Water Resources if required legislation is not adopted and definitive agreements executed by August 15, 2001, or if the California Public Utilities Commission does not adopt the required implementing decisions within 60 days after the Memorandum was signed, or if specified other adverse changes occur. We cannot provide assurance that all the required legislation will be enacted, regulatory actions taken, and definitive agreements executed before the applicable deadlines. In addition, a California voter initiative or referendum previously has been threatened against any measures that would raise consumer rates or aid California's investor-owned utilities. Finally, execution of the Memorandum does not eliminate the possibility that some of Southern California Edison's creditors could take steps to force Southern California Edison into bankruptcy proceedings. On April 20, 2001, a prehearing conference was held, at which the parties involved were asked to inform the California Public Utilities Commission of their view of the impact of the Memorandum on specified issues from a draft of a proposed order released by the Commission on March 15, 2001. This proposed order 77 instituted an investigation into whether California's investor-owned utilities have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. See "Risk Factors--The current California power crisis has had, and may continue to have, an adverse impact on us." At this prehearing conference, no definitive rulings were made on any issue in the investigation, including the Commission's resolution of the investigation, as called for in the Memorandum, nor were any views expressed on Southern California Edison's characterization of the impact on the investigation of the Memorandum. The Commission is expected to issue a further ruling concerning the scope and scheduling of the investigation and also to schedule a further prehearing conference. We cannot predict what the effects of any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us. On April 6, 2001, Pacific Gas and Electric announced that it had filed for reorganization under Chapter 11 of the United States Bankruptcy Code. Pacific Gas and Electric said that neither its parent holding company nor any of the parent's other subsidiaries are affected by Pacific Gas and Electric's filing. Pacific Gas and Electric cited as reasons for its bankruptcy filing the failure by the State of California to assume full procurement responsibility for Pacific Gas and Electric's net short position, the California Public Utilities Commission's actions on March 27 and April 3, 2001 that created new payment obligations for Pacific Gas and Electric, lack of progress in negotiations with the State to provide recovery of power purchase costs, the California Public Utilities Commission's adoption of an illegal and retroactive accounting change, and the slow progress of discussions with the Governor's representatives. On April 30, 2001, we filed with the Federal Energy Regulatory Commission seeking approval of a transaction in which our stock would be transferred to a newly-created indirect wholly-owned subsidiary of Edison International. The filing was made in connection with a financing under consideration by Edison International, in which some or all of our stock would be pledged by the newly- created company to its lenders in connection with the contemplated financing. Under the financing, the newly-created company would issue debt, remit the proceeds of the financing to Edison International to refinance a portion of its indebtedness and pledge our stock as collateral for the debt. If this financing were completed, and there was a subsequent event of default under the financing, this could result in a change in control of us if the secured lenders in the financing were to foreclose on our stock. If this were to occur, it would be an event of default under our current corporate credit facilities, which might trigger cross-defaults in other agreements to which we are a party. In connection with negotiations regarding a new line of credit, we are discussing with the lenders modifications to the change in control provision. We cannot give any assurance that the Federal Energy Regulatory Commission will approve this transaction, that this proposed financing will be made on the terms presently contemplated or that our lenders will agree to modifications to the change in control provision. The situation in California changes on an almost daily basis. You should monitor developments in California for the most up to date information. Recent Foreign Regulatory Matters United Kingdom--The U.K.'s 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 78 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 counter parties 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; however, due to difficulties encountered during testing, implementation of the new electricity trading arrangements was delayed from November 21, 2000 until March 27, 2001. A warmer-than-average winter (January to March 2000), the entry of new operations into the generation market, the impending introduction of the new electricity trading arrangements coupled with uncertainties surrounding the new Utilities Act and action by the Director General to control abuse of market power, discussed below, contributed to a drop in the energy component of pool prices throughout the year (time weighted average System Marginal Price dropped from (Pounds)22.39/MWh in 1999 to (Pounds)18.75/MWh in 2000) and depressed forward prices for winter 2000/2001. We have entered into contracts for differences 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. 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 prior years. As a result of the foregoing, we continue to expect lower revenues from our Ferrybridge and Fiddler's Ferry plants. 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. 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 energy 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. 79 Transmission of Wholesale Power Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others, also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the Federal Energy Regulatory Commission, when the entity providing the wheeling service is a jurisdictional public utility under the Federal Power Act. Until 1992, the Federal Energy Regulatory Commission's ability to compel wheeling was very limited, and the availability of voluntary wheeling service could be a significant factor in determining whether a site was viable for project development. The Federal Energy Regulatory Commission's authority under the Federal Power Act to require electric utilities to provide transmission service on a case by case basis to qualifying facilities, exempt wholesale generators, and other power generators was expanded substantially by the Energy Policy Act. Furthermore, in 1996 the Federal Energy Regulatory Commission issued a rulemaking order, Order 888, in which the Federal Energy Regulatory Commission asserted the power, under its authority to eliminate undue discrimination in transmission, to compel all jurisdictional public utilities under the Federal Power Act to file open access transmission tariffs consistent with a pro forma tariff drafted by the Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission subsequently issued Orders 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs. The Federal Energy Regulatory Commission also issued Order 889, which required those transmitting utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information about transmission requests and availability, on a publicly available computer bulletin board. Although the pro forma tariff does not cover the pricing of transmission service, Order 888 and the subsequently issued regional transmission organization rulemaking are expected to improve transmission access for independent power producers like us. A 1999 decision by the United States Court of Appeals for the Eighth Circuit has cast doubt on the extent of the Federal Energy Regulatory Commission's authority to require specified curtailment policies in the pro forma tariff. The United States Court of Appeals for the D.C. Circuit issued an opinion on June 30, 2000 that affirmed the Federal Energy Regulatory Commission's Order 888 et seq. in all material respects. Retail Competition In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of most states are considering, or have considered, whether to open the retail electric power market to competition. Retail competition is possible when a customer's local utility agrees, or is required, to "unbundle" its distribution service (for example, the delivery of electric power through its local distribution lines) from its transmission and generation service (for example, the provision of electric power from the utility's generating facilities or wholesale power purchases). Several state commissions and legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution service, which is called retail wheeling, and phasing in retail wheeling over the next several years. The competitive pricing environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, we expect that most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with qualifying facilities and exempt wholesale generators. On the other hand, qualifying facilities and exempt wholesale generators may be subject to pressure to lower their contract prices in an effort to reduce the stranded investment costs of their utility customers. We believe that, as a predominantly low cost producer of electricity, we will ultimately benefit from any increased competition that may arise from the opening of the retail market. Although our exempt wholesale generators are forbidden under the Public Utility Holding Company Act from selling electric power in the retail market, our exempt wholesale generators can sell at wholesale to a power marketer which could resell at retail. Furthermore, qualifying facilities are permitted to market power directly to large industrial users that could not 80 previously be served, because of local franchise laws or the inability to obtain retail wheeling. We also believe we will compete effectively as a wholesale supplier to power marketers serving the newly-open retail markets. Environmental Regulation 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 operations. 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. The Clean Air Act provides the statutory framework to implement a program for achieving national ambient air quality standards in areas exceeding such standards and provides for maintenance of air quality in areas already meeting such standards. Among other requirements, it also restricts the emission of toxic air contaminants and provides for the reduction of sulfur dioxide emissions to address acid deposition. In 1990, Congress passed amendments to the Clean Air Act that greatly expanded the scope of federal regulations in several significant respects. 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 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 81 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 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. 82 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 was not submitted by the Clinton Administration to the Senate for ratification, and the Bush Administration has announced its opposition to the Kyoto Protocol. 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, as a result of the treaty or otherwise, we 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 not aware of any material liabilities under this act; however, we cannot assure you that we will not incur CERCLA liability or similar state law liability in the future. Legal Proceedings PMNC Litigation In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County, entitled The Parsons Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which the plaintiffs asserted general monetary claims under the Construction Turnkey Agreement in the amount of $136.8 million. Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the Construction Turnkey Agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment in the amount of $43 million against Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount of $0.5 million. Brooklyn Navy Yard is appealing the attachment order. On the same day, the court stayed all proceedings in the California action pending the New York action. PMNC's motion to dismiss the New York action was denied by the New York Supreme Court and further denied on appeal in September 1998. On March 9, 1999, Brooklyn Navy Yard filed a motion for partial summary judgment in the New York action. The motion was denied and Brooklyn Navy Yard has appealed. The appeal and the commencement of discovery were suspended until June 2000 to allow for voluntary mediation between the parties. The mediation ended unsuccessfully on March 23, 2000. On November 13, 2000, a New York appellate court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum meruit, and limiting PMNC to its claims under the construction contract. Discovery is continuing. We agreed to indemnify Brooklyn Navy Yard and our partner in the venture from all claims and costs arising from or 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. EcoElectrica Potential Environmental Proceeding 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. At December 31, 2001, no loss accrual had been recorded by EcoElectrica. We do not believe the outcome of this matter will have a material adverse effect on our consolidated financial position or results of operations. 83 MANAGEMENT Directors and Executive Officers Our directors are elected by, and serve until their successors are elected by, our sole stockholder. Our officers are elected from time to time by the board of directors and hold office at the discretion of the board of directors. Set forth below are our current directors and executive officers and their ages and positions with us as of April 24, 2001.
Name Age Position ---- --- -------- John E. Bryson.......................... 57 Director, Chairman of the Board Dean A. Christiansen.................... 41 Director Theodore F. Craver, Jr.................. 49 Director Bryant C. Danner........................ 63 Director Director, President and Chief Alan J. Fohrer.......................... 50 Executive Officer Robert M. Edgell........................ 54 Executive Vice President and Division President of Edison Mission Energy, Asia Pacific William J. Heller....................... 44 Senior Vice President and Division President of Edison Mission Energy, Europe, Central Asia, Middle East and Africa Senior Vice President Worldwide Ronald L. Litzinger..................... 41 Operations Senior Vice President and President of Midwest Generation Georgia R. Nelson....................... 51 EME, LLC Senior Vice President and Chief Kevin M. Smith.......................... 43 Financial Officer Senior Vice President and Raymond W. Vickers...................... 58 General Counsel
Described below are the principal occupations and business activities of our directors and executive officers for the past five years, in addition to their positions indicated above. Mr. Bryson has been Director and Chairman of the Board of Edison Mission Energy since January 2000. Mr. Bryson was Director of Edison Mission Energy from January 1986 to January 1998. Mr. Bryson has been President of Edison International since January 2000 and Chairman of the Board and Chief Executive Officer of Edison International since 1990. Mr. Bryson served as Chairman of the Board, Chief Executive Officer and a Director of Southern California Edison from 1990 to January 2000. Mr. Bryson is a director of The Boeing Company, The Times Mirror Company, and Pacific American Income Shares, Inc. and LM Institutional Fund Advisors I, Inc. Mr. Christiansen has been Director of Edison Mission Energy since January 15, 2001 and serves as Edison Mission Energy's independent director. Mr. Christiansen has been President of Lord Securities since October 2000 and has been President of Acacia Capital since May 1990. Mr. Christiansen has been a Director of Capital Markets Engineering & Trading, New York since August 1999 and has been Director of Structural Concepts Corporation of Muskegon, MI since May 1995. Mr. Craver has been Director of Edison Mission Energy since January 15, 2001. Mr. Craver has been Senior Vice President, Chief Financial Officer and Treasurer of Edison International since January 2000. Mr. Craver has been Chairman of the Board and Chief Executive Officer of Edison Enterprise since September 1999. Mr. Craver served as Senior Vice President and Treasurer of Edison International from February 1998 to January 2000. Mr. Craver served as Senior Vice President and Treasurer of Southern California Edison from February 1998 to September 1999. Mr. Craver served as Vice President and Treasurer of Edison International and Southern California Edison from September 1996 to February 1998. Mr. Craver was Executive Vice President and Corporate Treasurer of First Interstate Bancorp from September 1990 to April 1996. Mr. Danner has been Director of Edison Mission Energy since May 1993. Mr. Danner has been Executive Vice President and General Counsel of Edison International since June 1995. Mr. Danner was Executive Vice 84 President and General Counsel of Southern California Edison from June 1995 until January 2000. Mr. Danner was Senior Vice President and General Counsel of Edison International and Southern California Edison from July 1992 until May 1995. Mr. Edgell has been Executive Vice President of Edison Mission Energy since April 1988. Mr. Edgell served as Director of Edison Mission Energy from May 1993 to January 2001. Mr. Edgell was named Division President of Edison Mission Energy's Asia Pacific region in January 1995. Mr. Fohrer has been Director, President and Chief Executive Officer of Edison Mission Energy since January 2000. From 1998 to 2000, Mr. Fohrer served as Chairman of the Board of Edison Mission Energy. From 1993 to 1998, Mr. Fohrer served as Vice Chairman of the Board of Edison Mission Energy. Mr. Fohrer was Executive Vice President and Chief Financial Officer of Edison International and was Executive Vice President and Chief Financial Officer of Southern California Edison from June 1995 until January 2000. Effective February 1996 and June 1995, Mr. Fohrer also served as Treasurer of Southern California Edison and Edison International, respectively, until August 1996. Mr. Fohrer was Senior Vice President, Treasurer and Chief Financial Officer of Edison International, and Senior Vice President and Chief Financial Officer of Southern California Edison from January 1993 until May 1995. Mr. Fohrer was Edison Mission Energy's interim Chief Executive Officer between May 1993 and August 1993. From 1991 until 1993, Mr. Fohrer was Vice President, Treasurer and Chief Financial Officer of Edison International and Southern California Edison. Mr. Heller has been Senior Vice President and Division President of Edison Mission Energy, Europe, Central Asia, Middle East and Africa since February 2000. Mr. Heller was elected Director of Edison Mission Energy's Board, effective December 9, 1999, and subsequently resigned effective February 7, 2000. Mr. Heller was Senior Vice President of Strategic Planning and New Business Development for Edison International from January 1996 until February 2000. Prior to joining Edison International, Mr. Heller was with McKinsey and Company, Inc. from 1982 to 1995, serving as principal and head of McKinsey's Los Angeles Energy Practice from 1991 to 1995. Mr. Litzinger has been Senior Vice President, Worldwide Operations, of Edison Mission Energy since June 1999. Mr. Litzinger served as Vice President- O&M Business Development from December 1998 to May 1999. Mr. Litzinger has been with Edison Mission Energy since November 1995 serving as both Regional Vice President, O&M Business Development and Manager, O&M Business Development until December 1998. Prior to joining Edison Mission Energy, Mr. Litzinger was a Reliability Supervisor with Texaco Refining and Marketing, Inc. from March 1995 to October 1995 and prior to that held numerous management positions with Southern California Edison since June 1986. Ms. Nelson has been Senior Vice President of Edison Mission Energy since January 1996 and has been President of Midwest Generation EME, LLC since May 1999. From January 1996 until June 1999, Ms. Nelson was Senior Vice President, Worldwide Operations. Ms. Nelson was Division President of Edison Mission Energy's Americas region from January 1996 to January 1998. Prior to joining Edison Mission Energy, Ms. Nelson served as Senior Vice President of Southern California Edison from June 1995 until December 1995 and Vice President of Southern California Edison from June 1993 until May 1995. Mr. Smith has been Senior Vice President and Chief Financial Officer of Edison Mission Energy since May 1999. Mr. Smith served as Treasurer of Edison Mission Energy from 1992 to 2000 and was elected a Vice President in 1994. During March 1998 until September 1999, Mr. Smith also held the position of Regional Vice President, Americas region. Mr. Vickers has been Senior Vice President and General Counsel of Edison Mission Energy since March 1999. Prior to joining Edison Mission Energy, Mr. Vickers was a partner with the law firm of Skadden, Arps, Slate, Meagher & Flom LLP concentrating on international business transactions, particularly cross- border capital markets and investment transactions, project implementation and finance. 85 DESCRIPTION OF THE NOTES The form and terms of the exchange notes and the original notes are identical in all material respects, except that transfer restrictions and registration rights applicable to the original notes do not apply to the exchange notes. For purposes of this description, references to "Edison Mission Energy," "we," "our," "ours" and "us" do not include any of our direct or indirect subsidiaries or affiliates. The following description is a summary of provisions of the indenture and the notes. It is not a complete description of the notes and is subject to, and qualified in its entirety, by reference to the notes and the indenture. We urge you to read the indenture and the notes because they, and not this description, define your rights as a holder of these notes. You may obtain a copy of the indenture and the notes from us by writing to us at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612. General We issued the original notes and will issue the exchange notes under the indenture, dated as of April 5, 2001, between us and United States Trust Company of New York, as trustee. References to the notes include the exchange notes unless the context otherwise requires. The notes are our unsecured senior obligations and rank equally in right of payment with all our other unsubordinated indebtedness. Because we conduct substantially all our business through numerous subsidiaries, all existing and future liabilities of our direct and indirect subsidiaries are and will be effectively senior to the notes with respect to the assets and cash flows of those subsidiaries. The notes are not guaranteed by, or otherwise obligations of, our project subsidiaries and project affiliates, or our other direct and indirect subsidiaries and affiliates. We issued the original notes in an aggregate principal amount of $600,000,000. We may, without the consent of the holders, increase such principal amount in the future on the same terms and conditions and with the same CUSIP number as the notes being offered hereby. The notes will mature on April 15, 2011 and will bear interest at the rate of 9.875% per annum. We will pay interest on the notes on each April 15 and October 15, beginning on October 15, to the holders of record on the immediately preceding April 1 and October 1. Interest on the notes will accrue from the most recent date to which interest has been paid, or, if no interest has been paid, from April 5, 2001. Interest will be computed on the basis of a 360-day year consisting of twelve 30-day months. The interest rate on the notes may be increased under the circumstances described in "Exchange Offer; Registration Rights." The original notes are, and the exchange notes will be, in denominations of $100,000 and any integral multiple of $1,000 in excess of $100,000. Redemption We may redeem the notes at any time, in whole or in part, at a redemption price equal to: . the greater of (1) 100% of the principal amount of the notes being redeemed; or (2) the sum of the present values of the Remaining Scheduled Payments on the notes being redeemed discounted to the date of redemption on a semiannual basis, assuming a 360-day year consisting of twelve 30-day months, at a rate equal to the Treasury Rate plus 75 basis points, . plus, in either case, accrued and unpaid interest, if any, on the principal amount of notes being redeemed to the redemption date. "Remaining Scheduled Payments" means, with respect to each note that we are redeeming, the remaining scheduled payments of the principal and interest on that note that would be due after the related redemption date if we were not redeeming that note. However, if the redemption date is not a scheduled interest payment date with respect to that note, the amount of the next succeeding scheduled interest payment on that note will be reduced by the amount of interest accrued on that note to the redemption date. 86 "Treasury Rate" means, with respect to any redemption date, an annual rate equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the redemption date. The semiannual equivalent yield to maturity will be computed as of the third business day immediately preceding the redemption date. "Comparable Treasury Issue" means the United States Treasury security selected by Credit Suisse First Boston Corporation or an affiliate as having a maturity comparable to the remaining term of the notes that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the notes. "Comparable Treasury Price" means the average of three Reference Treasury Dealer Quotations obtained by the trustee in respect of the notes to be redeemed on the applicable redemption date. "Reference Treasury Dealer Quotation" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by a Reference Treasury Dealer at 3:30 p.m., New York City time, on the third business day preceding the redemption date. "Reference Treasury Dealers" means Credit Suisse First Boston Corporation (so long as it continues to be a primary U.S. Government securities dealer) and any two other primary U.S. Government securities dealers chosen by us. If Credit Suisse First Boston Corporation ceases to be a primary U.S. Government securities dealer, we will appoint in its place another nationally recognized investment banking firm that is a primary U.S. Government securities dealer. We will give notice to The Depository Trust Company ("DTC") and holders of definitive notes at least 30 days (but not more than 60 days) before we redeem the notes. If we redeem only some of the notes, DTC's practice is to choose by lot the amount to be redeemed from the notes held by each of its participating institutions. DTC will give notice to these participants, and these participants will give notice to any "Street Name" holders of any indirect interests in the notes according to arrangements among them. These notices may be subject to statutory or regulatory requirements. We will not be responsible for giving notice of a redemption of the notes to anyone other than DTC and holders of definitive notes. Covenants Restrictions on Liens We will agree not to: (X) pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or other lien upon any property at any time directly owned by us to secure any indebtedness for money borrowed which is incurred, issued, assumed or guaranteed by us ("Indebtedness"), or (Y) cause or permit any of our subsidiaries to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or other lien upon any property at any time directly owned by them to secure any Indebtedness of ours, without, in each such case, providing for the notes to be equally and ratably secured with any and all such Indebtedness and with any other Indebtedness similarly entitled to be equally and ratably secured; provided, however, that the restrictions set forth in clauses (X) and (Y) above will not apply to, or prevent the creation or existence of: (1) liens existing at the original date of issuance of the notes; 87 (2) purchase money liens which do not exceed the cost or value of the purchased property; (3) other liens not to exceed 10% of our Consolidated Net Tangible Assets, provided that: (A) neither we nor our subsidiaries will be permitted to create or to permit to exist any liens to secure our Indebtedness in reliance upon this item (3) until the earlier to occur of: (x) the first date on or after the second anniversary of the consummation of the offering of the notes on which the notes are rated at least BBB- by Standard & Poor's and Baa3 by Moody's, and (y) the date on which Standard & Poor's rates the notes BBB or higher and Moody's rates the notes Baa2 or higher; and (B) notwithstanding the restriction in clause (A) above, we and our subsidiaries will be permitted to create and permit to exist liens in reliance upon this item (3) to secure Indebtedness not to exceed $100 million in the aggregate; (4) liens granted in connection with extending, renewing, replacing or refinancing in whole or in part the Indebtedness (including, without limitation, increasing the principal amount of such Indebtedness, other than the Indebtedness referred to in item (3)(B)) secured by liens described in clauses (1) through (3) above; and (5) liens granted by any of our subsidiaries on the capital stock or assets of any project subsidiary in order to secure any Indebtedness that we incur (other than Indebtedness the proceeds of which are used to finance the equity contributed by us, or loans made by us, to a project) in order to finance or refinance any acquisition, development, construction, expansion, operation or maintenance of such project subsidiary. "Consolidated Net Tangible Assets" means, as of any date of determination, the total amount of all of our assets, determined on a consolidated basis in accordance with generally accepted accounting principles as of such date, less the sum of: (a) our consolidated current liabilities, determined in accordance with generally accepted accounting principles, and (b) our assets that are properly classified as intangible assets in accordance with generally accepted accounting principles, except for any intangible assets which are distribution or related contracts with an assignable value. If we propose to pledge, mortgage or hypothecate any property at any time directly owned by us to secure any Indebtedness, other than as permitted by clauses (1) through (5) of the second previous paragraph, we will agree to give prior written notice thereof to the trustee, who will give notice to the holders of notes, and we will further agree, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively to secure all the notes equally and ratably with such Indebtedness. Except as set forth above, this covenant will not restrict the ability of our subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or lien upon their assets, in connection with project financings, sale-leasebacks or otherwise. Merger, Consolidation, Sale, Lease or Conveyance We will agree not to merge or consolidate with or into any other person and we will agree not to sell, lease or convey all or substantially all of our assets to any person, unless (1) we are the continuing corporation, or the successor corporation or the person that acquires all or substantially all of our assets is a corporation organized and existing under the laws of the United States or a State thereof or the District of Columbia and expressly assumes all our obligations under the notes and the indenture, (2) immediately after such merger, consolidation, sale, lease or conveyance, there is no default or Event of Default (as defined below) under the 88 indenture, (3) if, as a result of the merger, consolidation, sale, lease or conveyance, any or all of our property would become the subject of a lien that would not be permitted by the indenture, we secure the notes equally and ratably with the obligations secured by that lien and (4) we deliver or cause to be delivered to the trustee an officers' certificate and opinion of counsel each stating that the merger, consolidation, sale, lease or conveyance comply with the indenture. The meaning of the term "all or substantially all of the assets" has not been definitely established and is likely to be interpreted by reference to applicable state law if and at the time the issue arises and will be dependent on the facts and circumstances existing at the time. Except for a sale of all or substantially all our assets as provided above, and other than assets we are required to sell to conform with governmental regulations, we may not sell or otherwise dispose of any assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if, on a pro forma basis, the aggregate net book value of all such sales during the most recent 12-month period would exceed 10% of our Consolidated Net Tangible Assets (as defined above) computed as of the end of the most recent quarter preceding such sale; provided, however, that any such sales shall be disregarded for purposes of this 10% limitation if the proceeds are invested in assets in similar or related lines of our business; and, provided further, that we may sell or otherwise dispose of assets in excess of this 10% limitation if we retain the proceeds from such sales or dispositions, which are not reinvested as provided above, as cash or cash equivalents or if we use the proceeds from such sales to purchase and retire notes or to reduce or retire Indebtedness ranking equal in right of payment to the notes or indebtedness of our subsidiaries. Reporting Obligations We will agree to furnish or cause to be furnished to holders of notes copies of our annual reports and of the information, documents and other reports that we are required to file with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Exchange Act within 15 days after we file them with the Securities and Exchange Commission. Additional Covenants Subject to certain exceptions and qualifications, we will agree in the indenture to do, among other things, the following: (1) deliver to the trustee copies of all reports that we file with the Securities and Exchange Commission; (2) deliver to the trustee annual officers' certificates with respect to our compliance with our obligations under the indenture; (3) maintain our corporate existence, subject to the provisions described above relating to mergers and consolidations; (4) pay our taxes when due, except when we are contesting such taxes in good faith; and (5) following the effectiveness of any registration statement filed by us pursuant to the registration rights agreement, we will maintain our status as a reporting company under the Exchange Act whether or not the Securities and Exchange Commission rules and regulations require us to maintain that status (unless the Securities and Exchange Commission will not accept the filing of the applicable reports) or pay an additional interest rate on the notes in the amount of one half of one percent (50 basis points) per annum. Modification of the Indenture The indenture will contain provisions permitting us and the trustee, with the consent of the holders of at least a majority in aggregate principal amount of notes then outstanding, to modify or amend the indenture or 89 the rights of the holders of notes. However, no such modification or amendment may, without the consent of the holder of each outstanding note affected thereby: (a) change the stated maturity of the principal of, or extend the time of payment of interest on, any note; (b) reduce the principal amount of, or interest on, any note; (c) change the place or currency of payment of principal of, or interest on, any note; (d) reduce any amount payable upon the redemption of any note; or (e) impair the right to institute suit for the enforcement of any payment on or with respect to any note. In addition, without the consent of the holders of all notes then outstanding, no such modification or amendment may: (x) reduce the percentage in principal amount of outstanding notes the consent of whose holders is required for modification or amendment of the indenture; (y) reduce the percentage in principal amount of outstanding notes necessary for waiver of compliance with certain provisions of the indenture or for waiver of certain defaults; or (z) modify such provisions with respect to modification and waiver. The holders of at least a majority in principal amount of the outstanding notes may waive compliance by Edison Mission Energy with certain restrictive provisions of the indenture. The holders of a majority in principal amount of the outstanding notes may waive any past default under the indenture, except a default in the payment of principal or interest and certain covenants and provisions of the indenture which cannot be amended without the consent of the holder of each outstanding note affected. We and the trustee may, without the consent of any holder of notes, amend the indenture and the notes for the purpose of curing any ambiguity, or of curing, correcting or supplementing any defective provision thereof, or in any manner that we and the trustee may determine is not inconsistent with the indenture and the notes and will not adversely affect the interest of any holder of notes. Events of Default Each of the following will be an "Event of Default" under the indenture: (a) our failure to pay any interest on any note when due, which failure continues for 30 days; or (b) our failure to pay principal or premium when due; or (c) our failure to perform any other covenant in the notes or the indenture for a period of 90 days after the trustee or the holders of at least 25% in aggregate principal amount of the notes gives us written notice of our failure to perform; or (d) an event of default occurring under any of our instruments under which there may be issued, or by which there may be secured or evidenced, any Indebtedness for money borrowed that has resulted in the acceleration of such Indebtedness, or any default occurring in payment of any such Indebtedness at final maturity (and after the expiration of any applicable grace periods), other than: (i) Indebtedness which is payable solely out of the property or assets of a partnership, joint venture or similar entity of which we or any of our subsidiaries or affiliates is a participant, or which is secured by a lien on the property or assets owned or held by such entity, without further recourse to or liability of us; or (ii) Indebtedness, excluding (i) above, not exceeding $20,000,000; or (e) one or more nonappealable final judgments, decrees or orders of any court, tribunal, arbitrator, administrative or other governmental body or similar entity for the payment of money aggregating more 90 than $20,000,000 shall be rendered against us (excluding the amount thereof covered by insurance) and shall remain undischarged, unvacated and unstayed for more than 90 days, except while being contested in good faith by appropriate proceedings; or (f) certain events of bankruptcy, insolvency or reorganization in respect of us. If any Event of Default (other than an Event of Default due to certain events of bankruptcy, insolvency or reorganization) has occurred and is continuing, either the trustee or the holders of not less than 25% in principal amount of the notes outstanding under the indenture may declare the principal of all notes under the indenture and interest accrued thereon to be due and payable immediately. The trustee will be entitled, subject to the duty of the trustee during a default to act with the required standard of care, to be indemnified by the holders of notes before proceeding to exercise any right or power under the indenture at the request of such holders. Subject to such provisions in the indenture for the indemnification of the trustee and certain other limitations, the holders of a majority in principal amount of the notes then outstanding may direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee. No holder of notes may institute any action against us under the indenture (except actions for payment of overdue principal or interest) unless: (1) such holder previously has given the trustee written notice of the default and continuance thereof; (2) the holders of not less than 25% in principal amount of the notes then outstanding have requested the trustee to institute such action and offered the trustee reasonable indemnity; (3) the trustee has not instituted such action within 60 days of the request; and (4) the trustee has not received direction inconsistent with such written request from the holders of a majority in principal amount of the notes then outstanding. Defeasance and Covenant Defeasance Defeasance We will be deemed to have paid and will be discharged from any and all obligations in respect of the notes on the 123rd day after we have made the deposit referred to below, and the provisions of the indenture will cease to be applicable with respect to the notes (except for, among other matters, certain obligations to register the transfer of or exchange of the notes, to replace stolen, lost or mutilated notes, to maintain paying agencies and to hold funds for payment in trust) if: (A) we have deposited with the trustee, in trust, money and/or certain U.S. government obligations that, through the payment of interest and principal in respect thereof in accordance with their terms, will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes at the time such payments are due in accordance with the terms of the indenture; (B) we have delivered to the trustee: (i) an opinion of counsel to the effect that note holders will not recognize income, gain or loss for federal income tax purposes as a result of the defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect or a change in applicable federal income tax law or related treasury regulations after the date of the indenture; and (ii) an opinion of counsel to the effect that the defeasance trust does not constitute an "investment company" within the meaning of the Investment Company Act of 1940 and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law; 91 (C) immediately after giving effect to such deposit, no Event of Default, or event that after the giving of notice or lapse of time or both would become an Event of Default, will have occurred and be continuing on the date of such deposit or during the period ending on the 123rd day after the date of such deposit, and such deposit shall not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which we are a party or by which we are bound; and (D) if at such time the notes are listed on a national securities exchange, we have delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of such deposit and discharge. Defeasance of Certain Covenants and Certain Events of Default The provisions of the indenture will cease to be applicable with respect to: (x) the covenants described in "--Covenants" (other than those with respect to the maintenance of our existence and those described under the first paragraph of the caption "--Covenants--Merger, Consolidation, Sale, Lease or Conveyance" other than those described in clauses (2)-(5) under "--Covenants--Additional Covenants"); (y) clause (c) in "--Events of Default" with respect to such covenants; and (z) clauses (d) and (e) in "--Events of Default" upon (1) the deposit with the trustee, in trust, of money and/or certain U.S. government obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes, (2) the satisfaction of the conditions described in clauses (B)(ii), (C) and (D) of the preceding paragraph, and (3) our delivery to the trustee of an opinion of counsel to the effect that, among other things, the holders of the notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. Defeasance and Certain Other Events of Default If we exercise our option to omit compliance with certain covenants and provisions of the indenture as described in the immediately preceding paragraph and the notes are declared due and payable because of the occurrence of an Event of Default that remains applicable, the amount of money and/or U.S. government obligations on deposit with the trustee may not be sufficient to pay amounts due on the notes at the time of acceleration resulting from such Event of Default. In such event, we will remain liable for such payments. Book-Entry; Delivery and Form The certificates representing the exchange notes will be issued in fully registered form. Except as described below, the exchange notes initially will be represented by one or more global notes, in definitive, fully registered form without interest coupons. The global notes will be deposited with the trustee as custodian for DTC and registered in the name of Cede & Co. or another nominee as DTC may designate. DTC has advised us as follows: . DTC is a limited purpose trust company organized under the laws of the State of New York, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the Uniform Commercial Code and a "clearing agency" registered pursuant to the provision of Section 17A of the Exchange Act. 92 . DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thus eliminating the need for physical movement of certificates. Participants include securities brokers and dealers, banks, trust companies and clearing corporations and other organizations. Indirect access to the DTC system is available to others, including banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly. . Upon the issuance of the global notes, DTC or its custodian will credit, on its internal system, the respective principal amounts of the exchange notes represented by the global notes to the accounts of persons who have accounts with DTC. Ownership of beneficial interests in the global notes will be limited to persons who have accounts with DTC or persons who hold interests through the persons who have accounts with DTC. Persons who have accounts with DTC are referred to as "participants." Ownership of beneficial interests in the global notes will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee, with respect to interests of participants, and the records of participants, with respect to interests of persons other than participants. So long as DTC or its nominee is the registered owner or holder of the global notes, DTC or the nominee, as the case may be, will be considered the sole record owner or holder of the exchange notes represented by the global notes for all purposes under the indenture and the exchange notes. No beneficial owners of an interest in the global notes will be able to transfer that interest except according to DTC's applicable procedures, in addition to those provided for under the indenture. Owners of beneficial interests in the global notes will not: . be entitled to have the exchange notes represented by the global notes registered in their names, . receive or be entitled to receive physical delivery of certificated notes in definitive form, and . be considered to be the owners or holders of any exchange notes under the global notes. Accordingly, each person owning a beneficial interest in the global notes must rely on the procedures of DTC and, if a person is not a participant, on the procedures of the participant through which that person owns its interests, to exercise any right of a holder of exchange notes under the global notes. We understand that under existing industry practice, in the event an owner of a beneficial interest in the global notes desires to take any action that DTC, as the holder of the global notes, is entitled to take, DTC would authorize the participants to take that action, and that the participants would authorize beneficial owners owning through the participants to take that action or would otherwise act upon the instructions of beneficial owners owning through them. Payments of the principal of, premium, if any, and interest on the exchange notes represented by the global notes will be made to DTC or its nominee, as the case may be, as the registered owner of the global notes. Neither we, the trustee, nor any paying agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the global notes or for maintaining, supervising or reviewing any records relating to the beneficial ownership interests. We expect that DTC or its nominee, upon receipt of any payment of principal of, premium, if any, or interest on the global notes will credit participants' accounts with payments in amounts proportionate to their respective beneficial ownership interests in the principal amount of the global notes, as shown on the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in the global notes held through these participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for these customers. These payments will be the responsibility of these participants. Transfer between participants in DTC will be effected in the ordinary way in accordance with DTC rules. If a holder requires physical delivery of notes in certificated form for any reason, including to sell notes to 93 persons in states which require the delivery of the notes or to pledge the notes, a holder must transfer its interest in the global notes in accordance with the normal procedures of DTC and the procedures described in the indenture. Unless and until they are exchanged in whole or in part for certificated exchange notes in definitive form, the global notes may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC. Beneficial owners of exchange notes registered in the name of DTC or its nominee will be entitled to be issued, upon request, exchange notes in definitive certificated form. DTC has advised us that DTC will take any action permitted to be taken by a holder of notes, including the presentation of notes for exchange as described below, only at the direction of one or more participants to whose account the DTC interests in the global notes are credited. Further, DTC will take any action permitted to be taken by a holder of notes only in respect of that portion of the aggregate principal amount of notes as to which the participant or participants has or have given that direction. Although DTC has agreed to these procedures in order to facilitate transfers of interests in the global notes among participants of DTC, it is under no obligation to perform these procedures, and may discontinue them at any time. Neither we nor the trustee will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations. Subject to specified conditions, any person having a beneficial interest in the global notes may, upon request to the trustee, exchange the beneficial interest for exchange notes in the form of certificated notes. Upon any issuance of certificated notes, the trustee is required to register the certificated notes in the name of, and cause the same to be delivered to, the person or persons, or the nominee of these persons. In addition, if DTC is at any time unwilling or unable to continue as a depositary for the global notes, and a successor depositary is not appointed by us within 90 days, we will issue certificated notes in exchange for the global notes. 94 EXCHANGE OFFER; REGISTRATION RIGHTS As part of the sale of the original notes, under a registration rights agreement, dated as of April 2, 2001, we agreed with the initial purchasers in the offering of the original notes, for the benefit of the holders of the notes, to file with the SEC an exchange offer registration statement or, if applicable, within a specified time period, a shelf registration statement unless we were to determine in good faith that applicable SEC policy or applicable law did not permit us to effect this exchange offer. Under the registration rights agreement, we agreed to use our reasonable best efforts to cause to become effective a registration statement and maintain its effectiveness, as described in the registration rights agreement. We agreed to bear all expenses incurred in connection with our obligations under the registration rights agreement. Once this registration statement is declared effective, we will offer exchange notes that are identical in all material respects to the restricted original notes in return for surrender of the original notes. This offer will remain open for no less than the shorter of 30 days after the date notice of the exchange offer is mailed to the original note holders and the period ending when the last remaining original note is tendered into the exchange offer. For each original note surrendered to us under the exchange offer, the original note holder will receive exchange notes in an equal principal amount. Interest on each exchange note will accrue from the last date on which interest was paid on the original note so surrendered or, if no interest has been paid, since April 5, 2001. In the event that we reasonably determine in good faith that (1) the exchange notes would not be tradeable, upon receipt in the exchange offer, without restriction, (2) the SEC is unlikely to permit the exchange offer registration statement to become effective prior to the 270th day after the date of original issue of the notes or (3) the exchange offer may not be made in compliance with applicable laws, we will use our reasonable best efforts, subject to customary representations and agreements of the note holders, to have a shelf registration statement covering the resale of the original notes declared effective and kept effective until, April 5, 2003 subject to specified exceptions. We will, in the event of a shelf registration, provide to each note holder copies of the prospectus, notify each note holder when a registration statement for the notes has become effective and take other actions as are appropriate to permit resale of the notes. In the event that a registration statement is not declared effective within 270 days following the date of the original issue of the notes, the annual interest rates on the notes will be increased by 0.50% per annum effective on the 271st day following the date of the original issue, which increase will remain in effect until the date on which an exchange offer is commenced and an exchange offer registration statement will have become effective or a shelf registration statement will have become effective. In the event that a registration statement is required to be filed with the SEC and becomes effective and later ceases to be effective at any time during the period specified by the registration rights agreement, the annual interest rate on the notes will be increased by 0.50% per annum from and after the date such registration statement ceases to be effective to, but excluding, such date when the registration statement again becomes effective (or, if earlier, the end of such period specified by the registration rights agreement). Such additional interest will be paid to note holders on a regular distribution date. The interest rate on the notes will be increased by 0.50% per annum if we cease to maintain our status as a reporting company under the Exchange Act whether or not the SEC rules and regulations require us to maintain that status (unless the SEC will not accept the filing of the applicable reports). In the event that more than one of the aforementioned events occurs at the same time, the maximum increase in the interest rate applicable to the notes shall be 0.50% per annum. Each note holder, other than specified holders, who wishes to exchange its original notes for exchange notes in the exchange offer will be required to represent that: . it is not our affiliate; . any exchange notes to be acquired by it will be acquired in the ordinary course of business; and . that at the time of the completion of the exchange offer it will have no arrangement with any person to participate in the distribution, within the meaning of the Securities Act, of the exchange notes. 95 A note holder that sells its notes under a shelf registration generally: . would be required to be named as a selling holder in the related prospectus and to deliver a prospectus to purchasers; . will be subject to certain of the civil liability provisions under the Securities Act in connection with this sale; and . will be required to agree in writing to be bound by the provisions of the registration rights agreement which are applicable to the selling note holder, including specified indemnification obligations. MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS The following summary describes certain material United States federal income tax considerations of the acquisition, ownership and disposition of the exchange notes. The summary is based on the Internal Revenue Code of 1986, as amended (the "Code"), and regulations, rulings and judicial decisions as of the date hereof, all of which may be repealed, revoked or modified with possible retroactive effect. This discussion does not deal with holders that may be subject to special tax rules (including, but not limited to, insurance companies, tax-exempt organizations, financial institutions, dealers in securities or currencies, holders whose functional currency is not the United States dollar or holders who will hold the exchange notes as a hedge against currency risks or as part of a straddle, synthetic security, conversion transaction or other integrated investment comprised of the notes and one or more other investments). The summary is applicable only to purchasers that acquired the original notes pursuant to the offering at the initial offering price and who will hold the exchange notes as capital assets within the meaning of Section 1221 of the Code. This summary is for general information only and does not address all aspects of United States federal income taxation that may be relevant to holders of the exchange notes in light of their particular circumstances, and it does not address any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction. Prospective holders should consult their own tax advisors as to the particular tax consequences to them of acquiring, holding or disposing of the exchange notes. As used herein, the term "United States Holder" means a beneficial owner of a note that is (i) a citizen or resident of the United States for United States federal income tax purposes, (ii) a corporation or partnership (or any entity treated as a corporation or partnership for United States federal income tax purposes) created or organized under the laws of the United States, any state thereof or the District of Columbia, (iii) an estate the income of which is subject to United States federal income tax without regard to its source or (iv) a trust if (x) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or (y) the trust has a valid election in effect under applicable United States Treasury regulations to be treated as a United States Holder. If a partnership (including any entity treated as a partnership for United States federal income tax purposes) is a holder of the notes, the United States federal income tax treatment of a partner in such a partnership will generally depend on the status of the partner and the activities of the partnership. Partners in such a partnership should consult their own tax advisors as to the particular federal income tax consequences applicable to them. A "Non-United States Holder" is any beneficial holder of a note that is not a United States Holder. For United States federal income tax purposes, a beneficial owner of an original note will not recognize any taxable gain or loss on the exchange of the original notes for exchange notes under the exchange offer, and a beneficial owner's tax basis and holding period in the exchange notes will be the same as in the original notes. United States Holders Stated interest on an exchange note generally will be taxable to a United States Holder as ordinary income at the time it accrues or is received in accordance with the United States Holder's method of accounting for United States federal income tax purposes. 96 Upon the sale, exchange, redemption, retirement or other disposition of an exchange note, a United States Holder generally will recognize gain or loss equal to the difference between the amount realized upon the sale, exchange, redemption, retirement or other disposition (not including amounts attributable to accrued but unpaid interest, which will be taxable as ordinary income) and such United States Holder's adjusted tax basis in the exchange note. A United States Holder's adjusted tax basis in an exchange note will, in general, be the United States Holder's adjusted tax basis in the original note exchanged for the exchange note, less any principal payments received by such holder. Such gain or loss will generally be capital gain or loss. Capital gain recognized by an individual investor upon a disposition of an exchange note that has been held for more than 12 months will generally be subject to a maximum tax rate of 20% or, in the case of an exchange note that has been held for 12 months or less, will be subject to tax at ordinary income tax rates. A United States Holder's holding period for an exchange note will include the holding period of the original note exchanged for the exchange note. Non-United States Holders Under present United States federal income tax law, subject to the discussion of backup withholding and information reporting below: (a) payments of interest on the exchange notes to any Non-United States Holder will not be subject to United States federal income, branch profits or withholding tax provided that (i) the Non-United States Holder does not actually or constructively own 10% or more of the total combined voting power of all classes of our stock entitled to vote, (ii) the Non-United States Holder is not a bank receiving interest on an extension of credit pursuant to a loan agreement entered into in the ordinary course of its trade or business, (iii) the Non-United States Holder is not a controlled foreign corporation that is related to us (directly or indirectly) through stock ownership, (iv) such interest payments are not effectively connected with a United States trade or business, (v) the Non-United States Holder is not a foreign tax exempt organization or foreign private foundation for United States federal income tax purposes and (vi) certain certification requirements are met. Such certification will be satisfied if the beneficial owner of the exchange note certifies on IRS Form W-8 BEN or a substantially similar substitute form, under penalties of perjury, that it is not a United States person and provides its name and address, and (x) such beneficial owner files such form with the withholding agent or (y) in the case of an exchange note held through a foreign partnership or intermediary, the beneficial owner and the foreign partnership or intermediary satisfy certification requirements of applicable United States Treasury regulations; and (b) a Non-United States Holder will not be subject to United States federal income or branch profits tax on gain realized on the sale, exchange, redemption, retirement or other disposition of an exchange note, unless (i) the gain is effectively connected with a trade or business carried on by such holder within the United States or, if a treaty applies (and the holder complies with applicable certification and other requirements to claim treaty benefits), is generally attributable to a United States permanent establishment maintained by the holder, or (ii) the holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met. An exchange note held by an individual who at the time of death is not a citizen or resident of the United States will not be subject to United States federal estate tax with respect to an exchange note as a result of such individual's death, provided that (i) the individual does not actually or constructively own 10% or more of the total combined voting power of all classes of our stock entitled to vote and, (ii) the interest accrued on the exchange note was not effectively connected with the conduct of a United States trade or business. Backup Withholding and Information Reporting In general, payments of interest and the proceeds of the sale, exchange, redemption, retirement or other disposition of the exchange notes payable by a United States paying agent or other United States intermediary will be subject to information reporting. In addition, backup withholding at a rate of 31% will generally apply 97 to these payments if (i) in the case of a United States Holder, the holder fails to provide an accurate taxpayer identification number, or fails to certify that such holder is not subject to backup withholding or fails to report all interest and dividends required to be shown on its United States federal income tax returns, or (ii) in the case of a Non-United States Holder, the holder fails to provide the certification on IRS Form W-8BEN described above or otherwise does not provide evidence of exempt status. Certain United Status Holders (including, among others, corporations) and Non-United States Holders that comply with certain certification requirements are not subject to backup withholding. Any amount paid as backup withholding will be creditable against the holder's United States federal income tax liability provided that the required information is timely furnished to the IRS. Holders of exchange notes should consult their tax advisors as to their qualification for exemption from backup withholding and the procedure for obtaining such an exemption. PLAN OF DISTRIBUTION Each broker-dealer that receives exchange notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for original notes where the original notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any resale. In addition, until August 2, 2001, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus. We will not receive any proceeds from any sale of exchange notes by broker- dealers. Exchange notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of these methods of resale. These resales may be made at market prices prevailing at the time of resale, at prices related to these prevailing market prices or negotiated prices. Any resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any of the exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of the exchange notes may be deemed to be an underwriter within the meaning of the Securities Act, and any profit on the resale of exchange notes and any commission or concessions received by those persons may be deemed to be underwriting compensation under the Securities Act. Any broker-dealer that resells notes that were received by it for its own account in the exchange offer and any broker-dealer that participates in a distribution of those notes may be deemed to be an underwriter within the meaning of the Securities Act and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction, including the delivery of a prospectus that contains information with respect to any selling holder required by the Securities Act in connection with any resale of the exchange notes. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an underwriter within the meaning of the Securities Act. Furthermore, any broker-dealer that acquired any of its original notes directly from us: . may not rely on the applicable interpretation of the staff of the SEC's position contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983); and . must also be named as a selling noteholder in connection with the registration and prospectus delivery requirements of the Securities Act relating to any resale transaction. For a period of 180 days after the expiration date of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that 98 requests these documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer, including the expenses of one counsel for the holders of the notes, other than commissions or concessions of any brokers or dealers. We will indemnify the holders of the notes, including any broker-dealers, against various liabilities, including liabilities under the Securities Act. In addition, all reports and other documents we subsequently file under Sections 13(a) and 15(d) of the Securities Exchange Act will be deemed to be incorporated by reference into this prospectus and to be part of this prospectus from the date we subsequently file the reports and documents. Any statements contained in a document incorporated or deemed to be incorporated by reference into this prospectus are deemed to be modified or superseded for purposes of this prospectus to the extent modified or superseded by another statement contained in any subsequently filed document also incorporated by reference in this prospectus. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute part of this prospectus. You may request a copy of any of these filings, at no cost, by writing or telephoning us at the following address or phone number: Edison Mission Energy 18101 Von Karman Avenue, Suite 1700 Irvine, California 92612 (949) 752-5588 Attention: Corporate Secretary LEGAL MATTERS The legality of the exchange notes will be passed upon for Edison Mission Energy by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. EXPERTS The consolidated financial statements of Edison Mission Energy and subsidiaries included in Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2000, which is incorporated by reference in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said report. 99 We have not authorized any dealer, salesperson or other person to give any information or represent anything not contained in this prospectus. You must not rely on unauthorized information. This prospectus does not offer to sell or buy any notes in any jurisdiction where it is unlawful. The information in this prospectus is current as of May 4, 2001. However, you should realize that our affairs may have changed since the date of this prospectus. Until August 2, 2001, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions. [LOGO OF EDISON MISSION ENERGY APPEARS HERE]