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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

Commission File Number 000-24890

Edison Mission Energy

(Exact name of registrant as specified in its charter)

*

Issued by Mission Capital, L.P., a limited partnership in which Edison Mission Energy is the sole general partner. The payments of distributions on the preferred securities and payments on liquidation or redemption are guaranteed by Edison Mission Energy.

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES    /x/        NO    / /

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

        Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of March 28, 2002: $0. Number of shares outstanding of the registrant's Common Stock as of March 28, 2002: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

The Company

        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, 2001, we owned interests in 31 domestic and 49 international operating power projects with an aggregate generating capacity of 23,967 Megawatts, or MW, of which our share was 19,019 MW. At that date, one domestic and six international projects, totaling 1,153 MW of generating capacity, of which our anticipated share will be approximately 668 MW, were under construction. At December 31, 2001, we had consolidated assets of $10.7 billion and total shareholder's equity of $1.6 billion.

        We are incorporated under the laws of the State of Delaware. 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. Unless indicated otherwise or the context otherwise requires, references in this Annual Report on Form 10-K are with respect to Edison Mission Energy and its consolidated subsidiaries and the partnerships or limited liability entities through which Edison Mission Energy and its partners own and manage their project investments.

Forward-Looking Statements

        This annual report 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 annual report 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:

•

our ability to maintain an investment grade rating;



•

our ability to refinance short-term debt or raise additional financing for our future cash requirements;



•

supply, demand and price for electric capacity and energy in the markets served by our generating units;



•

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;



•

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; and



•

the cost, availability and pricing of fuel and fuel transportation services for our generating units.

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        We use words like "anticipate," "estimate," "project," "plan," "expect," "will," "believe" and similar expressions to help identify forward-looking statements in this annual report.

        For additional factors that could affect the validity of our forward-looking statements, and for other risk factors affecting our business and financial condition, you should read "Management's Discussion and Analysis of Results of Operations and Financial Condition—Risk Factors and -Critical Accounting Policies" contained in Part II, Item 7 and the "Notes to Consolidated Financial Statements" contained in Part II, Item 8. The information contained in this report is subject to change without notice. Readers should review future reports filed by us with the Securities and Exchange Commission. 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 annual report 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.

Description of Business

Electric Power Industry

        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 ourselves, 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. In deregulating markets, industry trends and regulatory initiatives have caused vertically integrated, price regulated utilities, to enter into markets in which generators complete with each other for their principal customers (wholesale power suppliers, distribution companies, and major end-users) on the basis of price, reliability and other factors. As a result of the recent energy crisis in California, some states have either discontinued or delayed implementation of initiatives involving retail deregulation. These developments have generally not affected the market structures in Illinois and Pennsylvania, where many of our of power plants are located.

        The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity has also led to the development of significant new markets for independent power producers outside the United States. We have developed or acquired power plants in the Asia-Pacific region and in Europe and the Middle East regions as a result of these developments.

Competition

        We and our subsidiaries are subject to intense competition in the United States and overseas from energy marketers, utilities, industrial companies and other independent power producers. Over the past several years, the restructuring of energy markets has led to the sale of utility-owned assets to us and our competitors. More recently, in response to market conditions, we and other power generators have changed focus from acquisition and growth to concentrating on selective asset dispositions as well as postponing or canceling power plants under development. This trend is in response to credit concerns

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in the wake of the bankruptcy of Enron Corp., economic recession in the United States, and a potential oversupply of new generating capacity.

        In markets where we sell power from plants where the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, we are subject to substantial competition with independent power producers with power plants located in the same geographic region. We compete primarily based on price, reliability and other factors which are heavily influenced by electricity demand and supply, which is commonly referred to as capacity. Our customers include large electric utilities or regional distribution companies. In some cases, the electric utilities and distribution companies have their own generation capacity, including nuclear generation, that affects the amount of generation available to meet demand and may affect the price of electricity in a particular market.

        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 services, could also lead to increased competition in the independent power market. See "—Regulatory Matters—Retail Competition."

Segment Information

        We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia-Pacific and Europe and Middle East. Our plants are located in different geographic areas, which mitigate the effects of regional markets, economic downturns or unusual weather conditions. These regions take advantage of the increasing globalization of the independent power market. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 19. Business Segments."

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Regional Overview of Business Segments

        As of December 31, 2001, we had ownership or leasehold interests in the following domestic operating projects:

(1)

Operated by subsidiaries or affiliates of Edison Mission Energy; all other projects are operated by unaffiliated third parties.

(2)

Currently offered for sale.

(3)

Sold subsequent to December 31, 2001.

(4)

Electric purchaser abbreviations are as follows:

(5)

All the cogeneration projects are gas-fired facilities, except for the James River project, which we recently sold, which used coal. All the exempt wholesale generator (EWG) projects are gas-fired facilities, except for the Homer City facilities and six of the Illinois plants, which use coal.

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        As of December 31, 2001, we had ownership or leasehold interests in the following international operating projects:

(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:

(3)

Sells to the pool with a long-term contract with SE.

(4)

Sells to the pool with a long-term contract with NORWEB.

(5)

Sells to the pool with a long-term contract with the State Electricity Commission of Victoria.

(6)

Minority interest in three projects.

(7)

Minority interest in one project.

Americas

        As of December 31, 2001, we had 31 operating projects in this region, all of which are presently located in the United States and its territories. Our Americas region is headquartered in Chicago,

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Illinois, with additional offices located in Irvine, California, and Boston, Massachusetts. A description of our power plants and major investments in energy projects in the Americas region is set forth below.

Illinois Plants

        On December 15, 1999, we completed a transaction with Commonwealth Edison, now 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 are located in the Mid-America Interconnected Network, which has transmission connections to the East Central Area Reliability Council and other regional markets. In connection with this transaction, we entered into three power purchase agreements with Commonwealth Edison with terms of up to five years expiring in 2004, pursuant to which Commonwealth Edison purchases capacity and has the right to purchase energy generated by the plants. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, LLC. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement. Our power purchase agreements with Exelon Generation accounted for 36% and 42% of our electric revenues for 2001 and 2000, respectively. See further discussion of the power purchase contracts with Exelon Generation under "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

        The Illinois plants are comprised of the following:

        As part of the purchase of the Illinois plants, we assigned our right to purchase the Collins Station to third-party entities and our subsidiary simultaneously entered into long-term lease of the Collins Station. We also completed sale-leaseback transactions with respect to our Illinois peaker units in July 2000 and our Powerton and Joliet power facilities in August 2000. We sold these assets and entered into long-term leases to provide capital to finance our acquisition or to repay corporate debt while maintaining control of the use of the power plants during the terms of the leases. See further

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discussion of these sale-leaseback transactions under "Management's Discussion and Analysis of Results of Operations and Financial Condition—Off-Balance Sheet Financing."

Homer City Facilities

        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. These facilities consist of three coal-fired steam turbine units, one coal preparation facility, an 1,800-acre site and associated support facilities in the mid-Atlantic region of the United States and have 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. For further discussion of the risks related to the sale of electricity from the Homer City facilities, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

        On December 7, 2001, our subsidiary completed a sale-leaseback of the Homer City facilities to third-party lessors. We sold the Homer City facilities and entered into long-term leases to provide capital to repay corporate debt while maintaining control of the use of the facilities during the terms of the leases. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Off-Balance Sheet Financing."

Major Investments in California Cogeneration Projects

        We own partnership investments in the Kern River Cogeneration Company, Midway Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, as described below. These projects have similar economic characteristics and have been used, collectively, to obtain bond financing by a special purpose entity, Edison Mission Energy Funding Corp., a special purpose entity that we include in our consolidated financial statements. Due to similar economic characteristics and the bond financing related to our equity investments, we view these projects collectively and refer to them as the Big 4 projects.

        Kern River Project—We own a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which we refer to as the Kern River project. Kern River Cogeneration sells electricity to Southern California Edison Company under a power purchase agreement that expires in 2005 and sells steam to Texaco Exploration and Production Inc. under a steam supply agreement that also expires in 2005.

        Midway-Sunset Project—We own a 50% partnership interest in Midway Sunset Cogeneration Company, which owns a 225 MW natural gas-fired cogeneration facility located near Taft, California, which we refer to as the Midway-Sunset project. Midway-Sunset sells electricity to Southern California Edison, Aera Energy LLC and Pacific Gas & Electric Company under power purchase agreements that expire in 2009 and sells steam to Aera under a steam supply agreement that also expires in 2009.

        Sycamore Project—We own a 50% partnership interest in Sycamore Cogeneration Company, which owns and operates a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which we refer to as the Sycamore project. Sycamore Cogeneration sells electricity to Southern California Edison under a power purchase agreement that expires in 2007 and sells steam to Texaco Exploration and Production Inc. under a steam supply agreement that also expires in 2007.

        Watson Project—We own a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural gas-fired cogeneration facility located in Carson, California, which we refer to as the Watson project. Watson Cogeneration sells electricity to Southern California Edison and to the adjacent British Petroleum refinery under power purchase agreements that expire in 2008 and sells steam to ARCO Products Company under a steam supply agreement that also expires in 2008.

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        We have a partnership interest in Sunrise Power Company that resulted from our efforts to add additional capacity in California in response to the California power crisis. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—The California Power Crisis."

        Sunrise Project—We own a 50% partnership interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern County, California, which we refer to as the Sunrise project. The Sunrise project consists of two phases. Phase I, a simple-cycle gas-fired facility (320 MW) was completed on June 27, 2001. Phase II, conversion to a combined-cycle gas-fired facility (560 MW), is currently scheduled to be completed in July 2003. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. For further discussion related to this agreement, see "Legal Proceedings—Sunrise Regulatory Proceedings."

Other Small Investments in Energy Projects

        We also own 50% investments in seven other small energy projects (less than 100 MW of net electric capacity) that are located in the United States. Each project sells electricity under a long-term power purchase agreement with the local electric utility.

Americas Projects Offered For Sale

        Our remaining projects in the Americas region consist of our Brooklyn Navy Yard, Gordonsville and EcoEléctrica projects described below. We are currently offering all of our interests in these projects for sale.

        Brooklyn Navy Yard Project—We own a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York, which we refer to as the Brooklyn Navy Yard project. Brooklyn Navy Yard sells electricity and steam to Consolidated Edison Company of New York, Inc. under a power purchase agreement that expires in 2039. See "Legal Proceedings—PMNC Litigation" for information regarding disputes related to the construction of this facility.

        Gordonsville Project—We own a 50% partnership interest in Gordonsville Energy, L.P., which owns a 240 MW natural gas-fired cogeneration facility located in Gordonsville, Virginia, which we refer to as the Gordonsville project. Gordonsville Cogeneration sells electricity to Virginia Electric & Power Company under a power purchase agreement that expires in 2024 and sells steam to Rapidan Service Authority under a steam supply agreement that also expires in 2024.

        EcoEléctrica Project—We own a 50% partnership interest in EcoEléctrica L.P., which owns a 540 MW power plant located Peñuelas, Puerto Rico, which we refer to as the EcoEléctrica project. EcoEléctrica sells electricity to Puerto Rico Electric Power Authority under a power purchase agreement that expires in 2018 and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2018.

Asset Sales

        During 2001, we decided to offer for sale some of our non-strategic investments in energy projects to reduce debt. At December 31, 2001, we had agreements to sell five of our projects. Subsequent to December 31, 2001, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project. The sales of our interests in the EcoEléctrica and Gordonsville projects did not close, and in each case, the sales agreement has terminated and we have recommenced marketing efforts. On March 8, 2002, we filed a complaint against Mirant Corporation and two of its affiliates, alleging that Mirant wrongfully terminated the sale agreement for the purchase of the EcoEléctrica project. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Dispositions" for further details about our asset sales.

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Investment in Four Star Oil and Gas Company

        We own a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil and Gas Company, with majority control held by affiliates of ChevronTexaco Corp. Four Star Oil and Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. Under a long-term service contract, the majority of Four Star Oil and Gas's properties are operated through Texaco Exploration & Production Inc. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Investments" for financial information on our oil and gas investments.

Asia-Pacific

        As of December 31, 2001, we had 15 operating projects in this region that are located in Australia, Indonesia, Thailand and New Zealand. Our Asia-Pacific region is headquartered in Singapore, with additional offices located in Australia, Indonesia and the Philippines. A description of our power plants, investment in Contact Energy and investments in energy projects in the Asia-Pacific region is set forth below.

Australia

        Loy Yang B Project—We own a 1,000 MW coal-fired power station in located in Traragon, Victoria, Australia, which we refer to as the Loy Yang B project. The project sells electricity to 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 spot price each half-hour. We have entered into an agreement with the State Electricity Commission of Victoria, which agreement we refer to as the State Hedge, that provides through October 16, 2016 for the project to receive a fixed price for a portion of its electricity in exchange for payment to the State of the spot price applicable to such portion. For further discussion of risks related to the sale of electricity from the Loy Yang B project, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

        Valley Power Peaker Project—During 2001, we began construction of a 300 MW gas-fired peaker plant located at the Loy Yang B coal-fired power plant site, which we refer to as the Valley Power Peaker project. The peaker units will service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with other power generators and distribution businesses. We own a 60% interest in the Valley Power Peaker project, with the remaining interest held by our 51.2%-owned affiliate, Contact Energy.

        Kwinana Project—We own a 70% interest in a 116 MW gas-fired cogeneration plant in Perth, Australia, which we refer to as the Kwinana project. We sell electricity to Western Power under a power purchase agreement that expires in 2021 and sell steam to the British Petroleum Kwinana refinery under a steam supply agreement which also expires in 2021.

New Zealand

        Contact Energy—We own a 51.2% majority interest in Contact Energy Limited. The remaining shares of Contact Energy are publicly held and traded on the New Zealand stock exchange. Contact

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Energy is the largest wholesaler and retailer of natural gas in New Zealand and generates about one-quarter of New Zealand's electricity. Contact Energy owns the following power plants:

(1)

Located in Australia.

        Contact Energy also owns a 40% interest in the Valley Power Peaker project under construction in Australia with the remaining interest held by a wholly-owned subsidiary of ours.

Indonesia

        The Paiton Project—We own a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia, which we refer to as the Paiton project. Paiton Energy sells electricity to PT PLN, the state-owned electric utility company, under a power purchase agreement that expires in 2029. PT PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN as well as settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the terms of the power purchase agreement from 2029 to 2039. For a further discussion of the Paiton project, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Contingencies."

Philippines

        CBK Project—In February 2001, we purchased a 50% interest in CBK Power Co. Ltd. CBK Power has entered into a 25-year build-rehabilitate-operate-transfer (BROT) agreement with National Power Corporation related to the 728 MW Caliraya-Botocan-Kalayaan hydroelectric project located in the Philippines, which we refer to as the CBK project. CBK Power is paid capital recovery fees and operations and maintenance fees for generating electricity and providing other services under the BROT agreement. At December 31, 2001, 168 MW have been commissioned and are operational.

Thailand

        Tri Energy Project—We own a 25% interest in Tri Energy Company Limited, which owns a 700 MW gas-fired cogeneration plant located west of Bangkok, Thailand, which we refer to as the Tri Energy project. Tri Energy sells electricity to Electricity Generating Authority of Thailand, which is known as EGAT, under a power purchase agreement that expires in 2020.

Europe and Middle East

        As of December 31, 2001, we had 34 operating projects in this region that are located in the U.K., Turkey, Spain and Italy. Our Europe and Middle East region is headquartered in London, England, with additional offices located in Italy, Spain and Turkey. The London office was established in 1989. A description of our power plants and investments in energy projects in the Europe and Middle East region is set forth below.

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United Kingdom

        First Hydro Project—We own two pumped storage stations in North Wales at Dinorwig and Ffestiniog which have a combined capacity of 2,088 MW, which we refer to as the First Hydro project. Pump storage stations consume electricity when it is comparatively less expensive in order to pump water up 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. We sell electricity and ancillary services to regional electricity companies, other generators and into short-term markets. For further discussion of the risks related to the sale of electricity from the First Hydro project, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

        Lakeland Project—We own a 220 MW combined-cycle natural gas-fired power plant located in Barrow-in-Furness, Cumbria, United Kingdom, which we refer to as the Lakeland project. We sell electricity to North Western Electricity Board under a power purchase contract that expires in 2006.

        Derwent Project—We own a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW gas-fired cogeneration plant in Derby, England, which we refer to as the Derwent project. Derwent sells electricity to Southern Electric plc under a power purchase agreement that expires in 2010 and sells steam to Courtaulds Chemicals (Holdings) Limited under a steam supply contract that also expires in 2010.

Italy

        ISAB Project—We own a 49% interest in ISAB Energy S.r.l. which owns a 512 MW integrated gasification combined cycle power plant in Sicily, Italy, which we refer to as the ISAB project. ISAB sells electricity to Gestore Rete Transmissione Nazionale, Italy's state transmission company, under a power purchase agreement that expires in 2020. The ISAB project is located at an oil refinery owned by ERG Petroli SpA.

        Italian Wind Project—In 2000, we purchased Edison Mission Wind Power Italy B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy by UPC International Partnership CV II, which we collectively refer to as the Italian Wind project. The projects use wind to generate electricity from turbines, which is sold under fixed-price, long-term tariffs to Gestore Rete Transmissione Nazionale. At December 31, 2001, 230 MW have been commissioned and are operational. Assuming all the projects under construction at December 31, 2001 are completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW.

Spain

        Spanish Hydro Project—We own 18 small, run-of-the-river hydroelectric plants regionally dispersed in Spain totaling 86 MW, which we refer to as the Spanish Hydro project. We sell electricity to Fuerzas Electricas de Cataluma, S.A. under concessions that have various expiration dates ranging from 2030 to 2065.

Turkey

        Doga Project—We own an 80% interest in Doga Enerji, which owns a 180 MW gas-fired cogeneration plant in Istanbul, Turkey, which we refer to as the Doga project. Doga Enerji sells electricity to Turkiye Elektrik Urehm, A.S., commonly known as TEAS, under a power purchase agreement that expires in 2018.

        In addition to the facilities and power plants that we own, we use the term "our" in regard to facilities and power plants that we operate under sale-leaseback arrangements.

Discontinued Operations

        As a result of the change in the prices of power in the U.K. and the anticipated negative impacts of such changes on earnings and cash flow, we offered for sale through a competitive bidding process

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the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in our consolidated financial statements. See, "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Discontinued Operations."

Trading and Risk Management Activities

        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 general policy to deal with investment grade counterparties or counterparties that have equivalent credit quality. Our risk management committees grant exceptions to the policy only after review and scrutiny. Most entities that have received exceptions are typically organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants in order to provide more predictable earnings and cash flow. 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 domestic power marketing and trading organization, Edison Mission Marketing & Trading, Inc., markets and trades electric power and energy related to commodity products, including forwards, futures, options and swaps. It also provides services and price risk management capabilities to the electric power industry. We segregate our activities into two categories:

•

Marketing and Fuel Management—Edison Mission Marketing & Trading engages in the sale of electricity and purchase of fuels through intercompany contracts with our subsidiaries that own or lease the Illinois plants and the Homer City facilities. The objective of these activities is to sell the output of the power plants on a forward basis, thereby increasing the predictability of earnings and cash flows. Edison Mission Marketing & Trading also conducts risk management activities to manage the price risk associated with the purchase of fuels, including natural gas and fuel oil. Transactions entered into related to marketing and fuel management activities are designated separately from Edison Mission Marketing & Trading's trading activities and recorded in what Edison Mission Marketing & Trading calls its hedge book (we record these transactions on an accrual basis unless fair value accounting is required).

•

Trading—In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. Edison Mission Marketing & Trading generally balances forward sales and purchases contracts and manages its exposure through a value at risk analysis, as described further below. Edison Mission Marketing & Trading also conducts price risk management activities for third parties including restructuring of power sales and power supply agreements. Collectively, Edison Mission Marketing & Trading refers to these as its trading activities and records these transactions in what it calls its proprietary book.

        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. Edison Mission Marketing & Trading has systems in place which monitor real time spot and forward pricing and perform option valuations. Edison Mission Marketing & Trading also has a wholesale power scheduling group that operates on a 24-hour basis.

        Internationally, we also conduct price risk management activities through subsidiaries that are primarily focused on marketing and fuel management activities in the same manner described above.

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        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 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 stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.

Seasonality

        Due to warmer weather during the summer months, electric revenues generated from the Homer City facilities 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 the summer months. The First Hydro plants and the Iberian Hy-Power plants provide for higher electric revenues during the winter months.

Regulatory Matters

General

        Our operations are subject to extensive regulation by governmental agencies in each of the countries in which we conduct operations. Our domestic operating 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. 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. 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.

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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 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

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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 facilities, the Illinois plants, and Brooklyn Navy Yard 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.

        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 ultimate 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 might develop or 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.

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        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 MW 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 from 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.

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        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 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—Many 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.

State Energy Regulation, California Deregulation and Recent Foreign Regulatory Matters

        See the discussion on state regulation, California deregulation and recent foreign regulatory matters in "Management's Discussion and Analysis of Results of Operations and Financial Condition—The California Power Crisis," and "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

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.

        In issuing Order No. 888 et al., the Federal Energy Regulatory Commission determined that the open-access rules set forth in the Order would apply to transmission with respect to wholesale sales and also with respect to retail transactions where the transmission component had been unbundled from the

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retail sale by state regulatory action or voluntarily by the utility making the retail sale. The Commission declined to assert jurisdiction over retail transmission that remained bundled into the retail sale. Subsequent court appeals of Order No. 888 have been brought by parties challenging the Order on the basis that the Commission had no authority to regulate the transmission of unbundled retail sales and by those challenging the Commission's failure to include the transmission of bundled retail sales in the order. On June 30, 2000, the U.S. Court of Appeals for the District of Columbia Circuit upheld the decision by the Federal Energy Regulatory Commission in both respects, finding that the Commission did have jurisdiction to regulate transmission of unbundled retail transactions, and that it was not required to assert jurisdiction over transmission embedded in bundled retail sales. In an opinion issued on March 4, 2002, the Supreme Court affirmed the decision of the Court of Appeals.

        In the meantime, while Order No. 888 was pending judicial review, it became apparent to the Federal Energy Regulatory Commission that the Order was not having the desired effects of eliminating discriminatory behavior by transmission owning utilities and in promoting the development of competitive wholesale electricity markets. Accordingly, in an effort to remedy the shortcomings it perceived, the Commission, on December 20, 1999, issued Order No. 2000, which required all transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing their transmission assets under a Regional Transmission Organization, or RTO, meeting certain criteria set forth in the Order. Although Order No. 2000 did not mandate that a utility join an RTO, it set forth various incentives for voluntary action by utilities to take such action and required them to explain in detail their reasons for deviating from the objectives set forth in the Order. RTOs meeting the Commission's criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential attributes, such as regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring capability, and other features. In subsequent orders, the Commission has progressively tightened its policies in favor of RTO formation, by such means as an explicit proposal that approvals of market-based rate authority for affiliates of utilities owning transmission should be tied to such utilities' placing their transmission assets in an RTO meeting the criteria of Order No. 2000. These and other regulatory initiatives by the Federal Energy Regulatory Commission are ongoing, and it is not possible to predict the extent of future developments. However, the direction of regulatory policy at the Commission appears generally positive for continued progress toward competitive wholesale electricity markets.

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.

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Environmental Matters and Regulations

        See discussion on environmental matters and regulations in "Management's Discussion and Analysis of Results of Operations and Financial Condition—Environmental Matters and Regulations."

Employees

        At December 31, 2001, Edison Mission Energy employed 3,021 people, all of whom were full-time employees and 188, 152 and 1,236 of whom were covered by collective bargaining agreements in the United Kingdom, Australia and the United States, respectively. We believe we have good relations with our employees.

        Between early June and mid-October of 2001, our subsidiary, Midwest Generation, and the union that represents the employees at the Illinois plants were in negotiations to replace the expired collective bargaining agreement, covering wages and working conditions. The union authorized a strike that began on June 28, 2001. Midwest Generation operated the Illinois plants during the strike. Negotiations have concluded with a new four-year agreement that was ratified by the represented employees on October 16, 2001. Pursuant to the reinstatement process, employees began returning to work on October 22, 2001.

Our Relationship with Certain Affiliated Companies

        Edison Mission Energy is an indirect subsidiary of Edison International. Edison International 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. Southern California Edison has faced material operating disruptions as a result of the California power crisis. For a description of the California power crisis, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—The California Power Crisis."

Tax Sharing Agreement

        We are also 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.

ITEM 2. PROPERTIES

        We lease our principal office in Irvine, California. This lease covers approximately 142,000 square feet. The term of the lease for approximately 65,500 square feet expires on December 31, 2004 with two five-year options to extend. The term of the lease for the balance of approximately 76,500 square feet expires on December 31, 2004 with no options to extend. We also lease office space in Chicago, Illinois; Chantilly, Virginia; Boston, Massachusetts; Fairfax, Virginia and Washington D.C. The Chicago lease is for approximately 41,000 square feet and expires on December 31, 2009. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010. The Boston lease is for approximately 40,500 square feet and expires on July 31, 2007. Both the Fairfax and the Washington D.C. leases are immaterial. At December 31, 2001, approximately 31% of the above space was either available for sublease or subleased. Our subsidiaries in the Asia Pacific region lease office space in Manila, Philippines; Melbourne, Australia; Jakarta, Indonesia; and Singapore. Our subsidiaries in the Europe and Middle East region lease office space in Barcelona, Spain; Istanbul, Turkey; London, England; and Rome, Italy. These subsidiary leases are immaterial.

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        The following table shows the material properties owned or leased by us or our projects. Each property represents at least five percent of our income before tax or is one in which we have an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project.

Description of Properties

(1)

Currently offered for sale.

ITEM 3. 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 for the project 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. On February 14, 2002, PMNC moved to amend the complaint in the New York action to add us as a defendant and to seek a $43 million attachment against us. This motion is presently calendared for May 2002. We agreed to indemnify Brooklyn Navy Yard and our partner in

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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.

EcoEléctrica Potential Environmental Proceeding

        We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoEléctrica 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 EcoEléctrica. We do not believe the outcome of this matter will have a material adverse effect on our consolidated financial position or results of operations. We are currently offering our interest in the EcoEléctrica project for sale.

Sunrise Regulatory Proceedings

        Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleges that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board complaint makes a similar allegation and requests that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. In response, on March 19, 2002, Sunrise filed a motion to dismiss with the Federal Energy Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion; however, we cannot predict what actions the Federal Energy Regulatory Commission may take at this proceeding.

Paiton Labor Suit

        In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and the former President Director of PT PLN are also named as defendants in the suit. The union seeks to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement then in effect between Paiton Energy and its lenders, as well as damages and other relief. The initial preliminary hearing was held on April 30, 2001 in Jakarta. Paiton Energy and the other defendants filed challenges to jurisdiction and moved for a dismissal of the suit, but such actions were denied by an order dated July 23, 2001. Paiton Energy has filed a notice of appeal. Paiton Energy believes, based upon discussions with its Indonesian counsel, that the suit is without merit.

        We experience other routine litigation in the normal course of our business. None of our pending litigation is expected to have a material adverse effect on our consolidated financial position or results of operations. See "Business—Regulatory Matters—Environmental Regulation."

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        Inapplicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS

        All the outstanding Common Stock of Edison Mission Energy is, as of the date hereof, owned by Mission Energy Holding Company, which is a wholly-owned subsidiary of The Mission Group, a wholly-owned subsidiary of Edison International. There is no market for the Common Stock. Dividends on the Common Stock will be paid when declared by our board of directors. We made cash dividend payments to The Mission Group totaling $65 million and $88 million during 2001 and 2000, respectively, and after our change in ownership to Mission Energy Holding Company, we made cash dividend payments totaling $32.5 million in 2001.

        Our articles of incorporation and bylaws contain restrictions on our ability to declare or pay dividends or distributions. These restrictions require the unanimous approval of our board of directors, including at least one independent director, before we can declare or pay dividends or distributions, unless either of the following are true:

•

we then have investment grade ratings with respect to our senior unsecured long-term debt and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or



•

such dividends and distributions 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.

        Our interest coverage ratio for the four quarters ended December 31, 2001 was 1.64 to 1. Accordingly, until our interest coverage ratio exceeds 2.2 to 1 for the immediately preceding four quarters, we can only pay dividends if we have an investment grade rating and have received rating agency confirmation that a dividend will not result in a downgrade or have received unanimous approval of our board of directors, including our independent director. For more information on these restrictions, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Credit Ratings."

        Company-Obligated Mandatorily Redeemable Securities of Partnership Holding Solely Parent Debentures. In November 1994, Mission Capital, L.P., a limited partnership of which Edison Mission Energy is the sole general partner, issued 3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a price of $25 per security. These securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2024 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have been redeemed as of December 31, 2001. During August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly Income Preferred Securities, Series B at a price of $25 per security. These securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2025 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have been redeemed as of December 31, 2001. We issued a guarantee in favor of the holders of the preferred securities, which guarantees the payments of distributions declared on the preferred securities, payments upon a liquidation of Mission Capital and payments on redemption with respect to any preferred securities called for redemption by Mission Capital. So long as any preferred securities remain outstanding, we will not be able to declare or pay, directly or indirectly, any dividend on, or purchase, acquire or make a distribution or liquidation payment with respect to, any of our common stock if at such time (i) we shall be in default with respect to our payment obligations under the guarantee, (ii) there shall have occurred any event of default under the subordinated indenture, or (iii) we shall have given notice of our selection of an extended interest payment period as provided in the indenture and such period, or any extension thereof, shall be continuing.

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ITEM 6.    SELECTED FINANCIAL DATA

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

        The following discussion contains forward-looking statements. These statements are based on our current plans and expectations and involve risks and uncertainties which could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. Important factors that could cause actual results to differ include risks set forth 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, 2001, we owned interests in 31 domestic and 49 international operating power projects with an aggregate generating capacity of 23,967 MW, of which our share was 19,019 MW. At that date, one domestic and six international projects, totaling 1,153 MW of generating capacity, of which our anticipated share will be approximately 668 MW, were under construction. At December 31, 2001, we had consolidated assets of $10.7 billion and total shareholder's equity of $1.6 billion.

        Our operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 85%, 89% and 79% of our total operating revenues during 2001, 2000 and 1999, respectively. Our consolidated operating revenues during those years also include equity in income from oil and gas investments, net gains (losses) from energy trading and price risk management activities and revenues attributable to operation and maintenance services.

        Our current strategy is focused on strengthening our balance sheet through the selective disposition of assets, enhancing the performance of our existing portfolio of power projects and aligning our staffing needs to meet these objectives.

Acquisitions, Dispositions and Sale-Leaseback Transactions

Acquisition of Interest in CBK Power Co. Ltd.

        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 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project comprises equity commitments of $110.6 million, of which our 50% share is $55.3 million, and debt financing which is in place for the remainder of the cost for this project. As of December 31, 2001, we have made equity contributions of $10 million. For a more detailed discussion of the commitment to contribute project equity, refer to "—Contractual Obligations, Commitments and Contingencies—Firm Commitments to Contribute Project Equity."

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Acquisition of Sunrise Project

        On November 17, 2000, we completed a transaction with Texaco Power & Gasification Holdings 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 had an option to repurchase, at cost, a 50% interest in the project prior to its commercial operation, which commenced on June 27, 2001. On June 25, 2001, Texaco exercised its option and repurchased a 50% interest for $84 million. As part of our acquisition of the Sunrise project, we also: (i) acquired from Texaco two gas turbines for the project and (ii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future power plant projects we designate. The Sunrise project consists of two phases, with Phase I, a simple-cycle gas-fired facility (320 MW), completed on June 27, 2001, and Phase II, conversion to a combined-cycle gas-fired facility (560 MW), currently scheduled to be completed in July 2003. We entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. See "—Legal Proceedings—Sunrise Regulatory Proceedings."

        The total purchase price of the Sunrise project from Texaco was $27 million. We funded the purchase with cash. The total estimated construction cost of this project through 2003 is approximately $459 million. The project intends to obtain project financing for a portion of the capital costs.

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 operations beyond the traditional marketing of our electric power to include trading of electricity and fuels, although this represents a small portion of our consolidated operations. 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 Project

        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. At December 31, 2001, 230 MW have been commissioned and are operational. Assuming all the projects under construction at December 31, 2001 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, with equity contribution obligations of up to 33 billion Italian Lira, depending on the number of projects that are ultimately developed. As of December 31, 2001, our payments in respect of these projects included 77 billion Italian Lira ($37.4 million) toward the purchase price and 33 billion Italian Lira ($16.3 million), which funded our entire equity contribution obligation.

Acquisition of Illinois Plants

        On December 15, 1999, we completed a transaction with Commonwealth Edison, now 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 are located in the

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Mid-America Interconnected Network which has transmission connections to the East Central Area Reliability Council and other regional markets. In connection with this transaction, we entered into three power purchase agreements with Commonwealth Edison with terms of up to five years expiring in 2004, pursuant to which Commonwealth Edison purchases capacity and has the right to purchase energy generated by the plants. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, LLC. Exelon Generation provided us notice to continue the agreement related to the coal units and the Collins Station for 2002. In October 2001, Exelon Generation terminated the power purchase agreement for the peaker units with respect to 300 megawatts of oil peakers, effective January 2002, but continued the agreement for all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.

        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 MW 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 our debt and $1.2 billion in equity contributions to us from Edison International.

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 a New Zealand and 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. 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 2,302 MW.

        Consideration for our interest in Contact Energy consisted of a cash payment of approximately $635 million (NZ$1.2 billion), which was financed by $120 million of preferred securities, a $214 million (NZ$400 million 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.

        During 2000, we increased our share of ownership in Contact Energy to 42.6%. Subsequently, during the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to 51.2%. Due to acquisition of a controlling interest, we began accounting for Contact Energy on a consolidated basis effective June 1, 2001. Prior to June 1, 2001, we used the equity method of accounting for Contact Energy. In order to finance the purchase of the additional shares, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which was syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held by us has been provided as collateral. On July 2, 2001, we redeemed NZ$400 million preferred securities issued by one of our subsidiaries, EME Taupo. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing documents

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provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally funded as a revolving credit facility. From June 2001 to October 2001, we issued NZ$250 million of new preferred securities through one of our subsidiaries. The proceeds were used to repay borrowings outstanding under the NZ$400 million credit facility and to repay the bridge loan.

        On October 12, 2001, we announced our intention to acquire the remaining 48.8% of Contact Energy that we do not own, thereby increasing our ownership interest to 100%. We proposed an offer of NZ$4.25 per share, including an interim dividend of NZ$0.11 per share, to the minority shareholders payable in cash. The offer commenced on November 6, 2001 and was extended until February 3, 2002. The offer was conditioned on our acquiring a 90% interest in Contact Energy, which would have enabled us to acquire the remaining minority interests through a merger. On February 4, 2002, we announced that we did not receive the necessary level of acceptances required to complete the transaction, and, therefore, we currently plan to continue with our current 51.2% ownership interest.

Acquisition of Homer City Facilities

        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 facilities 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.

        On December 7, 2001, we sold the Homer City facilities to third party lessors in a sale-leaseback transaction. See "—Sale-Leaseback Transactions" and "—Off-Balance Sheet Financing."

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 Sunrise beginning July 1, 2001, Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, the Homer City facilities beginning March 18, 1999, Contact Energy beginning May 1, 1999, and the Illinois plants beginning December 15, 1999. We began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest.

Dispositions

        On December 21, 2001, we completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements. See "—Discontinued Operations." The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.148 billion after tax) related to the loss on disposal. Net proceeds from the sales of £643 million

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were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants.

        During 2001, we also sold our 50% interest in the Nevada Sun-Peak project, 50% interest in the Saguaro project and 25% interest in the Hopewell project for a total gain on sale of $45 million ($24.4 million after tax). In addition, we entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our interests in the Commonwealth Atlantic, EcoEléctrica, Gordonsville, Harbor and James River projects. During 2001, we recorded asset impairment charges of $33.7 million related to the Commonwealth Atlantic, Gordonsville, Harbor and James River projects based on the expected sales proceeds. Subsequent to December 31, 2001, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project for $47.7 million. The sales of our interests in the EcoEléctrica and Gordonsville projects have not closed, and in each case, the sales agreement has terminated and we have recommenced marketing efforts. On March 8, 2002, we filed a complaint against Mirant Corporation and two of its affiliates, alleging that Mirant wrongfully terminated the sale agreement for the purchase of the EcoEléctrica project. We are currently offering for sale our interests in the Brooklyn Navy Yard, EcoEléctrica and Gordonsville projects.

        On June 25, 2001, we completed the sale of a 50% interest in the Sunrise project to Texaco Power & Gasification Holdings Inc. Proceeds from the sale were $84 million.

        On August 16, 2000, we completed the sale of 30% of our interest in the Kwinana cogeneration plant to SembCorp Energy. We retain the remaining 70% ownership interest in the plant. Proceeds from the sale were $12 million. We recorded a gain on the sale of $8.5 million ($7.7 million after tax).

        On June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a gain on the sale of $17 million ($10.5 million after tax).

Sale-Leaseback Transactions

        On December 7, 2001, our subsidiary completed a sale-leaseback of our Homer City facilities to third-party lessors for an aggregate purchase price of $1.591 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809.3 million). Under the terms of the 33.67-year leases, our subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, we have a right of first refusal to acquire the interest at fair market value. Minimum lease payments during the next five years are $175.0 million for 2002, $174.0 million for 2003, $142.1 million for 2004, $151.9 million for 2005, and $151.6 million for 2006. At December 31, 2001, the total remaining minimum lease payments are $3.4 billion. Lease costs will be levelized over the terms of the leases. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.

        On August 24, 2000, our subsidiary completed a sale-leaseback of our 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, which began January 2, 2001. We guarantee our subsidiary's payments under these 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 $97.3 million for 2002, $97.3 million for 2003, $97.3 million for 2004, $141.1 million for 2005, and $184.9 million for 2006. At December 31, 2001, the total remaining minimum lease payments are $2.3 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.

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        On July 10, 2000, one of our subsidiaries entered into a sale-leaseback of equipment, primarily Illinois peaker power units, to a third party lessor for $300 million. Under the terms of the 5-year lease, we have a fixed price purchase option at the end of the lease term of $300 million. We guarantee the monthly payments under the lease. In connection with the sale-leaseback, a subsidiary of ours purchased $255 million of notes issued by the lessor which accrue interest at the London Interbank Offered Rate, commonly referred to as LIBOR, plus 0.65% to 0.95%, depending on our credit rating. The notes are due and payable in 2005. The gain on the sale of equipment has been deferred and is being amortized over the term of the lease.

        For more information on these sale-leaseback transactions, see "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions."

Mission Energy Holding Company

        On June 8, 2001, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset is our common stock. In July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security interest in our common stock. Any foreclosure on the pledge of our common stock by the holders of the senior secured notes or the lenders under the term loan could result in a change of control of us. A change in control of us could require us or our subsidiaries to prepay indebtedness in our or their debt agreements. For a discussion of the provisions in our formation documents that constrain our ability to pay dividends or make distributions to Mission Energy Holding, see "—Credit Ratings".

        The respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with respect to our stock are governed by intercreditor arrangements. Both the senior secured notes and the term loan also have security interests in interest reserve accounts, covering the interest payable on those obligations for the first two years. We have not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to us. The net proceeds of the offering and the term loan not deposited into the respective interest escrow accounts were used to pay a dividend to Mission Energy Holding's parent, The Mission Group, which in turn loaned the net proceeds to its parent, Edison International. Edison International used the funds to repay a portion of its indebtedness that matured in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and the ability of our subsidiaries to enter into specified transactions or engage in specified business activities and require, in some instances, that we obtain the approval of the Mission Energy Holding's board of directors. Our articles of incorporation bind us to the restrictions in Mission Energy Holding's financing documents by restricting our ability to enter into specified transactions or engage in specified business activities, other than as permitted in Mission Energy Holding's financing documents, without shareholder approval.

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RESULTS OF OPERATIONS

        Operating revenues are derived from our majority-owned domestic and international entities. Equity in income from investments relates to energy projects where our ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which we have a significant influence but in which we do not have a controlling interest. With respect to entities accounted for under the equity method, we recognize our proportional share of the income or loss of such entities.

        As an aid in an understanding of our results of operations, the following table summarizes revenues and operating income during the past three years from major projects (in millions):

(1)

Represents percentage of our consolidated operating revenues or operating income before Corporate general and administrative expenses, interest and other expenses not reflected in our regional operations, as applicable.

(2)

Comprised of investments in Kern River project, Midway-Sunset project, Sycamore project and the Watson project. These projects are recorded on the equity method of accounting which means that we record our share of the income or loss from each partnership.

(3)

Four Star is comprised of our equity in income from our investment in Four Star Oil and Gas Company and price risk management activities described under Americas below.

        We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic regions: Americas, Asia-Pacific and Europe and Middle East. The following discussion of our operating results is set forth by region with reference to the performance of our major projects described above.

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Americas

Operating Revenues

        Operating revenues increased $42.1 million in 2001 compared to 2000, and increased $1.2 billion in 2000 compared to 1999. The 2001 increase resulted from higher electric revenues from the Homer City facilities due to higher energy prices, as compared to the prior year. This increase was partially offset by lower electric revenues from the Illinois plants in 2001 due to lower dispatch of their coal units as a result of lower market prices for power. The 2000 increase resulted from a full-year of electric revenues from the Illinois plants acquired in December 1999 and the Homer City facilities acquired in March 1999.

        Electric power generated at the Illinois plants is sold under three five-year power purchase agreements with Exelon Generation Company, terminating in December 2004. Exelon Generation is obligated to make capacity payments for the plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $1.1 billion for each of the years ended December 31, 2001 and 2000. This represented 36% and 42% of our consolidated operating revenues in 2001 and 2000, respectively. For more information on these power purchase agreements, see "—Market Risk Exposures—Illinois Plants" and "—Risk Factors."

        Net gains from energy trading activities were $10 million in 2001 and $62.2 million from September 1, 2000, the acquisition date of Citizens Power, to December 31, 2000. The 2001 decrease in gains primarily resulted from a reduction in our trading activity in 2001, as compared to 2000, due to volatility of power prices in the West Coast trading markets during the fourth quarter of 2000 and the adverse impact of the California power crisis on our credit in 2001.

        Total gains and losses from price risk management activities recorded at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133) were $25.3 million, ($79.5) million and ($6.4) million in 2001, 2000 and 1999, respectively. The 2001 gain was primarily due to realized and unrealized gains for a gas swap purchased to hedge 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 transactions of investments accounted for on the equity method, and thus, we were required to record changes in fair value of these positions through the income statement (commonly referred to as mark-to-market accounting). During 2000, we recorded a loss on these gas swaps of $87 million due to a substantial increase in gas prices in the fourth quarter of 2000. As gas prices decreased in 2001, we recorded a gain of $44.7 million on these positions resulting in a year-over-year increase in our earnings in 2001 from 2000 of $131.7 million. Partially offsetting this gain in 2001 was a

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loss resulting from the change in market value of future contracts entered into with respect to a portion of our anticipated fuel purchases through 2002 at the Illinois plants that did not qualify for hedge accounting under SFAS No. 133.

        The 2000 losses from price risk management activities recorded at fair value increased from 1999 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 discussed above. Partially offsetting the 2000 loss was a gain realized on financial options entered into beginning August 2000 as a hedge of our price risk associated with expected natural gas purchases at the Illinois plants for 2001. 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 was deferred as required by hedge accounting and was recognized during 2001 based on the date of the occurrence of the original anticipated transaction. 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 of 2000. 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 increased $96.1 million in 2001 over 2000, and increased $32.4 million in 2000 over 1999. The 2001 increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing on the West Coast during 2001 and revenues from the Sunrise project, which commenced operations in June 2001. We had no comparable results for the Sunrise project in 2000. 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.

        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 2001, 2000 and 1999 are with Southern California Edison. Our share of equity in earnings from these projects accounted for 8% in 2001, 6% in 2000 and 10% in 1999 of our consolidated revenues for the respective years. For more information on these projects and other projects in California, see "—Contractual Obligations, Commitments and Contingencies—The California Power Crisis."

        Due to warmer weather during the summer months, electric revenues generated from the Homer City facilities 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 costs increased $33.6 million in 2001 compared to 2000, and increased $893.9 million in 2000 compared to 1999. The 2001 increase was primarily due to an increase in plant operations at the Illinois plants, partially offset by lower fuel costs at these plants. The 2001 increase in plant operations resulted from lease costs related to the sale-leaseback commitments for the Powerton-Joliet power facilities and the Collins gas and oil-fired power plant. There were no comparable lease costs for the Powerton-Joliet power facilities through the period ended August 2000. See "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions" for discussion of the financial impact

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of sale-leaseback transactions. In addition, plant operations costs increased due to higher maintenance costs at the Illinois plants in 2001 from planned outages and costs of additional security related to a strike at the Illinois plants during June through October 2001. Fuel costs were lower at the Illinois plants in 2001 due to less dispatch of their coal units as compared to 2000 and decreased generation from the Collins Station and peaker plants. The 2000 increase resulted from a full year of expenses at the Illinois plants and the Homer City facilities.

        Depreciation and amortization expense decreased $24 million in 2001 compared to 2000, and increased $138.7 million in 2000 compared to 1999. The 2001 decrease resulted from lower depreciation expense at the Illinois plants related to the sale-leaseback transaction for the Powerton-Joliet power facilities with third-party lessors on August 24, 2000. The 2000 increase was primarily due to a full year of depreciation and amortization expense related to the Illinois plants.

        Asset impairment and other charges of $59.1 million consisted of $33.7 million to write down our investments to the estimated net proceeds from the planned sale of the Commonwealth Atlantic, Gordonsville, Harbor and James River projects and $25.4 million related to a loss on the termination of a portion of the Edison Mission Energy Master Turbine Lease. For more information on the termination of the lease, see "—Contractual Obligations, Commitments and Contingencies—Edison Mission Energy—Master Turbine Lease." There were no comparable asset impairment and other charges for the same prior year periods.

        Administrative and general expenses consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts and a provision for bad debts. In 2001, we recorded a provision of $8.5 million for bad debts from Enron as a result of its bankruptcy. The 2001 increase also included a full year of trading operations partially offset by higher bonuses during 2000. Prior to the September 1, 2000 acquisition of Citizens Power, administrative and general expenses incurred by our own marketing operations were reflected in Corporate/Other administrative and general expenses.

Operating Income

        Operating income increased $110.7 million in 2001 compared to 2000, and increased $160.2 million in 2000 compared to 1999. The 2001 increase was primarily due to increases in operating income from the Homer City facilities, equity in income from investments in energy projects and gains from price risk management activities discussed above. The 2000 increase was primarily due to a full year of operating income from the Illinois plants and the Homer City facilities and increased equity in income from our oil and gas investments due to higher oil and gas prices.

Asia-Pacific

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Operating Revenues

        Operating revenues increased $280.2 million in 2001 compared to 2000, and decreased $29.4 million in 2000 compared to 1999. The 2001 increase was primarily due to consolidating Contact Energy operating revenues as a result of us acquiring a controlling interest in the company, effective June 1, 2001. Electric revenues generated by Contact Energy benefited in 2001 from higher energy prices in New Zealand caused by dry and cold conditions during the third quarter of 2001. The increase was partially offset by lower U.S. dollar electric revenues from the Loy Yang B plant in Australia due to a 11.1% decrease in the average exchange rate of the Australian dollar compared to the U.S. dollar during 2001, compared to 2000. The 2000 decrease was attributable to lower electric revenues from our Loy Yang B plant. During May 2000, we experienced a major unplanned outage due to damage to the generator at one of our two 500 MW units at the Loy Yang B power plant in Australia. The unit was restored to operation in September 2000. The repair costs in excess of our $2 million deductible amount, together with the loss of profits after the first 15 days and until the unit was back in operation, were partially recovered from insurance.

        Net losses from price risk management activities recorded at fair value were $4.1 million in 2001. The losses primarily resulted from the change in the market value of interest rate swaps and options that did not qualify for hedge accounting under SFAS No. 133 and the ineffective portion of a long-term contract with the State Electricity Commission of Victoria entered into by the Loy Yang B plant, which is a derivative that qualified as a cash flow hedge under SFAS No. 133. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 4. Accumulated Other Comprehensive Income (Loss)" for further discussion.

        Equity in income from investments decreased $7.1 million in 2001 compared to 2000, and decreased $3.5 million in 2000 compared to 1999. The 2001 decrease primarily reflects Contact Energy being accounted for on a consolidated basis effective June 1, 2001, compared to the equity method of accounting prior to the acquisition of a controlling interest. The 2000 decrease was primarily due to lower profitability of our interest in Contact Energy resulting from lower electricity prices caused by milder winter weather conditions.

Operating Expenses

        Fuel and plant operations costs increased $204.4 million in 2001 compared to 2000, and decreased $12.3 million in 2000 compared to 1999. The 2001 increase was primarily due to consolidating Contact Energy operating expenses, effective June 1, 2001. The 2000 decrease resulted primarily from lower fuel costs at the Loy Yang B plant due to the major unplanned outage at one of its two 500 MW units.

        Depreciation and amortization expense increased $16.9 million in 2001 compared to 2000, and decreased $5.5 million in 2000 compared to 1999. The 2001 increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses, effective June 1, 2001. The 2000 decrease was primarily due to favorable changes in foreign exchange rates.

Operating Income

        Operating income increased $47.7 million in 2001 compared to 2000, and decreased $15.1 million in 2000 compared to 1999. The 2001 increase was primarily due to consolidating Contact Energy's results of operations, effective June 1, 2001, and the favorable impact of higher energy prices in New Zealand discussed above. The increase was partially offset by lower operating income from the Loy Yang B plant, resulting primarily from lower electric revenues due to a decrease in the value of the Australian dollar compared to the U.S. dollar. The 2000 decrease was due to lower operating income from the Loy Yang B plant resulting from the major unplanned 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.

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        Europe and Middle East (1)

(1)

The results of Ferrybridge and Fiddler's Ferry are not included in this table since the operations are classified as discontinued operations for all historical periods presented. For more information on Ferrybridge and Fiddler's Ferry, see "—Discontinued Operations."

Operating Revenues

        Operating revenues decreased $86.3 million in 2001 compared to 2000, and increased $53.0 million in 2000 compared to 1999. The 2001 decrease resulted primarily from lower capacity revenues from the First Hydro plant. On March 27, 2001, the United Kingdom pool pricing system was replaced with a bilateral physical trading system referred to as the new electricity trading arrangements. The new electricity trading arrangements are described in further detail under "—Market Risk Exposures—United Kingdom." These new electricity trading arrangements resulted in lower capacity prices in 2001, compared to 2000. The 2000 increase resulted from a full year of electric revenues from the Doga project, which commenced commercial operation in May 1999, and by higher capacity revenues from the First Hydro plants due to favorable market conditions. The First Hydro plants and the Iberian Hy-Power plants are expected to provide for higher electric revenues during the winter months.

        Net gains from price risk management activities recorded at fair value were $3.3 million in 2001. The gains primarily represent the change in market value of long-term commodity contracts entered into by the First Hydro plant for the purchase and sale of electricity that were recorded at fair value under SFAS No. 133 with changes in fair value recorded through the income statement, effective July 1, 2001. The related cumulative effect of change in accounting for these contracts is described in further detail under "—Cumulative Effect of Change in Accounting Principle—Accounting for Derivatives."

        Equity in income from investments increased $18.3 million in 2001 compared to 2000, and decreased $6.4 million in 2000 compared to 1999. The 2001 increase primarily reflects gains from the ISAB project. In 2001, the operational performance of the project substantially improved as expected, thereby achieving profitability. During 2000, we recorded losses from this project. Commercial operation of the ISAB project commenced in April 2000. The 2000 decrease was primarily due to losses incurred primarily from extended start-up and commissioning activities of the ISAB project during 2000, its first year of operation.

Operating Expenses

        Fuel and plant operations costs increased $27.1 million in 2001 compared to 2000, and increased $22.8 million in 2000 compared to 1999. The 2001 increase was primarily due to higher fuel costs at the First Hydro plant and Doga plant. The increase in fuel costs at the First Hydro plant reflects the changes under the new electricity trading arrangements. Under the new trading arrangements, fuel

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costs include contracts to purchase electricity which we used to meet sales commitments when it was more cost-effective to purchase as compared to generate electricity, thus, reducing the need for physical pumping or generating. In addition, due to the new trading arrangements, some costs previously paid by suppliers now are being paid by generators and all market participants are being charged imbalance costs when their metered position differs from their contracted position. The new electricity trading arrangements are described in further detail under "—Market Risk Exposures—United Kingdom." Fuel costs increased at the Doga plant primarily due to increased production in 2001, compared to the same prior year period. The 2000 increase resulted from a full year of expenses at the Doga project, partially offset by lower fuel expense at the First Hydro plant. Fuel expense at First Hydro decreased primarily due to lower generation levels in 2000, resulting in a lower pumping requirement.

Operating Income

        Operating income decreased $89.7 million in 2001 compared to 2000, and increased $21.3 million in 2000 compared to 1999. The 2001 decrease was primarily due to lower operating income of $105.9 million from the First Hydro plant due to lower energy and capacity prices resulting from the new electricity trading arrangements. The 2000 increase was primarily due to operating income from the Doga project and higher operating income from the First Hydro plant.

Corporate/Other

        Net gains from price risk management activities were $1.7 million in 2001. The gains primarily resulted from the change in market value of our interest rate swaps with respect to our $100 million senior notes that did not qualify for hedge accounting under SFAS No. 133.

        Long-term incentive compensation expense consists of charges related to our terminated phantom option plan. Long-term incentive compensation expenses increased $62 million in 2001 compared to 2000, and decreased $192.3 million in 2000 compared to 1999. The 2001 increase was due to a reduction in the liability for previously accrued incentive compensation by approximately $60 million recorded during 2000 and additional 2001 compensation expense related to deferred payments and annual vesting of benefits. The 2000 decrease was due to the absence of new accruals, as the plan had been terminated, and to a reduction in the liability. This reduction 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.

        Administrative and general expenses increased $1.8 million in 2001 compared to 2000, and increased $25 million in 2000 compared to 1999. There were no material changes in 2001 administrative and general expenses from 2000. The 2000 increase was primarily due to additional salaries and facilities costs incurred to support the 1999 acquisitions. We recorded a pre-tax 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

36

administrative and general operating costs, including reductions in management and administrative personnel.

Other Income (Expense)

        Interest and other income increased $4.5 million in 2001 compared to 2000, and decreased $13.7 million in 2000 compared to 1999. The 2000 decrease was primarily due to fees incurred in December 2000 related to the liquidation of Edison Mission Energy Global Management, Inc. in connection with the redemption of the $120 million Flexible Money Market Cumulative Preferred Stock.

        Gains on sale of assets were $41.3 million, $25.8 million and $7.6 million in 2001, 2000 and 1999, respectively. Gains on sale of assets for 2001 and 2000 included:

        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 continued 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 the profits and losses of Four Star Oil & Gas 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 decreased $10.9 million in 2001 compared to 2000, and increased $250.6 million in 2000 compared to 1999. The 2001 decrease was due to a combination of the following:

•

A reduction in corporate debt of $1.667 billion using the proceeds of the sale-leaseback of the Powerton-Joliet power plants in August 2000 and the Illinois peaker power units in July 2000; and



•

Lower interest rates on variable rate debt generally tied to LIBOR primarily related to financing for our Illinois plants and our corporate line of credit; and



•

Favorable changes in foreign exchange rates which reduced the U.S. dollar equivalent of foreign borrowings; partially offset by



•

Higher-cost borrowings resulting from the California power crisis, including refinancing of short-term debt through the issuance of $1 billion in new fixed rate debt in 2001 and higher interest margins on our corporate line of credit.

        The 2000 increase was primarily the result of additional debt financing associated with the acquisitions of the Illinois plants and the Homer City facilities.

        Dividends on mandatorily redeemable preferred securities decreased $9.8 million in 2001 compared to 2000 and increased $9.7 million in 2000 compared to 1999. The 2001 decrease reflects the

37

redemption of the NZ$400 million EME Taupo preferred securities in July 2001. The 2000 increase reflects the issuance of preferred securities in connection with the original Contact Energy acquisition.

Provision (Benefit) for Income Taxes

        We had effective tax provision (benefit) rates of 45.6%, 49.7% and (43.0)% in 2001, 2000 and 1999, respectively. The lower effective income tax rate in 2001 is largely due to changes in income levels in different international tax jurisdictions. 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 facilities and Illinois plants. 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, we benefited from lower foreign income taxes that resulted 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 decreased from 34% to 30% effective in July 2001. In accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the reductions in the Australian income tax rates resulted in reductions in income tax expense of approximately $5.9 million in 1999.

        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 a material adverse effect upon our financial condition or results of operations.

Minority Interest

        Minority interest expense increased $19 million in 2001 compared to 2000 and increased $0.2 million in 2000 compared to 1999. The 2001 increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that increased our ownership interest from 42.6% to 51.2%.

Discontinued Operations

        As a result of the change in the prices of power in the U.K. and the anticipated negative impacts of such changes on earnings and cash flow, we offered for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.

        The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.148 billion after tax) related to the loss on disposal. Included in the loss on disposal is the asset impairment charge of $1.9 billion ($1.154 billion after tax) we recorded in the third quarter of 2001 to reduce the carrying amount of the power plants to reflect the estimated fair value less the cost to sell and related currency adjustments.

        Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. The early repayment of the projects' existing debt facility of £682.2 million at December 21, 2001 resulted in an extraordinary loss of $28 million, after tax, attributable to the write-off of unamortized debt issue costs.

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        Effective January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges under SFAS No. 133. We could not conclude, based on information available at December 31, 2000, that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

        Effective January 1, 2000, we recorded a $4.1 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting for major maintenance costs. Through December 31, 1999, we accrued for major maintenance costs incurred during the period at the Ferrybridge and Fiddler's Ferry power plants between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred.

Cumulative Effect of Change in Accounting Principle

Accounting for Derivatives and SFAS No. 133

        Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates 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. Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also 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.

        Effective January 1, 2001, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the documentation requirements of SFAS No. 133 are met.

        Accounting for derivatives under SFAS No. 133 is complex. Each transaction requires an assessment of whether it is a derivative according to the definition under SFAS No. 133, including amendments and interpretations. Transactions that do not meet the definition of a derivative are accounted by us on the accrual basis, unless they relate to our trading operations, in which case they are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, either do not meet the definition of a derivative or qualify for the normal purchases and sales exception.

        As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under the prior accounting policy.

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Discussion of Initial Adoption of SFAS No. 133

        On January 1, 2001, we recorded a $0.2 million, after tax, increase to income from continuing operations and a $230.2 million, after tax, decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. The following material items were recorded at fair value:

•

The forward sales contracts from our Homer City facilities qualified as cash flow hedges. We did not use the normal sales and purchases exception for these forward sales contracts due to our net settlement procedures with counterparties as discussed below under "Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133." As a result of higher market prices for forward sales from our Homer City facilities, we recorded a liability of $115.9 million at January 1, 2001, deferred tax benefits of $54.1 million and a decrease in other comprehensive income of $61.8 million.



•

The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia qualified as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. As a result of higher market prices for forward sales from our Loy Yang B plant, we recorded a liability of $227 million at January 1, 2001, deferred tax benefits of $68.1 million and a decrease in other comprehensive income of $158.9 million.



•

The majority of our activities related to the fuel contracts for our Collins Station in Illinois did not qualify for either the normal purchases and sales exception or as cash flow hedges. We could not conclude, based on information available at January 1, 2001, that the timing of generation from the Collins Station met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, these contracts were recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement. We have continued to record fuel contracts for our Collins Station at fair value.

Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133

        Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in quantities that are expected to be sold in the normal course of business. This modification had two significant impacts:

•

As a result of the new interpretation, our Homer City forward sales contracts qualified for the normal sales and purchases exception, commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we reversed the value of the Homer City forward sales contracts from our consolidated balance sheet. The cumulative effect of this change in accounting is reflected as a $15.5 million, after tax, decrease to other comprehensive income in 2001.



•

For the period between January 1, 2001 through June 30, 2001, we applied the normal sales and purchases exception for long-term commodity contracts that included both selling and purchasing electricity by our First Hydro plant. However, the criteria applicable to the buyer of power outlined under Statement No. 133 Implementation Issue Number C15 precluded the contracts from qualifying under the normal sales and purchases exception as of July 1, 2001 because First Hydro is not contractually obligated to maintain sufficient capacity to meet electricity needs of a customer. Accordingly, we recorded a $14.9 million, after tax, increase to income from continuing operations as the cumulative effect of change in accounting for derivatives in our consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of

40

these contracts were reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.

        Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, of a derivative's change in fair value is immediately recognized in earnings. We recorded a net loss of $1.4 million in 2001, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.

Accounting for Major Maintenance Costs

        Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, 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 guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $21.8 million, after tax, increase to income from continuing operations, as the cumulative effect of change in accounting for major maintenance costs during the quarter ended March 31, 2000.

Accounting for Start-up Costs

        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 in 1999 that resulted from adopting SOP 98-5 was $13.8 million, after tax.

Extraordinary Gain

        As a result of the Homer City sale-leaseback transaction on December 7, 2001, we recorded an extraordinary gain of $5.7 million, net of income tax expense of $4.4 million, attributable to the extinguishment of debt that was assumed by the third party lessors in the sale-leaseback transaction. See "—Sale-Leaseback Transactions."

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LIQUIDITY AND CAPITAL RESOURCES

        At December 31, 2001, we had cash and cash equivalents of $372.1 million and had available a total of $554.3 million of borrowing capacity under our $750 million corporate credit facility. The credit facility includes a one-year $538.3 million component, Tranche A, that expires on September 17, 2002 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. The credit facility provides credit available in the form of cash advances or letters of credit. At December 31, 2001, Tranche A consisted of one borrowing of $80 million at one-month LIBOR of 1.9256%, plus the applicable margin as determined by our long-term credit ratings (an all in rate of 4.30%). Tranche B, which had no advances outstanding at December 31, 2001, included the issuance of letters of credit in the amount of $115.7 million. In addition to the interest payments, we pay a facility fee as determined by our long-term credit ratings (0.625% and 0.75% at December 31, 2001 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings. See "—Corporate Financing Plans."

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

        Net cash provided by (used in) operating activities:

        Cash provided by continuing operating activities is derived primarily from operations of the Illinois plants and the Homer City facilities, distributions from energy projects and dividends from investments in oil and gas. The lower operating cash flow from continuing operations in 2001, compared to 2000, reflects lower distributions from energy projects and higher current income taxes payable due to the sale-leaseback of the Homer City facilities, partially offset by higher dividends from oil and gas investments. The change in operating cash flow in 2001 was also due to the timing of cash receipts and payables related to working capital items. Lower distributions from energy projects in 2001 primarily resulted from the delay in payments from the California utilities to our investments in California qualifying facilities. See "—The California Power Crisis" for further discussion. The higher operating cash flow from continuing operations in 2000, compared to 1999, primarily reflects higher pre-tax earnings from projects acquired in 1999 and higher dividends from oil and gas investments.

        Net working capital at December 31, 2001 was $324.6 million compared to ($800.8) million at December 31, 2000. The increase primarily reflects the repayment on our corporate credit facilities that were classified as short-term obligations at December 31, 2000 with the proceeds from the issuance of long-term senior notes in 2001.

        Cash used in operating activities from discontinued operations in 2001 reflects operating losses from the Ferrybridge and Fiddler's Ferry power plants in 2001 as compared to operating income during 2000, and the timing of cash payables related to working capital items.

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Cash Flows From Financing Activities

        Net cash provided by (used in) financing activities:

        Cash used in financing activities from continuing operations in 2001 consisted of net proceeds from bond issuances totaling $1 billion, the proceeds of which were partially used to permanently repay $677 million under our former corporate credit facilities. In addition, we used the proceeds from the December 2001 Homer City sale-leaseback transaction to permanently repay $250 million under the Homer City facilities construction loan and to make a $350 million payment under our $750 million corporate credit facility. Dividends totaling $65 million and $32.5 million were paid to The Mission Group and Mission Energy Holding Company, respectively, and ultimately $96.5 million was paid to Edison International, our ultimate parent company, during 2001, compared to $88 million during 2000. As of December 31, 2001, we had recourse debt of $2.1 billion, with an additional $4 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.

        Cash used in financing activities from discontinued operations in 2001 was primarily related to the early repayment of the term loan facility in connection with the sale of the Ferrybridge and Fiddler's Ferry power plants on December 21, 2001.

        Payments made under 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 from continuing operations during 2000. We used the proceeds from the August 2000 Powerton and Joliet sale-leaseback transaction for a significant portion of the payments under our credit facilities and our floating rate notes. In 2000, we also had borrowings of $1.2 billion under our credit facilities and commercial paper facilities.

        Cash provided by financing activities from discontinued operations in 2000 was primarily related to a loan from Edison Capital, an indirect affiliate. During 2001, the financing was repaid with interest.

        In 1999, financings related to the acquisition of three new projects in 1999 contributed to net cash provided by financing activities from continuing operations. These financings included senior secured bonds totaling $830 million related to the Homer City facilities; $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 received $1.5 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 also issued $600 million of 7.73% Senior Notes due 2009.

        Cash provided by financing activities from discontinued operations in 1999 resulted from the financing related to the acquisition of the Ferrybridge and Fiddler's Ferry power plants. The financing consisted of a term loan facility of $1.3 billion and a $500 million equity contribution from Edison International.

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Cash Flows From Investing Activities

        Net cash provided by (used in) investing activities:

        Cash provided by investing activities from continuing operations in 2001 included proceeds of $782 million received from the sale-leaseback transaction with respect to the Homer City facilities in December 2001. In connection with this transaction, $139 million was deposited into a restricted cash account on the closing date. In June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for $84 million. Included in 2001 investing activities was cash used by us for equity contributions totaling approximately $134 million 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 "—The California Power Crisis" for further discussion. In addition, we paid $10 million as equity contributions for the CBK project; $6.4 million as part of the purchase price and $3 million as equity contributions for the Italian Wind projects; $20 million as part of the purchase of the 50% interest in the CBK project; and $63.4 million for the purchase of additional shares in Contact Energy.

        In 2001, cash provided by investing activities from discontinued operations was primarily due to £643 million proceeds received from the sale of the Ferrybridge and Fiddler's Ferry power plants on December 21, 2001.

        In 2000, net cash provided by investing activities from continuing operations included 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, $30.9 million was paid toward the purchase price and $13.3 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 EcoEléctrica project (June 2000), the Tri Energy project (July 2000) and the ISAB project (September 2000), respectively.

        In 1999, cash used in investing activities from continuing operations was primarily due to the purchase of the Homer City facilities, the Illinois Plants and the 40% interest in Contact Energy. We invested $242.2 million, $330.6 million and $200 million in 2001, 2000 and 1999, respectively, in new plant and equipment principally related to the Valley Power project in Australia, Homer City facilities and Illinois plants in 2001, Homer City facilities and Illinois plants in 2000 and the Homer City facilities in 1999.

        In 1999, cash used in investing activities from discontinued operations was primarily due to the purchase of the Ferrybridge and Fiddler's Ferry power plants.

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Corporate Financial Ratios

        In assessing the leverage of Edison Mission Energy, as a holding company, and its ability to meet debt service obligations, we and our principal bank lenders use two primary ratios: a recourse debt to recourse capital ratio and an interest coverage ratio. These ratios are determined in accordance with financial covenants that have been included in our corporate credit facilities and are not determined in accordance with generally accepted accounting principles as reflected in our Consolidated Statements of Cash Flows. Accordingly, these ratios should not be considered in isolation or as a substitute for cash flows from operating activities or cash flow statement data set forth in our Consolidated Statement of Cash Flows. While the ratios included in our corporate credit facilities measure the leverage and ability of Edison Mission Energy to meet its debt service obligations, they do not measure the liquidity or ability of our subsidiaries to meet their debt service obligations. Furthermore, these ratios are not necessarily comparable to other similarly titled captions of other companies due to differences in methods of calculations.

        Our corporate credit facilities include covenants tied to these financial ratios(1):

(1)

Our corporate credit facilities and corporate debt securities also include a Tangible Net Worth Covenant, which is determined based on our shareholder's equity adjusted for changes in other comprehensive income after December 31, 1999. At December 31, 2001, our tangible net worth as determined in accordance with the covenant was $944.9 million, which exceeds the covenant requirement of $613.8 million.

        As indicated in the above table, at December 31, 2001, we met the above financial covenants. The actual interest coverage ratio during 2001 was adversely affected by the operating results of the Ferrybridge and Fiddler's Ferry projects in the United Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was 1.98 to 1.0. Compliance with these covenants is subject to future financial performance, including items that are beyond our control. See "—Market Risk Exposures" and "—Risk Factors."

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Discussion of Recourse Debt to Recourse Capital Ratio

        The recourse debt to recourse capital ratio of Edison Mission Energy at December 31, 2001 and 2000 was calculated as follows:

(1)

Recourse debt means direct obligations of Edison Mission Energy or obligations of one of its subsidiaries for which Edison Mission Energy has provided a guaranty.

        During 2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in our shareholder's equity from $1.1 billion of after-tax losses, attributable to the loss on sale of our Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. We sold the Ferrybridge and Fiddler's Ferry power plants in December 2001 due, in part, to the adverse impact of the negative cash flow pertaining to these plants. Our recourse debt at December 31, 2001 was slightly less than our recourse debt at December 31, 2000 with the proceeds from new notes issued during the course of the year having been used to repay short-term indebtedness.

Discussion of Interest Coverage Ratio

        The following table sets forth the major component of our interest coverage ratio for 2001 and 2000: