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UNITED STATES
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, 2003

Commission File Number 000-24890

Edison Mission Energy
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (949) 752-5588

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share
(Title of Class)

*

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 certain 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 ý    No o

        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. Yes ý

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

        Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 27, 2003: $0. Number of shares outstanding of the registrant's Common Stock as of March 10, 2004: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

PART I

ITEM 1. BUSINESS

The Company

        Edison Mission Energy, which is referred to as EME in this annual report, is an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. EME also conducts price risk management and energy trading activities in power markets open to competition. EME is a wholly owned subsidiary of Mission Energy Holding Company, which is referred to as MEHC in this annual report. Edison International is EME's ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States.

        EME was formed in 1986 with two domestic operating power plants. As of December 31, 2003, EME owned or leased interests in 80 operating power plants with an aggregate net physical capacity of 23,771 megawatts (MW), of which EME's capacity pro rata share was 18,733 MW. At that date, one international power plant, totaling 369 MW of net physical capacity, of which EME's anticipated capacity pro rata share will be approximately 185 MW, was under construction.

        As of December 31, 2003, consolidated debt of EME was $6.2 billion, including debt maturing on December 15, 2004, which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings Co. The $693 million of debt of Edison Mission Midwest Holdings maturing in December 2004 will need to be repaid or refinanced. Edison Mission Midwest Holdings currently does not have sufficient cash to repay this indebtedness when due. EME expects that this debt will be refinanced well in advance of its December maturity, although there is no assurance that this will be accomplished. A failure to repay or refinance Edison Mission Midwest Holdings' $693 million obligation is likely to result in a default under the MEHC senior secured notes and term loan. These events could make it necessary for MEHC or EME, or both, to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code. EME's independent auditors' audit opinion for the year ended December 31, 2003 contains an explanatory paragraph that indicates the consolidated financial statements included in Part II of this annual report have been prepared on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay or refinance its $693 million obligation raises substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty. See "—Liquidity and Capital Resources" and "—Management's Overview" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

        EME is incorporated under the laws of the State of Delaware. EME's headquarters and principal executive offices are located at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612, and EME's telephone number is (949) 752-5588. Unless indicated otherwise or the context otherwise requires, references to EME in this annual report on Form 10-K are with respect to EME and its consolidated subsidiaries and the partnerships or limited liability entities through which EME and its partners own and manage their project investments.

Forward-Looking Statements

        This annual report on Form 10-K contains forward-looking statements that reflect EME's current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events. Other information distributed by EME that is incorporated in this annual report, or that refers to or incorporates this annual report, may also contain forward-looking statements. In this annual report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "intends," "plans," "probable" and variations of such words and similar

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expressions are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact EME or its subsidiaries, include:

•

EME's and its subsidiaries' ability to refinance or repay debt maturing in December 2004 or raise additional financing for their future cash requirements;



•

the ability of Midwest Generation to restructure, refinance, terminate or otherwise reach a resolution with regard to the Collins lease;



•

the ability of EME to complete the sale of some or all of its international assets at market values sufficient to generate cash to repay indebtedness;



•

EME's and its subsidiaries' ability to provide sufficient collateral in support of their forward sales of electricity and purchases of fuel;



•

supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;



•

general political, economic and business conditions in the countries in which EME does business;



•

governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including environmental regulations that could require capital expenditures or otherwise affect EME's cost and manner of doing business;



•

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, availability, heat rate and output;



•

the cost and availability of fuel and fuel transportation services for EME's generating units;



•

the cost and availability of transmission services;



•

the cost and availability of required emissions allowances;



•

weather conditions, natural disasters, and other unforeseen events; and



•

EME's and its subsidiaries' continued participation in tax-allocation and payment agreements with their affiliates.

        Additional information about the risk factors listed above and other risks and uncertainties is contained throughout this annual report and in the Notes to Consolidated Financial Statements and Management's Discussion and Analysis of Financial Condition and Results of Operations that appear in Part II of this annual report. Readers are urged to read this entire annual report and carefully consider the risks, uncertainties and other factors that affect EME's business. The information contained in this annual report is subject to change without notice, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

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Description of the Industry

Electric Power Industry

        Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities and government-owned power agencies 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 specified types of non-utility power producers, known as qualifying facilities, under specified 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 EME, developed in the United States.

        Beginning in the mid-1990s, industry restructuring and opening of retail markets to competition in several states led some utilities to divest generating assets, which created new opportunities for growth of independent power in the United States. In those jurisdictions that have deregulated retail markets, industry trends and regulatory initiatives resulted in a new set of market relationships in which independent generators and marketers compete with incumbent distribution utilities for sales to end-users on the basis of price, reliability and other factors. As a result of the 2000-2001 California power crisis and related volatility in wholesale markets, some states have either discontinued or delayed implementation of initiatives involving deregulation and some utilities have delayed or cancelled plans to divest their generating assets. These developments have generally not affected the progress of industry restructuring in Illinois and Pennsylvania, where many of EME's power plants are located. However, as discussed further below, competition, regulatory uncertainty and lower wholesale energy prices have adversely affected independent power producers, including several of EME's subsidiaries. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview, Risks Related to the Business and Critical Accounting Policies."

        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. EME has developed or acquired power plants in the Asia Pacific region and in the Europe region as a result of these developments. However, as discussed below, volatility in global energy markets has introduced considerable uncertainty as to the future rates of growth in the global independent power producers sector.

Competition and Market Condition Generally

        EME and its 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 EME and its competitors. More recently, in response to market conditions, EME has changed its focus from acquisition and growth to reducing debt and operating, maintaining, and maximizing the value of its current asset base. Accordingly, EME has engaged in asset sales, has canceled, deferred or sold new development projects, and has taken a number of actions to decrease capital expenditures, including reductions in operating costs, and suspension of operations at several power plants. This trend reflects significant declines in the credit ratings of most major market participants, and the decline of liquidity in the energy markets as a result of credit concerns.

        Where EME sells power from plants from which the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, EME is subject to market fluctuations in prices based on a number of factors, including the amount of capacity available to meet demand, the price of fuel, particularly gas, and the presence of transmission constraints. EME's customers include

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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.

        The proposed introduction of a new standard market design structure by the Federal Energy Regulatory Commission, or the FERC, in those regions not currently organized into centralized power markets and the continued expansion by utilities of unbundled retail distribution services could lead to increased competition in the U.S. independent power market. See "—Regulatory Matters—Retail Competition."

Segment Information

        EME operates predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific and Europe. EME's plants are located in different geographic areas, which mitigate somewhat the effects of regional markets, regional economic downturns or unusual weather conditions. Through its presence in these regions, EME has taken advantage of the increasing globalization of the independent power market. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 21. Business Segments."

Regional Overview of Business Segments

        As of December 31, 2003, EME had ownership or leasehold interests in the following operating power plants in the Americas Region:

(1)

Plant is operated under contract by an EME operations and maintenance subsidiary (partially owned plants) or plant is operated directly by an EME subsidiary (wholly owned plants).

(2)

Currently being sold. See "—Asset Sales."

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(3)

Electric purchaser abbreviations are as follows:

(4)

All the cogeneration plants are gas-fired facilities. All the exempt wholesale generator (EWG) plants are gas-fired facilities, except for the Homer City facilities and six of the Illinois Plants, which use coal.

        As of December 31, 2003, EME had ownership or leasehold interests in the following operating power plants in the Europe and Asia Pacific Regions:

(1)

Plant is operated under contract by an EME operations and maintenance subsidiary (partially owned plants) or plant is operated directly by an EME subsidiary (wholly owned plants).

(2)

Operational MW shown. Unit under construction (369 MW/185 MW) at December 31, 2003 not included.

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(3)

Electric purchaser abbreviations are as follows:

(4)

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

(5)

Minority interests are owned by third parties in three of the power plants.

(6)

Minority interest in one power plant in Australia.

(7)

Total nameplate rating of all generators shown. Actual maximum operating capacity may be reduced by streamflows.

(8)

The renegotiated power purchase agreement limits purchase to 728 MW of capacity until December 2005.

Asset Sales

        On December 31, 2003, EME entered into a sale agreement with a third party for its 50% partnership interest in the Brooklyn Navy Yard project which is expected to be completed during the first quarter of 2004. EME is considering the sale of additional investments, including its interest in the EcoEléctrica project and some or all of its international projects depending on, among other things, market prices. Management has not committed to the sale of any specific project other than the Brooklyn Navy Yard project. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview" for further details on EME's asset sales.

        In addition to the facilities and power plants that EME owns, EME uses the term "its" in regard to facilities and power plants that EME or an EME subsidiary operates under sale-leaseback arrangements.

Americas

        As of December 31, 2003, EME had 25 operating power plants in this region, all of which are presently located in the United States and its territories. EME's Americas region is headquartered in Chicago, Illinois with additional offices located in Irvine, California, and Boston, Massachusetts. A description of EME's larger power plants and major investments in energy projects in the Americas region is set forth below.

Illinois Plants

        On December 15, 1999, a wholly owned indirect subsidiary of EME, Midwest Generation, LLC (Midwest Generation), completed a transaction with Commonwealth Edison, now a subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel power plants located in Illinois, which are collectively referred to as the Illinois Plants. These power plants are located in the Mid-America Interconnected Network, which has transmission connections to the East Central Area Reliability Council and other regional markets.

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        The Illinois Plants include the following:

(1)

Beginning in January 2003, operations at Collins Station Units 4 and 5 (1,060 MW) and at Will County Station Units 1 and 2 (310 MW) were suspended pending improvement in market conditions.

(2)

Bloom peaking units were decommissioned in 2003.

        As part of the purchase of the Illinois Plants, EME assigned its right to purchase the Collins Station to third-party entities and Midwest Generation simultaneously entered into a long-term lease arrangement of the Collins Station with these third-party entities. EME also completed sale-leaseback transactions involving its Powerton and Joliet power facilities in August 2000. EME sold these assets to third parties and entered into long-term leases of the facilities from these third parties to provide capital to finance its acquisition, in the case of the Collins Station, or to repay corporate debt while maintaining control of the use of the power plants during the terms of the leases. For more information on these transactions, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Off-Balance Sheet Transactions."

Power Purchase Agreements

        On December 15, 1999, Midwest Generation entered into three separate five-year power purchase agreements with Commonwealth Edison that expire on December 31, 2004. In January 2001, Commonwealth Edison assigned these agreements to its affiliate, Exelon Generation. Under these agreements, Midwest Generation agreed to make the capacity of specific units of the Illinois Stations available to Exelon Generation. These agreements allow Midwest Generation to sell any excess energy, including energy not dispatched by Exelon Generation, to other purchasers under specified conditions. Payments under these power purchase agreements constituted approximately 21%, 41% and 43% of EME's consolidated operating revenues for 2003, 2002 and 2001, respectively. As discussed in detail below, Exelon Generation has released 5,428 MW of Midwest Generation's generating capacity from

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the power purchase agreements for 2004. Therefore, 3,859 MW of Midwest Generation's generating capacity remains subject to power purchase agreements with Exelon Generation in 2004.

Coal-Fired Stations Power Purchase Agreement—

        The power purchase agreement for the coal-fired stations provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy taken by Exelon Generation. The capacity payments compensate Midwest Generation for fixed charges such as debt service, labor and insurance, and the energy payment compensates Midwest Generation for variable costs of actual electricity production taken by Exelon Generation. Exelon Generation also compensates Midwest Generation for the cost of startups, shutdowns and some low-load operations, which are not covered by the normal energy charge rate. Midwest Generation also supplies ancillary services with respect to the coal-fired stations. If Exelon Generation does not request all available energy from the coal-fired stations under the power purchase agreement, Midwest Generation may sell the excess energy to third parties, subject to certain conditions.

        Pursuant to the provisions of the coal-fired power purchase agreement, Exelon Generation has elected to retain 2,383 MW of coal-fired capacity for contract year 2004, thus releasing from the contract 3,262 MW of capacity. The final contract year under this power purchase agreement is 2004.

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        The following table lists the coal-fired units from which Exelon Generation is committed to purchase capacity and energy during 2004 and the units which have been released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

2004 — Coal-Fired Units

(1)

"Summer" months are June through September, and "Non-Summer" months are the remaining months in the year.

(2)

Released units refer to those option units for which Exelon Generation has not exercised its right to purchase capacity and energy during 2004, and which are thus released from the terms of the power purchase agreement.

(3)

Operations currently suspended at these units.

(4)

Under the power purchase agreement, Joliet Unit 6 sold to Exelon Generation based on 314 MW of net power output. Exelon Generation subsequently sold 24 MW of auxiliary power to Joliet Units 7 and 8 via internal power distribution lines. Under merchant operation, the Joliet Station nets the power transferred out between Joliet Unit 6 and Joliet Units 7 and 8 reducing Joliet Unit 6 net output to the grid to 290 MW.

        As noted in the above table, the coal-fired units' power purchase agreement sets forth different capacity charges for the summer months and the non-summer months. The capacity payments are based on the contracted amounts identified in the power purchase agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. If the group equivalent availability factor is higher than a specified threshold, then the adjustment factor calculation provides Midwest Generation with the opportunity to increase the normal monthly capacity payment, but if the group equivalent availability factor is lower than the minimum, then Midwest Generation is penalized by a loss in the monthly capacity payment. The monthly capacity payment adjustment factor provides Midwest Generation with an incentive to maintain the individual units at high equivalent availabilities. The group equivalent availability factor required in the calculation for potentially achieving the full

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monthly capacity payment for the coal-fired units is 65% for the summer months and 55% for the non-summer months.

Collins Station Power Purchase Agreement—

        The Collins Station power purchase agreement provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy generated by Midwest Generation and taken by Exelon Generation. The capacity payments provide Midwest Generation revenue for fixed charges such as debt service, labor and insurance, and the energy payment partially compensates Midwest Generation for variable costs of actual electricity production taken by Exelon Generation. The agreement also includes the requirement that Midwest Generation supply ancillary services with respect to units under contract. Exelon Generation is obligated to dispatch and purchase a specified minimum amount of electric energy or pay an additional payment calculated under the agreement to meet this minimum purchase requirement. If Exelon Generation does not request all available energy from the units under contract, Midwest Generation may sell the excess energy to third parties, subject to several conditions.

        Pursuant to the provisions of the Collins Station power purchase agreement, Exelon Generation has elected to retain 1,084 MW of capacity of the units at the Collins Station for contract year 2004, thus releasing from the contract 1,614 MW of capacity. The final contract year under this power purchase agreement is 2004.

        The following table lists the generating units at the Collins Station from which Exelon Generation is committed to purchase capacity and energy during 2004 and the generating units which have been released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

2004 — Collins Station

(1)

"Summer" months are June through September, and "Non-Summer" months are the remaining months in the year.

(2)

Released units refer to those generating units for which Exelon Generation has exercised its right to terminate the power purchase agreement, and which are thus released from the terms of the power purchase agreement.

(3)

Operations currently suspended at these units.

        As noted in the above table, the Collins Station power purchase agreement sets forth different capacity charges for the summer months and non-summer months. The capacity payments are based on the contracted amounts identified in the agreement and are adjusted by a factor that is in part based

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on the group equivalent availability factor. With respect to all energy purchased under the power purchase agreement, Exelon Generation is obligated to pay: a monthly capacity charge for the reserved units which varies according to the time of year; a per megawatt-hour energy charge; various charges for start-up of the reserved units; low load charges that apply at any hour in which Exelon Generation schedules a reserved unit to operate at an output below a level specified in the agreement; and an annual settlement amount to the extent natural gas prices exceed a specified amount and Exelon Generation dispatches more than a threshold amount of energy. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" for discussion related to planned termination of the Collins lease. In addition, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" for discussion related to the asset impairment for Midwest Generation's Collins Station.

Peaking Units Power Purchase Agreement—

        The peaking units power purchase agreement provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy taken by Exelon Generation. If Exelon Generation does not request all available energy from the units under contract, Midwest Generation may sell the excess energy to third parties, subject to several conditions.

        Pursuant to the provisions of the power purchase agreement, Exelon Generation has elected to retain 392 MW of capacity of the peaking units for contract year 2004, thus releasing from the contract 552 MW of capacity. The final contract year under this power purchase agreement is 2004.

        The following table shows the peaking units from which Exelon Generation is committed to purchase capacity and energy during 2004 and the peaking units which have been released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

2004 — Peaking Units

(1)

"Summer" months are June through September, and "Non-Summer" months are the remaining months in the year.

(2)

Released units refer to those peaking units for which Exelon Generation has exercised its right to terminate the power purchase agreement, and which are thus released from the terms of the power purchase agreement.

        See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview" for discussion related to asset impairment charges for Midwest Generation's peaking units.

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Illinois Power Markets

        Beginning in 2003, Midwest Generation has been selling a significant portion of its energy into wholesale power markets. As discussed above, Exelon Generation has released 5,428 MW of Midwest Generation's generating capacity from the power purchase agreements entered into by Exelon Generation and Midwest Generation, leaving 3,859 MW of Midwest Generation's generating capacity subject to the power purchase agreements with Exelon Generation for the remainder of 2004. All these power purchase agreements expire on December 31, 2004. Energy produced by Midwest Generation not under contract with Exelon Generation is sold at market prices to utilities, third-party electricity retailers and power marketers through Edison Mission Marketing & Trading.

        With respect to the capacity that has been released from the power purchase agreements with Exelon Generation, Midwest Generation's coal units derive their revenue from forward sales to regional utilities and power marketers and from sales on a spot basis, and the Collins Station and the peaking units derive revenue from sales on a spot basis.

        The primary markets currently available to Midwest Generation for sales of electricity and capacity not subject to power purchase agreements are direct "wholesale customers" and broker-arranged "over-the-counter customers." Wholesale customer transactions are bilateral sales to regional buyers, including investor-owned utilities, municipal utilities, rural electric cooperatives and retail energy suppliers. Wholesale customer transactions include real-time, daily and longer term structured sales; they are not arranged through brokers and may be tailored to meet the specific requirements of wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include forward sales of electricity. The most liquid over-the-counter markets in the Midwest region are sales into the control area of Cinergy, referred to as "Into Cinergy," and, to a lesser extent, sales into the control areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. Due to geographic proximity, "Into ComEd" has been the primary market for Midwest Generation. Since 2002, liquidity has decreased significantly in these markets and continues to be limited because of the decision by many trading entities to reduce or discontinue operations. In addition, the financial problems of other trading entities have resulted in far fewer creditworthy participants in these markets.

        The emergence of "Into Cinergy," "Into ComEd" and "Into AEP" as commercial hubs for the trading of physical power not only facilitates transparency of wholesale power prices in these markets, but also provides liquidity required to support risk management strategies utilized to mitigate exposure to electricity price volatility. Energy is traded in the form of physically delivered megawatt-hours. Delivery is either made (1) into the receiving control area's transmission system (i.e., Cinergy's, ComEd's, or AEP's transmission system) by the seller's daily election of control area interface, or (2) by procuring energy generated from a source within the receiving control area. Almost all of Midwest Generation's plants are capable of meeting the current "Into ComEd" delivery criteria. Performance of transactions in these markets is subject to contracts that generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit assessment, parent company guarantees, letters of credit and cash margining arrangements. As noted, however, liquidity in all of these markets has been adversely affected by the financial problems of trading and marketing entities.

        As discussed below, the prices for certain sales by Midwest Generation could be adversely affected if Commonwealth Edison's transmission system is integrated into the transmission system administered by PJM Interconnection, LLC, commonly referred to as PJM, and if market power mitigation measures for the Northern Illinois Control Area, referred to as NICA, as currently proposed by PJM, and pending before the Federal Energy Regulatory Commission, or FERC, are adopted.

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        For a discussion of the risks related to Midwest Generation's sale of electricity, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

        Currently, sales of power produced by Midwest Generation that is not under a power purchase agreement with Exelon Generation require using transmission which must be obtained from Commonwealth Edison. An independent system operator does not yet oversee operations of the Commonwealth Edison control area; however, it has requested that such operations be placed under the control of PJM effective May 1, 2004. Such request is currently pending decision by the FERC (see further discussion of this proceeding below). In addition, a number of other utilities in the region participate in the Midwest Independent System Operator (Midwest ISO), a Regional Transmission Organization (RTO) authorized pursuant to the FERC's Order No. 2000, where a bilateral market with a single rate for transmission within the RTO already exists. The regional market is further supported by open access transmission under various utility company transmission tariffs that are not within the Midwest ISO. The open access transmission tariffs of the Midwest ISO and others in the region allow Midwest Generation to utilize their transmission and distribution systems to sell power at wholesale on a non-discriminatory basis relative to the system owners. Such tariffs are vital to allow Midwest Generation to compete in the deregulated electricity markets because they provide a uniform set of prices and standards of transmission service that have been approved by regulatory agencies and are publicly available.

        The Illinois Electric Service Customer Choice and Rate Relief Law of 1997 requires each Illinois electric utility that owns or controls transmission facilities or provides transmission services in Illinois, and is a member in the Mid-American Interconnected Network, such as Commonwealth Edison, to submit for approval by the FERC an application for establishing or joining an independent system operator. On December 11, 2002, Commonwealth Edison, American Electric Power and others filed with the FERC seeking permission to join PJM as their RTO. PJM is a prominent independent system operator providing system operations and market settlement throughout the Mid-Atlantic States. The effect of including Commonwealth Edison and American Electric Power in the PJM RTO would be to transfer functional control of their transmission systems to PJM and to eliminate so-called rate pancaking for transmission and ancillary services over a region that would extend significantly beyond the current western boundaries of PJM and into electricity markets in the Midwest. Rate pancaking occurs when energy must move through multiple, separately priced transmission systems to travel from its point of production to its point of delivery, and each transmission owner along the line charges separately for the use of its system. Another effect would be to make the transmission systems of Commonwealth Edison and American Electric Power subject to the PJM Open Access Transmission Tariff (referred to herein as the "PJM Tariff") and Market Rules. Under such rules (and assuming the inclusion of both Commonwealth Edison and American Electric Power in PJM), sales of power from the Midwest Generation plants can be made within the broad regional area encompassed by PJM without the necessity of securing physical reservations of transmission capacity, either through bilateral transactions with specific purchasers or into the PJM-dispatched markets without a named counterparty.

        Approval of the December 11 application of Commonwealth Edison and American Electric Power was granted by the FERC on April 1, 2003. However, the ability of American Electric Power to join PJM has been brought into question by the enactment of legislation in Virginia on April 2, 2003, requiring the approval of Virginia state authorities for any transfer of control from American Electric Power to PJM of American Electric Power transmission assets located in Virginia. In July 2003, state authorities in Kentucky placed similar obstacles on the transfer of control of American Electric Power transmission assets located in that state.

        On April 16, 2003, Commonwealth Edison and PJM issued a joint press release stating that the integration of Commonwealth Edison into PJM would proceed separately from that of American

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Electric Power, notwithstanding the absence of a direct transmission link owned by Commonwealth Edison between its service territory and the existing PJM. In response, EME, Midwest Generation, and other affected parties filed with the FERC for clarification or rehearing of its April 1, 2003 order, and essentially contested the appropriateness of Commonwealth Edison joining PJM on an "islanded" basis, without a direct transmission link between its service territory and that of the existing PJM. On June 4, 2003, the FERC clarified that a series of pre-conditions imposed by an order issued on July 31, 2002, which tentatively approved the stated decisions of Commonwealth Edison and American Electric Power to join PJM together, continue to be applicable to the separate application of Commonwealth Edison to join PJM alone. On August 1, 2003, Commonwealth Edison filed a notice of appeal of the July 31, 2002 order and the June 4, 2003 order on rehearing with the U.S. Court of Appeals for the D.C. Circuit.

        Processing by PJM of Commonwealth Edison's application to integrate Commonwealth Edison's operations under PJM separately from American Electric Power was delayed following the August 14, 2003 blackout in the Midwest and Northeast. On December 31, 2003, PJM and Commonwealth Edison made a filing with the FERC seeking its approval to commence full integration of Commonwealth Edison on May 1, 2004, without AEP. On January 21, 2004, EME and Midwest Generation filed a protest opposing the separate integration of Commonwealth Edison into PJM on an "islanded" basis on numerous grounds, including the adverse impact of a separate, stand-alone segment of PJM limited to the control area of Commonwealth Edison, which would be essentially disconnected from the rest of PJM by the states of Indiana and Ohio. One of the primary objections to such a circumscribed market within PJM, which would be subject to its market rules, is the fact that the PJM Market Monitor utilizes price mitigation techniques that do not take into account the availability of imports of electricity from non-PJM sources in evaluating the existence of competitive conditions and in deciding whether to apply restraints on bids from generators located within PJM — in this instance, the service territory of Commonwealth Edison. PJM subsequently filed its intended rules for the application of its market mitigation techniques to such territory, which EME and Midwest Generation have also opposed on numerous factual and legal grounds (see further discussion below). It is not possible to predict the outcome of such further proceedings at this time.

        On July 23, 2003, the FERC issued an order finding that the regional through and out rates, or RTORs, of the Midwest ISO and PJM are unjust and unreasonable when applied to transactions sinking within the proposed Midwest ISO/PJM footprint and directed Midwest ISO and PJM to make a compliance filing within thirty days eliminating the RTORs. The FERC also initiated an investigation and hearing to determine whether the through and out rate under the tariffs of Commonwealth Edison, AEP and others (for which RTO membership has been delayed) are unjust, unreasonable or unduly discriminatory or preferential for transactions sinking in the proposed Midwest ISO/PJM footprint. Such actions by FERC were designed to achieve the elimination of transmission rate pancaking within the broad region encompassed by PJM, as expanded, and the Midwest ISO, which was one of several actions required as a condition of its approval in July 2002 of the decisions of Commonwealth Edison and American Electric Power to join PJM instead of the Midwest ISO. Numerous transmission owners sought rehearing of the July 23 order, and the FERC subsequently issued an order on rehearing on November 17, 2003, setting a new effective date of April 1, 2004, for the elimination of the through and out rates and making certain other adjustments to phase in the new rates. However, the affected utilities in the region have continued to protest the alleged adverse financial impact of the described orders on them, and FERC subsequently moved the date for the elimination of the through and out rates to May 1, 2004. On March 5, 2004, the affected parties announced an agreement to postpone the date for the elimination of through and out rates to December 1, 2004, in an effort to facilitate a settlement of the longer term issues. EME and Midwest Generation oppose such agreement on legal and policy grounds, but it has been filed with the FERC with a request for approval by March 19, 2004. The outcome cannot be predicted.

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        In the meantime, on September 29 and 30, 2003, the FERC held a Commissioner-level hearing and inquiry into regional transmission organization issues related to the Midwest ISO and PJM. The purpose of the inquiry was to gather sufficient information to move forward in resolving the commitment made by several entities, including Commonwealth Edison, to establish a joint and common market in the Midwest and PJM region. Following such inquiry on November 25, 2003, the FERC issued an order finding that the actions of the state of Virginia described above and similar actions of state authorities in Kentucky were impeding the ability of American Electric Power to join PJM and thus potentially thwarting the development of regional power markets in the Midwest. The order set for hearing certain issues that must be addressed in order to "exempt" a utility from a state law or regulation having such effect, and required a decision by the assigned Administrative Law Judge by March 15, 2004. Such hearings have been completed, and the matter has been briefed and argued to the Administrative Law Judge, where it is currently under submission awaiting his decision. The November 25, 2003 order also required American Electric Power to be integrated into PJM by October 1, 2004.

        As described above, there currently is a proposal pending before FERC to integrate Commonwealth Edison into PJM on an "islanded" basis effective May 1, 2004. On February 5, 2004, PJM filed proposed revisions to the PJM Tariff to incorporate market power mitigation measures for the NICA, which would become effective upon Commonwealth Edison's integration into PJM on a stand-alone basis, currently scheduled for May 1, 2004. In its February 5, 2004 filing, PJM claimed that, while the NICA markets were expected to generally be competitive, mitigation measures were required to control the exercise of market power in certain circumstances. With regard to the NICA energy market, PJM has proposed that in certain circumstances, sales by marginal units would be capped at the greater of such units' incremental operating cost plus ten percent or the NICA market price. With regard to sales of capacity in the NICA, PJM also has proposed that offers of capacity be capped at $30 per megawatt-day, plus any additional amounts that are demonstrated to compensate the seller for its opportunity costs or other annual avoidable incremental costs. In certain circumstances, this offer cap could be increased to $160 per megawatt-day. On February 26, 2004, Midwest Generation filed a protest to PJM's proposed market power mitigation measures for the NICA which contested the need for these mitigation measures and requested that FERC defer Commonwealth Edison's integration into PJM until American Electric Power's scheduled integration into PJM on October 1, 2004. It is not possible to predict at this time whether PJM's proposed market power mitigation measures for the NICA will be accepted by FERC, either in whole, or in part. If FERC should accept these market power mitigation measures as currently proposed by PJM, the prices for certain sales by Midwest Generation could be adversely affected.

        For a discussion of the risks related to Midwest Generation's transmission service, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

Homer City Facilities

        On March 18, 1999, EME 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 boilers and steam turbine-generator 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 PJM and 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. For a discussion of the risks related to the sale of electricity from the Homer City facilities, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

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

Big 4 Projects

        EME owns partnership investments in 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 Edison Mission Energy Funding Corp., a special purpose entity. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Summary of Significant Accounting Policies," for discussion of EME's accounting for this entity. Due to similar economic characteristics and the bond financing related to its equity investments, EME views these projects collectively and refers to them as the Big 4 projects.

Kern River Cogeneration Plant

        EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers 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 ChevronTexaco Exploration and Producing under a steam supply agreement that also expires in 2005.

Midway-Sunset Cogeneration Plant

        EME owns a 50% partnership interest in Midway-Sunset Cogeneration Company, which owns a 225 MW natural gas-fired cogeneration facility located near Taft, California, which EME refers to as the Midway-Sunset project. Midway-Sunset sells electricity to Southern California Edison, Aera Energy LLC (Aera) 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 Cogeneration Plant

        EME owns 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 EME refers 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 ChevronTexaco Exploration and Producing under a steam supply agreement that also expires in 2007.

Watson Cogeneration Plant

        EME owns a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural gas-fired cogeneration facility located in Carson, California, which EME refers to as the Watson project. Watson Cogeneration sells electricity to Southern California Edison and to the adjacent BP refinery under power purchase agreements that expire in 2008 and sells steam to BP West Coast Products LLC under a steam supply agreement that also expires in 2008.

Other Americas Power Plants

Sunrise Power Plant

        EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired facility in Kern County, California, which EME refers to as the Sunrise project. The Sunrise

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project was constructed in two phases. Phase 1 achieved commercial operation in June 2001 and consisted of a 320 MW simple-cycle peaking facility. Phase 2, a combined-cycle gas-fired facility, converted the simple-cycle peaking facility to a 572 MW combined cycle plant. Phase 2 achieved commercial operation in June 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 "Item 3. Legal Proceedings—Sunrise Power Company Lawsuits."

Brooklyn Navy Yard Cogeneration Plant

        EME owns 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 EME refers 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 2036. EME expects to complete the sale of its 50% partnership interest in the Brooklyn Navy Yard project during the first quarter of 2004. See "—Asset Sales."

EcoEléctrica Power Plant

        EME owns a 50% partnership interest in EcoEléctrica L.P., which owns a 524 MW power plant located Peñuelas, Puerto Rico, which EME refers to as the EcoEléctrica project. EcoEléctrica sells electricity to Puerto Rico Electric Power Authority under a power purchase agreement that expires in 2022 and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2022. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview" for discussion of planned asset sales.

March Point Cogeneration Plant

        EME owns a 50% partnership interest in March Point Cogeneration Company, which owns a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, which EME refers to as the March Point project. The March Point project consists of two phases. Phase 1 is an 80 MW gas turbine cogeneration facility and Phase 2 is a 60 MW gas turbine combined cycle facility. March Point Cogeneration sells electricity to Puget Sound Energy, Inc. under a power purchase agreement that expires in 2011 and sells shares to Equilon Enterprises, LLC under a steam supply agreement that also expires in 2011.

Westside Power Plants

        EME owns partnership investments in Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, and Sargent Canyon Cogeneration Company. Due to similar economic characteristics, EME views these projects collectively and refers to them as the Westside projects. EME owns a 50% partnership interest in each of the companies listed above and each company owns a 38 MW natural gas-fired cogeneration facility located in California. Each of the projects sells electricity to Pacific Gas & Electric Company under 15-year power purchase agreements with expirations through 2007.

American Bituminous Power Plant

        EME owns a 50% interest in American Bituminous Power Partners, L.P., which owns a 80 MW waste coal facility located in Grant Town, West Virginia, which EME refers to as the Ambit project. Ambit sells electricity to Monongahela Power Company under a power purchase agreement that expires in 2027.

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Investment in Four Star Oil & Gas Company

        As of December 31, 2003, EME owned a 38.5% direct and indirect interest, with 37.4% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of ChevronTexaco Corp. Four Star Oil & 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 & Gas's properties are operated through ChevronTexaco Exploration & Production Inc. On January 7, 2004, EME sold 100% of the stock of Edison Mission Energy Oil & Gas, which in turn holds minority interests in Four Star Oil & Gas. Proceeds from the sale were approximately $100 million. EME expects to record a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

Asia Pacific

        As of December 31, 2003, EME had 19 operating power plants in this region that are located in Australia, Indonesia, the Philippines, Thailand and New Zealand. EME's Asia Pacific region is headquartered in Australia, with an additional office located in Singapore. A description of EME's power plants, its investment in Contact Energy and investments in energy projects in the Asia Pacific region is set forth below. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview" for discussion of planned asset sales.

Australia

Loy Yang B Power Plant

        EME owns a 940 MW coal-fired power station located in Traralgon, Victoria, Australia, which EME refers 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 system marginal price each half-hour. EME has entered into an agreement with the State Electricity Commission of Victoria, which agreement EME refers to as the State Hedge, that provides through October 31, 2016 for the project to receive a fixed price for a portion of its electricity in exchange for payment to the State of the system marginal price applicable to such portion. For further discussion of risks related to the sale of electricity from the Loy Yang B project, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

Valley Power Peaker Power Plant

        During 2002, EME completed construction of a 300 MW gas-fired peaker plant located adjacent to the Loy Yang B coal-fired power plant site, which EME refers to as the Valley Power Peaker project. The peaker units 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 a variety of generation and retail businesses. EME owns a 60% interest in the Valley Power Peaker project, with the remaining interest held by its 51.2%-owned affiliate, Contact Energy Limited.

Kwinana Cogeneration Plant

        EME owns a 70% interest in a 118 MW gas-fired cogeneration plant in Perth, Australia, which EME refers to as the Kwinana project. EME sells electricity to Western Power under a power purchase agreement that expires in 2021 and sells electricity and steam to the British Petroleum Kwinana Refinery under an energy and services agreement which also expires in 2021.

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New Zealand

Contact Energy

        EME owns a 51% majority interest in Contact Energy Limited. The remaining shares of Contact Energy are publicly held and traded on the New Zealand stock exchange. Contact Energy is the largest wholesaler and retailer of natural gas in New Zealand and generates about 30% of New Zealand's electricity. For further discussion of risks related to the sale of electricity from Contact Energy, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures." Contact Energy owns the following power plants:

(1)

Located in Australia. The plant has a total capacity of 300 MW in which Contact Energy owns a 25% share (75 MW). EME owns a 12.8% share (38 MW) through its 51.2% ownership interest in Contact Energy.

        Contact Energy also owns a 40% interest in the Valley Power Peaker project in Australia with the remaining interest held by an EME wholly owned subsidiary.

Indonesia

The Paiton Power Plant

        As of December 31, 2003, EME owned 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 EME refers to as the Paiton project. In January 2004, EME acquired additional shares of Paiton Energy for $14 million, thereby increasing its ownership interest from 40% to 45%. Paiton Energy sells electricity to PT PLN, the state-owned electric utility company, under a power purchase agreement. On December 23, 2002, an amendment to the original power purchase agreement became effective, bringing to a close and resolving a series of disputes between Paiton Energy and PT PLN which began in 1999 and were caused, in large part, by the effects of the regional financial crisis in Asia and Indonesia. The amended power purchase agreement includes changes in the price for power and energy charged under the power purchase agreement, provides for payment over time of amounts unpaid prior to January 2002 and extends the expiration date of the power purchase agreement from 2029 to 2040. These terms have been in effect since January 2002 under a previously agreed Binding Term Sheet which was replaced by the power purchase agreement amendment.

        In February 2003, Paiton Energy and all of its lenders completed the restructuring of the project's debt. As part of the restructuring, Export-Import Bank of the United States loaned the project $381 million, which was used to repay loans made by commercial banks during the period of the project's construction. In addition, the amortization schedule for repayment of the project's loans was extended to take into account the effect upon the project of the lower cash flow resulting from the

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restructured electricity tariff. The initial principal repayment under the new amortization schedule was made on February 18, 2003. Distributions from the project are not anticipated to occur until 2006.

Philippines

CBK Power Plants

        EME owns a 50% interest in CBK Power Co. Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with National Power Corporation for the 792 MW Caliraya-Botocan-Kalayaan hydro electric complex located in the Republic of the Philippines, which EME refers 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 agreement. As of November 30, 2003, all units forming part of the project had completed their net dependable capacity tests, and are operational with tested capacity of 792 MW (net physical capacity) against a guaranteed minimum of 728 MW. As of December 31, 2003, National Power Corporation had not issued certificates of completion for the Kalayaan Phase II units and as such 369 MW were still considered under construction and 423 MW were operational.

Thailand

Tri Energy Cogeneration Plant

        EME owns a 25% interest in Tri Energy Company Limited, which owns a 700 MW gas-fired cogeneration plant located west of Bangkok, Thailand, which EME refers to as the Tri Energy project. Tri Energy sells electricity to Electricity Generating Authority of Thailand under a power purchase agreement that expires in 2020.

Europe

        As of December 31, 2003, EME had 36 operating power plants in this region that are located in the U.K., Turkey, Spain and Italy. EME's Europe region is headquartered in London, England, with additional offices located in Italy and Spain. The London office was established in 1989. A description of EME's power plants and investments in energy projects in the Europe region is set forth below. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview" for discussion of planned asset sales.

United Kingdom

First Hydro Power Plants

        EME's wholly owned subsidiary, First Hydro, owns two pumped storage stations in North Wales at Dinorwig and Ffestiniog which have a combined capacity of 2,088 MW, which EME refers to as the First Hydro project. Pumped storage stations consume electricity when it is comparatively less expensive in order to pump water for storage in an upper reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is higher. First Hydro sells electricity to electricity suppliers, other generators and into short-term markets. Additionally, it sells ancillary services to the system operator. For further discussion of issues related to the First Hydro project, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures" and "—Historical Distributions Received by EME," as well as "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 11. Financial Instruments."

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Derwent Cogeneration Plant

        EME owns a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW gas-fired cogeneration plant in Derby, England, which EME refers to as the Derwent project. Derwent sells electricity to SSE Energy Supply Ltd. under a power purchase agreement that expires in 2010 and sells steam to Acetate Products Limited under a steam supply contract that also expires in 2010.

Italy

ISAB Power Plant

        EME owns a 49% interest in ISAB Energy S.r.l. which owns a 528 MW integrated gasification combined cycle power plant in Sicily, Italy, which EME refers 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 by an oil refinery owned by ERG Petroli SpA.

Italian Wind Power Plants

        In 2000, an international subsidiary of EME acquired a 50% interest in 13 power projects that are in operation in Italy by UPC International Partnership CV II, which EME collectively refers 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 (GRTN). At December 31, 2003, the entire planned 303 MW had been commissioned and 283 MW are in commercial operation. The project, however, is restricted to 283 MW as the project is awaiting 20 MW of transmission capacity to be interconnected to one of the sites. It is expected that GRTN will complete the interconnection in the second quarter of 2004.

Spain

Spanish Hydro Power Plants

        EME's wholly owned subsidiary, Iberica de Energias, S.L., owns 18 small, run-of-the-river hydro electric plants regionally dispersed in Spain totaling 84 MW, which EME refers to as the Spanish Hydro project. Iberica de Energias, S.L. sells electricity to Fuerzas Eléctricas de Cataluña, S.A. under concessions that have various expiration dates ranging from 2030 to 2065.

Turkey

Doga Cogeneration Plant

        EME owns an 80% interest in Doga Enerji, which owns a 180 MW gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. Doga Enerji sells electricity to Türkiye Elektrik Dagitim Anonim Sirketi, commonly known as TEDAS, under a power purchase agreement that expires in 2019. See "Item 7. Management's Discussion and Analysis of and Financial Condition and Results of Operations—Contingencies" for information regarding regulatory developments affecting the Doga project.

        In addition to the facilities and power plants that EME owns, EME uses the term "its" in regard to facilities and power plants that EME or an EME subsidiary operates under sale-leaseback arrangements.

Discontinued Operations

        For a description of discontinued operations see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 8. Discontinued Operations."

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Price Risk Management and Trading Activities

        EME's domestic power marketing and trading organization, Edison Mission Marketing & Trading, Inc., markets the energy and capacity of EME's merchant generating fleet and, in connection with this activity, trades electric power and energy and related commodity and financial products, including forwards, futures, options and swaps. Edison Mission Marketing & Trading also provides services and price risk management capabilities to the electric power industry. Almost all of this trading activity is related either to realizing value from the sale of energy and capacity from EME's merchant plants or to risk management activities related to preserving the value of this marketing activity. EME segregates its marketing and trading 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 EME's 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 are recorded in what Edison Mission Marketing & Trading calls its hedge book.



•

Trading—As part of its trading activities, EME seeks to generate profit from the volatility of the price of electricity, fuels and transmission by buying and selling contracts for their sale or provision, as the case may be, in wholesale markets under limitations approved by EME's Risk Management Committee. These trading activities generally occur in markets that are related to the price risk management activities described above. Edison Mission Marketing & Trading generally balances forward sales and purchase contracts. Edison Mission Marketing & Trading's activities have included restructuring of power sales and power supply agreements for third parties, although these activities are not currently being pursued. 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. Edison Mission Marketing & Trading also has a wholesale power scheduling group that operates on a 24-hour basis.

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

        In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to factors beyond EME's control, market liquidity has decreased significantly since the beginning of 2002 and continues to be limited. A number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may require EME to rely more heavily on a smaller set of wholesale customers, which may also increase EME's credit risk. As noted, a reduction in price reporting has also limited price transparency in certain markets, which also may increase trading risks. While various industry groups and regulatory agencies have taken steps to address market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market confidence. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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        To manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever possible to mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

        EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place which define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk management committee. EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities and its proprietary positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible 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, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

        In executing agreements with counterparties to conduct price risk management or trading activities, EME generally provides credit support in the form of guarantees or letters of credit or enters into margining arrangements (agreements to provide or receive collateral based on changes in the market price of the underlying contract under specific terms). To manage its liquidity, EME assesses the potential impact of future price changes in determining the amount of collateral requirements under existing or anticipated forward contracts. There is no assurance that EME's liquidity will be adequate to meet margin calls from counterparties in the case of extreme market changes or that the failure to meet such cash requirements would not have a material adverse effect on its liquidity. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview, Risks Related to the Business and Critical Accounting Policies—Risks Related to the Business."

Seasonality

        EME's third quarter equity in income from its domestic energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's domestic energy projects, located on the West Coast, have power sales contracts that provide for higher payments during the summer months.

        EME's third quarter electric revenues are materially higher than revenues related to other quarters of the year because warmer weather in the summer months results in higher electric revenues being generated from the Homer City facilities and the Illinois Plants. By contrast, the First Hydro plants have higher electric revenues during the winter months.

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Regulatory Matters

General

        EME's operations are subject to extensive regulation by governmental agencies in each of the countries in which EME conducts operations. EME's 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 ownership and operation of its projects, and the use of electric energy, capacity and related products, including ancillary services from its projects. Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operation of a power plant and the ownership of a power plant. 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. Furthermore, each of EME's international projects is subject to the energy and environmental laws and regulations of the foreign country in which the project is located. The degree of regulation varies by country and may be materially different from the regulatory regime in the United States.

        EME is subject to a varied and complex body of laws and regulations that are in a state of flux. Intricate and changing environmental and other regulatory requirements could necessitate substantial expenditures and could create a significant risk of expensive delays or significant loss of value in a project if it were to become unable to function as planned due to changing requirements or local opposition.

U.S. Federal Energy Regulation

        The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale 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 under that Act by the FERC 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 FERC. 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.

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        An "exempt wholesale generator" under the Public Utility Holding Company Act is an entity determined by the FERC 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 FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the FERC to revoke or modify previously approved rates after notice and opportunity for hearing. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC 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 FERC thereunder, but the FERC typically grants exempt wholesale generators the authority to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, the Federal Power Act grants the FERC 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 FERC typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates. The FERC has indicated its intention to review some of the waivers of financial reporting rules currently granted to some entities with market rate authority.

        Currently, in addition to the facilities owned or operated by EME, a number of its operating projects, including the Homer City facilities, the Illinois Plants, and Brooklyn Navy Yard facilities, are subject to the FERC ratemaking regulation under the Federal Power Act. EME's future domestic non-qualifying facility independent power projects will also be subject to the FERC 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 or operates facilities used for generation, transmission or distribution of electric energy for sale. Exempt wholesale generators and foreign utility companies are not deemed to be electric utility companies, and ownership or operation of qualifying facilities does not cause a company to become an electric utility company. 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 sale, and power marketing activities will not, therefore, result in an entity being deemed to be an electric utility company.

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        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.

        Edison International, EME's ultimate parent company, is a holding company because it owns Southern California Edison, an electric utility company. However, Edison International is 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, EME is 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). EME is not a holding company under the Public Utility Holding Company Act, because its interests in power generation facilities are exclusively in qualifying facilities, facilities owned by exempt wholesale generators and facilities owned by foreign utility companies. All international projects and specified U.S. projects that EME might develop or acquire will be non-qualifying facility independent power projects. EME intends 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 EME's becoming a holding company subject to registration and regulation under the Public Utility Holding Company Act and could trigger defaults under the covenants in EME's project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and could cause certain of EME's project agreements and other contracts to be voidable.

Public Utility Regulatory Policies Act of 1978

        The Public Utility Regulatory Policies Act provides two primary benefits to qualifying facilities. First, as discussed above, ownership of qualifying facilities will not cause a company to be deemed an electric utility company for purposes of the Public Utility Holding Company Act. In addition, all cogeneration facilities that are qualifying facilities are exempt from most provisions of the Federal Power Act and regulations of the FERC thereunder. Second, the FERC 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 nondiscriminatory basis. The FERC'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 FERC'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 EME has 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 FERC under the Federal Power Act, and EME 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

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Securities and Exchange Commission to be void. If a project were to lose its qualifying facility status, EME 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 FERC 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, EME cannot provide assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME's 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 EME, or claims by a utility customer for the refund of payments previously made.

        EME endeavors to develop its qualifying facility projects, monitor regulatory compliance by these projects and choose its 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 EME's 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, EME 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.

        Over the past few years, the U.S. Congress has considered various legislative proposals to restructure the electric industry that would require, among other things, retail customer choice, repeal of the Public Utility Holding Company Act, or PUHCA, and prospective, partial repeal of the Public Utility Regulatory Policies Act. There are also a number of other proposals that have been introduced in Congress that incorporate provisions related to restructuring electricity markets. Different versions of such legislation passed both houses of Congress late in the last session and included provisions related to PUHCA repeal, providing the FERC with new authority related to imposing reliability standards but restricting the FERC's ability to mandate adoption of a standard wholesale market design. A joint Conference Committee produced a report that was acceptable to the House, but was unable to obtain sufficient votes in the Senate to limit extended debate by opponents of the conference report seeking to delay final adoption of the bill (known as a filibuster). It is unclear at this time whether the Senate will be able to muster sufficient votes in the current session to overcome a filibuster and obtain the needed waivers from budgetary rules and pass the Conference report. While there are some pending efforts to enact portions of the comprehensive energy bill on an individual basis, the Congressional leadership and administration have thus far opposed such efforts and the likelihood of success is uncertain.

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Natural Gas Act

        Many of the domestic operating facilities that EME owns, operates or has investments in use natural gas as their primary fuel. Under the Natural Gas Act, the FERC has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The FERC 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.

Recent Foreign Regulatory Matters

        See the discussion on recent foreign regulatory matters in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—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. This transmission service over the lines of intervening transmission owners is also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is a jurisdictional public utility under the Federal Power Act.

        The Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity. Among other things, the Energy Policy Act expanded the FERC's authority to order electric utilities to transmit third-party electricity over their transmission lines, thus allowing qualifying facilities under the Public Utility Regulatory Policies Act of 1978, power marketers and those qualifying as exempt wholesale generators under the Public Utility Holding Company Act of 1935 to more effectively compete in the wholesale market.

        In 1996 the FERC issued Order No. 888, also known as the Open Access Rules, which require utilities to offer eligible wholesale transmission customers non-discriminatory open access on utility transmission lines on a comparable basis to the utilities' own use of the lines. In addition, the Open Access Rules directed jurisdictional public utilities that control a substantial portion of the nation's electric transmission networks to file uniform, non-discriminatory open access tariffs containing the terms and conditions under which they would provide such open access transmission service. The FERC subsequently issued Order Nos. 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 FERC also issued Order No. 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 December 1999, the FERC issued Order No. 2000, which required all jurisdictional transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing functional control over 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 joining and required utilities to explain in detail their reasons for deviating from the objectives set forth in the Order. RTOs meeting the FERC'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.

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        In subsequent orders, the FERC has progressively tightened its policies in favor of RTO formation, including an explicit proposal that approvals of market-based rate authority for affiliates of utilities owning transmission should be tied to such utilities' placing functional control over their transmission assets in an RTO meeting the criteria of Order No. 2000. On January 15, 2003, the FERC proposed to allow additional percentage points on a utility's return on equity in its transmission rates when it participates in an RTO, divests its RTO-operated transmission assets, or pursues additional measures that promote efficient operation and expansion of the transmission grid. As outlined below, the FERC has also proposed to establish a standard market design that would govern transmission service and energy trading arrangements in all regions of the country.

        On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking having the stated purpose of remedying the remaining opportunities for undue discrimination in transmission and establishing a standardized transmission service and wholesale market design, or SMD, that would provide a "level playing field" for all entities that seek to participate in wholesale electric markets. The SMD proposal includes a number of features that, taken together, should provide a flexible transmission service and an open and transparent spot market design that convey the right pricing signals for investment in transmission and generation facilities, and for other purposes. Comments on certain features of the SMD proposal were filed by interested parties in October 2002 and during the first quarter of 2003. The SMD proposal has also engendered considerable comment, and in some cases opposition, including in the U.S. Congress, and the anticipated timetable for issuance of a final rule is now unclear.

        In April 2003, the FERC attempted to address some more controversial aspects of its SMD proposal in a "White Paper," which set forth the elements of its SMD proposal that it regarded as the most fundamental features of a sound wholesale market "platform" and modified its proposal as to other aspects that it regarded as subject to regional variation. Currently, the SMD policies are being implemented in different degrees and on different schedules in various parts of the country, and are the subject of active consideration and focus by stakeholders in wholesale markets in the Midwest. These and other regulatory initiatives by the FERC are ongoing, and it is not possible to predict the extent of future developments or how they might affect the wholesale power business.

Retail Competition

        In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of many states 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. Volatility in California and other regional power markets has resulted in several states slowing, and in some cases reversing or reassessing, their plans to allow retail competition.

Environmental Matters and Regulations

        See the discussion on environmental matters and regulations in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters and Regulations."

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Employees

        At December 31, 2003, EME and its subsidiaries employed 2,610 people, all of whom were full-time employees and 141, 159 and 1,001 of whom were covered by collective bargaining agreements in the United Kingdom, Australia and the United States, respectively.

EME's Relationship with Certain Affiliated Companies

        EME 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 serves customers in California.

MEHC

        On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. At the same time, MEHC borrowed $385 million under a new term loan. The senior secured notes and the term loan are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes or the lenders under the term loan could result in a change in control of EME. This relationship is discussed further in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 1. General—Mission Energy Holding Company."

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ITEM 2. PROPERTIES

        EME leases its principal office in Irvine, California. This lease covers approximately 147,000 square feet and expires on December 31, 2004. EME also leases office space in Chicago, Illinois; Chantilly, Virginia; and Boston, Massachusetts. The Chicago lease is for approximately 51,000 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 37,000 square feet and expires on July 31, 2007. At December 31, 2003, approximately 38% of the above space was either available for sublease or subleased.

        The following table shows the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of EME's income before tax or is one in which EME has 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

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ITEM 3. LEGAL PROCEEDINGS

EcoEléctrica Environmental Proceeding

        EME owns an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the United States Environmental Protection Agency, or EPA, 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. EcoEléctrica and the Department of Justice agreed to settle the matter for $195 thousand. The parties signed a Stipulation, Settlement Agreement and Order reflecting their agreement. The Department of Justice then filed its complaint, which was subsequently dismissed by the court in recognition of the Stipulation, Settlement Agreement and Order, and EcoEléctrica paid the $195 thousand fine, and the settlement became final.

Sunrise Power Company Lawsuits

        Sunrise Power Company, in which a wholly owned subsidiary of EME owns a 50% interest, sells all 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 FERC against all sellers of power under long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleged that the contracts were "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California Electricity Oversight Board complaint made a similar allegation and requested 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 January 2003, the California Public Utilities Commission and the California Electricity Oversight Board dismissed their complaints against Sunrise Power Company pursuant to a global settlement that also involved a restructuring of Sunrise Power Company's long-term contract with the California Department of Water Resources. On December 31, 2002, Sunrise Power Company restructured its contract with the California Department of Water Resources. The restructured agreement reduced by 5% the capacity payments to be made to Sunrise Power Company as compensation for having power available when needed. In addition, Sunrise Power Company's option to extend the agreement for one year beyond December 31, 2011 was terminated; however, the term of the restructured agreement was extended until June 30, 2012.

        On May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, against the California Department of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the consultants involved in the negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all the contracts entered into in 2001, as well as all the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company was not served with the complaint. On November 25, 2003, the plaintiffs filed a voluntary dismissal with prejudice of this lawsuit. The dismissal was entered by the court on December 2, 2003.

        On May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract

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terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the jurisdictional issue. On July 9, 2003, Judge Whaley of the U.S. District Court concluded the federal court lacked jurisdiction and remanded the case to the originating San Francisco Superior Court. Defendants, including Sunrise Power Company, stipulated to respond to the complaint thirty days after it is assigned to a specific court of the San Francisco Superior Court. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also alleges a class action. One of the newly added parties has again removed the lawsuit to federal court, where it is currently pending (subject to remand). EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

Paiton Labor Suit

        In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the state-owned electric utility company, was also named as a defendant in the suit, along with the Indonesian Minister of Mines and Energy and the former President Director of PT PLN. 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. On April 16, 2002 the Central Jakarta District Court dismissed the lawsuit against Paiton Energy and the other defendants on the basis that the PLN Labor Union was not authorized under the law to bring such an action. The PLN Labor Union filed an appeal on April 23, 2002. In order for the Appeals Court to hear any appeal on the matter, the District Court must have certified its judgment and forwarded it to the Appeals Court.

        While Paiton Energy has not, to date, received notice of any change in jurisdiction, it now appears that jurisdiction has passed to the appellate court. The appellate court has not indicated when, or if, it will move on the PLN Labor Union's appeal. Paiton Energy continues to believe that the District Court's decision was grounded on the applicable legal bases and should withstand any appellate scrutiny.

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 (EME) is, as of the date hereof, owned by Mission Energy Holding Company (MEHC), which is a wholly owned subsidiary of Edison Mission Group Inc. (formerly 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 EME's board of directors. EME made cash dividend payments to Edison Mission Group totaling $65 million during 2001, and after EME's change in ownership, EME made cash dividend payments to MEHC totaling $32.5 million in 2001. EME did not pay or declare any dividends to MEHC during 2003 and 2002.

        EME's certificate of incorporation and bylaws contain restrictions on its ability to declare or pay dividends or distributions. These restrictions require the unanimous approval of EME's board of directors, including at least one independent director, before EME can declare or pay dividends or distributions, unless either of the following is true:

•

EME then has an investment grade credit rating and receives rating agency confirmation that the dividend or distribution will not result in a downgrade; or



•

the dividends do not exceed $32.5 million in any fiscal quarter and EME then meets an interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters.

        EME's interest coverage ratio for the four quarters ended December 31, 2003 was 2.45 to 1. Accordingly, EME is currently permitted to pay dividends up to $32.5 million per quarter beginning the first quarter of 2004 under the "ring-fencing" provisions of EME's certificate of incorporation and bylaws. For more information on these restrictions, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Interest Coverage Ratio."

Company-Obligated Mandatorily Redeemable Securities of Partnership Holding Solely Parent Debentures

        In November 1994, Mission Capital, L.P., a limited partnership of which EME 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 and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024 which were issued by EME in November 1994. The Series A 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. None of these securities had been redeemed as of December 31, 2003. 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 and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025 which were issued by EME in August 1995. The Series B 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. None of these securities had been redeemed as of December 31, 2003. EME 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. As described in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Summary of Significant Accounting Policies," EME no longer consolidates Mission Capital and includes the junior subordinated debentures in its consolidated balance sheet.

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        EME has the right from time to time to extend the interest payment period on its junior subordinated deferrable interest debentures to a period not exceeding 60 consecutive months, at the end of which all accrued and unpaid interest will be paid in full. If EME does not make interest payments on its junior subordinated debentures, it is expected that Mission Capital will not declare or pay distributions on its cumulative monthly income preferred securities. During an extension period, EME may not do any of the following:

•

declare or pay any dividend on, or purchase, acquire or make a distribution or liquidation payment with respect to, any of its common or preferred stock;



•

acquire for cash or other property any indebtedness of any affiliate of EME (other than affiliates of EME which meet specified requirements) for money borrowed; or



•

make any loan or advance to, or guarantee or become contingently liable in respect of indebtedness of, any affiliate of EME (other than affiliates of EME which meet specified requirements).

        Furthermore, so long as any preferred securities remain outstanding, EME 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 EME's common stock if at such time (i) EME shall be in default with respect to its payment obligations under the guarantee, (ii) there shall have occurred any event of default under the subordinated indenture, or (iii) EME shall have given notice of its selection of the extended interest payment period described above and such period, or any extension thereof, shall be continuing.

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ITEM 6. SELECTED FINANCIAL DATA

(1)

In the fourth quarter of 2002, EME adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which required EME to reclassify as part of income from continuing operations, an extraordinary gain of $6 million, net of tax, recorded in December 2001. The extraordinary gain was attributable to the extinguishment of debt that was assumed by the third-party lessors in the December 2001 Homer City sale-leaseback transaction.

(2)

In the fourth quarter of 2003, EME adopted FIN No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51," which required EME to reflect the junior subordinated deferrable interest debentures as a liability, which under the prior accounting treatment would have been eliminated in consolidation, instead of the cumulative Monthly Income Preferred Securities.

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

        This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains forward-looking statements. These statements are based on Edison Mission Energy's (EME's) knowledge of present facts, current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of performance; they are subject to risks, uncertainties and assumptions that could cause actual future activities and results of operations to be materially different from those set forth in this discussion. Important factors that could cause actual results to differ include risks set forth in "Market Risk Exposures" and "Risks Related to the Business." Unless otherwise indicated, the information presented in this section is with respect to EME and its consolidated subsidiaries.

        The MD&A is presented in four major sections:

MANAGEMENT'S OVERVIEW, RISKS RELATED TO THE BUSINESS AND CRITICAL ACCOUNTING POLICIES

Management's Overview

Introduction

        EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of owning or leasing, operating and selling energy and capacity from electric power generation facilities worldwide. EME's subsidiaries or affiliates have typically been formed to own all of or an interest in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. EME also owns a 51% interest in Contact Energy, an integrated energy company located in New Zealand. As of December 31, 2003, EME's subsidiaries and affiliates owned or leased interests in 28 projects, of which 14 are domestic and 14 (including EcoEléctrica) are international.

        EME has financed the development and construction or acquisition of its projects by contributions of equity from EME and the incurrence of so-called project financed debt obligations by the subsidiaries and affiliates owning the operating facilities. These project level debt obligations are generally structured as non-recourse to EME, with several exceptions, including EME's guarantee of the Powerton and Joliet leases as part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Illinois Plants. As a result, these project level debt obligations have structural priority with respect to revenues, cash flows and assets of the project companies over debt obligations incurred by EME, itself. In this regard, EME has, itself, borrowed funds to make the equity contributions required of it for its projects and for general corporate purposes. Since EME does not, itself, directly own any revenue producing generation facilities, it depends for the most part on cash distributions from its projects to meet its debt service obligations, to pay for general and administrative expenses and to pay dividends to its parent, Mission Energy Holding Company (MEHC).

        Distributions to EME from projects are generally only available after all current debt service obligations at the project level has been paid and are further restricted by contractual restrictions on

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distributions included in the documentation evidencing the project level debt obligations. Because of such a contractual constraint, distributions to EME from cash generated from the Illinois Plants has been restricted since October 1, 2002 due to a downgrade of the credit rating of this project's debt to below investment grade. EME also is currently subject to constraints on its ability to make distributions to its parent, MEHC. For a description of the most significant contractual constraints under the projects, see "—Liquidity and Capital Resources—Dividend Restrictions in Major Financings."

        EME's project portfolio may be grouped into two categories: contracted plants and merchant plants. At December 31, 2003, EME owned 25 projects that sell a majority of their power to customers under long-term sales arrangements (greater than 5 years) consisting of power purchase agreements or hedge contracts (in the case of Contact Energy, sales are made through its retail electricity business). While these projects involve a number of risks, their long-term sales arrangements generally provide a stable and predictable revenue stream which results in reasonably predictable cash distributions to EME.

        EME owns three projects (the Illinois Plants, the Homer City facilities and the First Hydro Power Plants) which operate in whole or in part without long-term sales arrangements (representing approximately 70% of EME's project portfolio based on capacity). Although the generation of the Illinois Plants was at the time of their acquisition in late 1999 subject to sale under contracts with Exelon Generation, the amount of capacity and energy subject to sale under these contracts has been gradually reduced in the ensuing contract years, and these contracts will expire at the end of 2004. Output from merchant plants (as well as excess output from contracted plants) which is not committed to be sold under long-term sales arrangements is subject, in terms of price and volume, to market forces which determine the actual amount and price of power sold from these power plants. A description of these market forces and the risks associated with them is included under "—Market Risk Exposures."

Management Focus in 2003 and 2004

        Beginning in 2001, a number of significant developments adversely affected merchant generators (companies that sell a majority of their generation into wholesale power markets), including EME. These developments included lower prices and greater volatility in wholesale power markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their obligations. As a result of these developments, EME's focus during 2003 was on the following objectives:

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Comprehensively addressing the indebtedness at EME and its subsidiaries that mature or expire in 2003 and 2004, with a focus on debt reduction. In December 2003, EME's subsidiary, Mission Energy Holding International, Inc., received funding under a three-year, $800 million secured loan which was used together with other internally generated cash to repay $1.2 billion of EME and Edison Mission Midwest Holdings indebtedness. See further discussion under "MEHC's and EME's Liquidity—Key Financing Developments." This was the first step in a four-part restructuring plan announced in November 2003. The remaining steps are described below.



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Managing EME cash flow and credit resources to support project obligations, marketing and hedging of merchant power, and maturing debt obligations. During 2003, cash distributions to EME from its subsidiaries and affiliates increased to $507 million from $351 million in 2002.



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Focusing on operational excellence at its generation projects. For 2003, EME targeted a fleet equivalent availability factor of 87% and a fleet equivalent forced outage rate of 7%. EME exceeded targeted performance in 2003, achieving an availability factor of 89% across its project portfolio and a forced outage rate of 5% compared to a benchmark (set by NERC-GADS) availability factor of 85% and a forced outage rate of 7% for an equivalent project portfolio.

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        In 2004, EME management intends to continue its focus on operational performance at its generating plants, managing its cash and credit resources to support the contracting of its merchant generation and on implementing its debt restructuring and de-leveraging plan. The key steps to be undertaken in this plan are:

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Refinancing indebtedness associated with the Illinois Plants.

EME intends to arrange a refinancing of indebtedness associated with the Illinois Plants. This consists of $693 million of debt due at Edison Mission Midwest Holdings and the planned termination of the Collins Station lease. See "—Liquidity and Capital Resources—Agreement in Principle to Terminate the Collins Station Lease." EME expects that the refinancing of these arrangements will be completed well in advance of December 2004, but there is no assurance that this will be accomplished.

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Selling some or all of its international operations.

EME has engaged investment bankers to market for sale its international project portfolio. The marketing efforts commenced during the first quarter of 2004. Completion of the sale of some or all of EME's international project portfolio is contingent on receiving acceptable offers with respect to both price and terms and conditions.

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Using the proceeds of asset sales to reduce consolidated indebtedness.

Assuming a successful sale of its international assets and completion of the sale of identified domestic projects, EME plans to use the proceeds first to repay the $800 million term loan described above and, with any additional proceeds received, to retire other consolidated indebtedness or make distributions to MEHC.

        In addition, EME's focus includes realizing planned cash distributions from subsidiaries and affiliates, maintaining operational excellence, obtaining a fair public policy outcome with respect to a well structured expansion of the PJM market, and otherwise supporting the development of competitive markets for wholesale generation in Illinois.

See "Business—Regulatory Matters."

Overview of EME's 2003 Operating Performance

        EME's 2003 operating performance was significantly improved over 2002. A number of important items affected this performance, including the following:

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Power prices in PJM rebounded in 2003 from their depressed prices in 2002 driven largely by higher natural gas prices in the United States as discussed further below. The 24-hour PJM market price (at the Homer City busbar) increased 37% from $25.63 per megawatt hour in 2002 to $35.08 per megawatt hour in 2003. The increase in market price substantially improved the profitability of the Homer City plant.



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Higher natural gas prices also resulted in improved profitability of EME's interest in Four Star Oil & Gas Company and the Big 4 projects.



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The Paiton project debt was restructured following the late 2002 revisions in its power purchase contracts.



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The Sunrise project completed Phase 2 of its development ahead of schedule and, thus, was able to generate additional capacity revenues during the summer of 2003.



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Contact Energy continued to expand its retail customer base which, together with increases in retail prices and higher sales of wholesale natural gas, collectively improved the profitability of this subsidiary.

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On the negative side, EME recorded three asset impairment charges (pre-tax) during 2003:



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$245 million related to the impairment of eight small peaking units of the Illinois Plants resulting from a revised long-term outlook for capacity revenues from these units. The lower capacity revenue outlook is the result of a number of factors, including higher forecasted long-term natural gas prices and the current oversupply of generation in the MAIN Region;



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$53 million related to the write-down of EME's investment in the Brooklyn Navy Yard project due to its planned disposition; and



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$6 million related to the write-down of EME's investment in the Gordonsville project, which was subsequently sold in 2003.



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Also on the negative side, the amount of capacity sold to Exelon Generation from the Illinois Plants decreased significantly from 2002 as discussed further below.

        In 2003, the Illinois Plants had 4,739 MW of contracted capacity (to Exelon Generation) and 3,109 MW of uncontracted capacity available for sale in the merchant generation market, compared with 8,987 MW of contract capacity and 300 MW of uncontracted capacity in 2002. The reduction in contracted generating capacity decreased revenues from Exelon Generation as a percentage of the Illinois Plants' total energy and capacity revenues to 68% in 2003 from 99% in each of 2002 and 2001. The reduction in contracted capacity resulted in a decrease of capacity revenues of $222 million, partially offset by an increase of $127 million in energy revenues from sales of increased merchant generation. Prices realized from sales of merchant generation were significantly higher than energy prices payable under the power purchase agreements with Exelon Generation. EME expects that capacity prices in the MAIN region will, in the near term, be significantly lower than those payable under the existing agreements with Exelon Generation (due to the current generation overcapacity conditions in the MAIN region market), but also expects that merchant energy prices will, in the near term, be higher than those currently received under the existing agreements with Exelon. See "—Market Risk Exposures" for further discussion of forward market prices in the MAIN region.

        A significant factor affecting merchant generators in 2003 was the substantial increase in the price of natural gas, especially when compared with the less volatile cost of other fuels, such as coal. During 2003, natural gas prices at Henry Hub (a major natural gas trading hub) averaged $5.48 per million British Thermal Units, commonly referred to as MMBtu, compared to $3.37 per MMBtu for 2002. Based upon data from NYMEX as of December 26, 2003, the calendar year 2004 forward natural gas price at Henry Hub was $5.45 per MMBtu. Increases in natural gas prices during 2003 resulted in higher wholesale electricity prices (since natural gas is the primary fuel for many generation plants). This increase in natural gas prices was a positive factor for low-cost merchant coal facilities (such as a majority of EME's domestic merchant plants) in markets dominated by gas-fired plants and somewhat positive for such facilities in those markets more dependent on low-cost coal and nuclear facilities. In contrast, for gas-fired merchant generators that sell their power into markets dominated by low-cost coal and nuclear power plants, the increase in natural gas prices adversely affected their results. These conditions adversely affected the Collins Station and small peaking units in Illinois as discussed above.

Expansion of PJM in Illinois

        For the Illinois Plants to achieve their optimal value, it is important that efficient and fair markets exist in the Midwest region. The Illinois Plants are located within the service territory of Exelon Generation's affiliate, Commonwealth Edison (ComEd), which has made a filing with the Federal Energy Regulatory Commission (FERC) to join the PJM System effective May 1, 2004. Although FERC has indicated its general approval for ComEd and American Electric Power (AEP) to join PJM if certain conditions designed to foster broad regional markets in the Midwest are met, the integration

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of AEP into PJM has been stalled due to the opposition of the states of Virginia and Kentucky. While EME and Midwest Generation have supported the entry of ComEd and AEP into PJM at the same time, they have nevertheless opposed ComEd's entry into PJM without AEP on numerous grounds, including the importance of the AEP system to the proper functioning of the markets administered by PJM. This issue is currently pending before FERC.

        If the integration of ComEd into PJM standing alone is allowed by the FERC to proceed on May 1, 2004, the Illinois Plants will become subject to PJM's market rules, including those designed to mitigate generation market power, which PJM has indicated may be applied as if the market is limited only to the generation within the ComEd footprint. (By contrast, PJM has stated to the FERC that market mitigation measures will likely not be necessary from and after the integration of AEP into PJM.) EME and Midwest Generation have strongly opposed this limited view of the market with the FERC, and the matter is pending decision in connection with the ComEd/PJM integration filing. If this opposition is unsuccessful, the price for sales of energy from such plants (during the period prior to AEP's integration) not sold pursuant to bilateral agreement could be capped at their marginal operating cost to produce such energy plus ten percent, under the proposed rules of the PJM Market Monitor. See "—Risks Related to the Business—EME is subject to extensive energy industry regulation."

Contracting Strategy

        EME's goal is to reduce the volatility of its earnings and cash flow and, thus, improve the predictability of operating results. To do this, EME plans to implement a layered contracting strategy for forward sales from the Illinois Plants and the Homer City facilities. A layered contracting strategy means that EME's marketing subsidiary, Edison Mission Marketing & Trading, plans to enter into a number of forward contracts diversified by counterparty, contract term and generation product to reduce market risk and enhance the predictability of revenues. Implementation of this strategy is dependent on a number of factors, such as a reduction in the current oversupply of generation, the rate of demand growth, and agreement between counterparties of reasonable credit support undertakings.

EME's Parent Company—MEHC

        On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, MEHC borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes or the lenders under the term loan would result in a change in control of EME. Beginning in 2004, MEHC's principal source of liquidity is cash dividends from EME.

        EME has not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to EME. The MEHC financing documents contain restrictions on EME's ability and the ability of EME's subsidiaries to enter into specified transactions or engage in specified business activities and require, in some instances, that EME obtains the approval of MEHC's board of directors. EME's certificate of incorporation binds it to the restrictions in MEHC's financing documents by restricting EME's ability to enter into specified transactions or engage in specified business activities, other than as permitted in MEHC's financing documents, without shareholder approval. See "—Risks Related to the Business."

        MEHC is subject to the informational requirements of the Securities Exchange Act of 1934 and, in accordance with these requirements, files reports, information statements and other information with the Securities and Exchange Commission.

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Acquisitions and Dispositions of Investments in Energy Plants

Acquisitions

        On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand. Consideration for the Taranaki station consisted of a cash payment of approximately $275 million, which was initially financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from Contact Energy's issuance of long-term U.S. dollar denominated notes.

Dispositions

        On December 31, 2003, EME agreed to sell its 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P. to a third party. Completion of the sale, currently expected in the first quarter of 2004, is subject to closing conditions, including obtaining regulatory approval. Proceeds from the sale are expected to be approximately $42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related to the planned disposition of this investment.

        On December 12, 2003, EME agreed to sell 100% of its stock of Edison Mission Energy Oil & Gas, which in turn holds minority interests in Four Star Oil & Gas, to Medicine Bow Energy Corporation. Following receipt of regulatory approvals and satisfaction of all other closing conditions, EME completed this sale on January 7, 2004. Proceeds from the sale were approximately $100 million. EME expects to record a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

        On December 12, 2003, EME completed the sale of its 40% interest in a development project in Thailand to a third party. Proceeds from the sale were $13 million to be paid in two installments, the first of which, in the amount of $5 million, was received by EME on December 15, 2003. The remaining payment is payable in June 2004.

        On November 21, 2003, Gordonsville Energy Limited Partnership, in which EME owns a 50% interest, completed the sale of the Gordonsville cogeneration facility to Virginia Electric and Power Company. Proceeds from the sale, including distribution of a debt service reserve fund, were $36 million. EME recorded an impairment charge of $6 million during the second quarter of 2003 related to the planned disposition of this investment.

Risks Related to the Business

EME and its subsidiaries have a substantial amount of indebtedness, including short-term indebtedness and long-term lease obligations.

        As of December 31, 2003, consolidated debt of EME was $6.2 billion, including $693 million of debt maturing in December 2004 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. EME also has a $145 million credit facility expiring in September 2004. In addition, EME's subsidiaries have $6.7 billion of long-term lease obligations that are due over a period ranging up to 31 years.

        The $693 million of debt of Edison Mission Midwest Holdings maturing in December 2004 will need to be repaid or refinanced. Edison Mission Midwest Holdings is currently not expected to have sufficient cash to repay the $693 million debt due in December 2004, and there is no assurance that it will be able to refinance this debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in July 2001 or under the guarantee entered into by Midwest Generation EME in December 2003, or at all. EME's independent auditors' audit opinion for the year ended December 31,

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2003 contains an explanatory paragraph that indicates the consolidated financial statements are prepared on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay or refinance this obligation raises substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty.

        A failure to repay or refinance Edison Mission Midwest Holdings' $693 million of debt as required by its terms would result in an event of default under the Edison Mission Midwest Holdings financing documents. Furthermore, these events would trigger cross-defaults under agreements to which Edison Mission Midwest Holdings and Midwest Generation are parties, including the Collins, Powerton and Joliet leases. An acceleration of debt and lease payments due under these agreements could result in a substantial claim for termination value under the EME guarantee of the Powerton and Joliet leases and could result in a default under EME's financing arrangements. A default by EME on its financing arrangements or a default by one of its subsidiaries on indebtedness considered under the MEHC financing documents as having recourse to EME is likely to result in a default under the MEHC financing documents. These events could make it necessary for EME to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code.

        The substantial amount of consolidated debt and financial obligations presents the risk that EME and its subsidiaries might not have sufficient cash to service their indebtedness or long-term lease obligations and that the existing corporate debt, project debt and lease obligations could limit the ability of EME and its subsidiaries to compete effectively or to operate successfully under adverse economic conditions.

EME has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices.

        EME's merchant energy power plants do not have long-term power purchase agreements. Because the output of these power plants is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the amount and price of power sold from the power plants.

        Among the factors that influence future market prices for energy and capacity in the MAIN Region and PJM are:

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prevailing market prices for fuel oil, coal and natural gas, emission credits and associated transportation costs;



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the extent of additional supplies of energy and capacity from current competitors or new market entrants, including the development of new generation facilities;



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transmission congestion in and to the MAIN region and/or PJM;



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the FERC-approved structure of PJM's expansion into the MAIN region and the application of PJM market monitoring rules to generation within this structure;



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the availability, reliability and operation of nuclear generating plants, where applicable, and the extended operation of nuclear generating plants in the MAIN Region and PJM beyond their presently expected dates of decommissioning;



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weather conditions prevailing in the MAIN Region and PJM from time to time; and



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the rate of electricity use as a result of factors such as regional economic conditions and the implementation of conservation programs.

        There is no assurance that EME's merchant energy power plants will be successful in selling power into their markets or that the prices received for such power will generate positive cash flows. If EME's merchant energy power plants are not successful, they may not be able to generate enough cash to

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service their own debt and lease obligations, which could have a material adverse effect on EME. See "—Market Risk Exposures—Commodity Price Risk."

EME is subject to extensive energy industry regulation.

        EME's operations are subject to extensive regulation by governmental agencies in each of the countries in which operations are conducted. See "Item 1. Business—Regulatory Matters." EME's domestic projects are also subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the operations of a power plant, the ownership of a power plant and various aspects related to transmission access. 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, among other things, the geographical location, zoning, land use and operation of a project. EME's international projects are subject to the energy, environmental and other laws and regulations of the foreign jurisdictions in which these projects are located. The degree of regulation varies according to each country and may be materially different from the regulatory regimes in the United States. For more information, see "Item 1. Business—Regulatory Matters."

        There is no assurance that the introduction of new laws or other future regulatory developments in countries in which EME or its subsidiaries conduct business will not have a material adverse effect on its business, results of operations or financial condition, nor is there any assurance that EME or its subsidiaries will be able to obtain and comply with all necessary licenses, permits and approvals for its projects. If projects cannot comply with all applicable regulations, EME's business, results of operations and financial condition could be adversely affected. In addition, if any projects were to lose their status as a qualifying facility, exempt wholesale generator or foreign utility company under U.S. federal regulations, EME could become subject to regulation as a "holding company" under the Public Utility Holding Company Act of 1935. If that were to occur, EME would be required to divest all operations not functionally related to the operation of a single integrated utility system and would be required to obtain approval of the Securities and Exchange Commission for various actions. See "Item 1. Business—Regulatory Matters—U.S. Federal Energy Regulation."

EME is subject to extensive environmental regulation that may involve significant and increasing costs.

        EME's operations are subject to extensive environmental regulation by foreign, federal, state and local authorities. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future enforcement proceedings that may be taken by environmental authorities, could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that its business, financial position and results of operations would not be materially adversely affected.

        Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. EME cannot provide assurance that it will be able to obtain and comply with all necessary licenses, permits and approvals for its plants.

        Currently, environmental advocacy groups and regulatory agencies in the United States have been focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their

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potential role in climate change. The adoption of laws and regulations to implement carbon dioxide controls could adversely affect EME's coal-fired plants. EME has an equity interest in or owns and operates generating plants in a number of countries that have ratified or are expected to ratify the Kyoto Protocol and these nations are actively developing policies and measures to assist them with meeting the individual national emission targets as set out within the Kyoto Protocol. As a result of the United States' opposition to the treaty, the treaty will not come into effect unless it is ratified by Russia. If the treaty comes into effect or if other countries in which EME operates adopt laws and regulations limiting carbon dioxide emissions even in the absence of the treaty, these requirements could adversely affect EME's operations in those nations. Also, coal plant emissions of nitrogen and sulfur oxides, mercury and particulates are potentially subject to increased controls and mitigation expenses. Changing environmental regulations could require EME to purchase additional emissions allowances or make some units uneconomical to maintain or operate. Furthermore, EME's international projects are subject to the environmental laws and regulations of the foreign jurisdictions in which they are located. The degree of regulation varies according to each country and may be materially different from the regulatory regimes in the United States. If EME cannot comply with all applicable regulations, its business, results of operations and financial condition could be adversely affected. See "—Environmental Matters and Regulations."

The ability of EME's largest subsidiary, Edison Mission Midwest Holdings, to make distributions is restricted.

        The credit ratings of Edison Mission Midwest Holdings are below investment grade, thereby restricting its ability to pay dividends to EME. Edison Mission Midwest Holdings is the direct parent of Midwest Generation, which owns or leases the Illinois Plants. EME is the guarantor of the Powerton and Joliet leases and is obligated under intercompany notes to Midwest Generation to make debt service payments. Each intercompany note is a general corporate obligation of EME and payments on it are made from distributions from subsidiaries and other sources of cash received by EME. Accordingly, EME must continue to make payments under the intercompany notes notwithstanding that Edison Mission Midwest Holdings is not permitted to make distributions to EME. If EME were not able to make the loan payments, it would result in a default under the financing documents to which Edison Mission Midwest Holdings is a party and could result in a default under EME's financing arrangements. This could have a material adverse effect on the results of operations and cash flow of EME.

EME's credit ratings are below investment grade, which may adversely affect its ability to refinance debt or to provide credit support to subsidiaries.

        The credit ratings of EME and several of its subsidiaries are currently below investment grade, and this may adversely affect their ability to enter into new financings and, to the extent that new financings or amendments to existing financing arrangements are obtained, may adversely affect the terms and interest rates that can be obtained. Any future incremental reduction or withdrawal of one or more of EME's credit ratings or the credit ratings of its subsidiaries could have an additional adverse effect on their ability to access capital on acceptable terms, including their ability to refinance debt obligations as they mature.

        EME, directly and through a subsidiary, provides credit support to its subsidiaries. The credit support is in the form of cash and letters of credit. Without an investment grade rating, EME's ability to provide credit support to its subsidiaries is limited. If EME were unable to provide adequate credit support, this would reduce the number of counterparties willing to enter into bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to rely on short-term and spot markets instead of bilateral contracts. Furthermore, if forward prices for power increase significantly, EME may not be able to meet margining requirements. Failure to meet a margining requirement would permit the counterparty to terminate the related bilateral contract early and demand immediate payment for the replacement value of the contract. See "—Liquidity and Capital Resources—Credit Ratings."

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A substantial amount of EME's revenues are derived under power purchase agreements with a single customer.

        During 2003, 2002 and 2001, 21%, 41% and 43%, respectively, of EME's consolidated operating revenues were derived under three power purchase agreements between EME's wholly owned subsidiary, Midwest Generation, and Exelon Generation Company, a subsidiary of Exelon Corporation. Midwest Generation was less dependent on Exelon Generation as a major customer during 2003 due to Exelon Generation's release of capacity from the coal units. In 2004, 2,383 MW of capacity from the coal units and 1,084 MW of capacity from the Collins Station will remain subject to the power purchase agreements. The power purchase agreements terminate at the end of 2004. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major utilities located in Illinois and Pennsylvania. If Exelon Generation were to fail, become unable to fulfill, or choose to terminate some of its obligations under these power purchase agreements, Midwest Generation might not be able to find another customer on similar terms for the output of the Illinois Plants. Any material failure by Exelon Generation to make payments to Midwest Generation under these power purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME. For a further discussion of the power purchase agreements, see "Item 1. Business—Americas—Illinois Plants."

EME's parent, MEHC, depends upon cash flows from EME and tax-allocation payments from Edison International to service its debt.

        MEHC's principal asset is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, MEHC borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes or the lenders under the term loan would result in a change in control of EME. For a discussion of the provisions in EME's formation documents that constrain its ability to pay dividends or distributions to MEHC, see "—Credit Ratings."

        If MEHC or EME were no longer included in the consolidated tax returns of Edison International as a result of Edison International no longer continuing to own, directly or indirectly, at least 80% of the voting power of the stock of such company and at least 80% of the value of such stock, such company would no longer be eligible to participate in tax-allocation payments with other subsidiaries of Edison International. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, MEHC, EME and other Edison International subsidiaries. The agreements to which EME is a party may be terminated by the immediate parent company at any time, by notice given before the first day of the first year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice. If MEHC and EME did not participate in the respective tax-allocation agreements, they would not be entitled to receive tax-allocation payments if payments were due under the agreements. See "—Intercompany Tax-Allocation Payments."

Restrictions in EME's certificate of incorporation, its credit facilities and the MEHC financing documents limit the ability of EME and its subsidiaries to enter into specified transactions that they otherwise may enter into and may significantly impede their ability to refinance their debt.

        The financing documents entered into by MEHC contain financial and investment covenants restricting EME and its subsidiaries. EME's certificate of incorporation binds it to the provisions in MEHC's financing documents by restricting EME's ability to enter into specified transactions and engage in specified business activities without shareholder approval. The instruments governing EME's

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indebtedness also contain financial and investment covenants. Restrictions contained in these documents could affect, and in some cases significantly limit or prohibit, EME and its subsidiaries' ability to, among other things, incur, refinance, and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and engage in mergers and consolidations. These restrictions may significantly impede the ability of EME and its subsidiaries, including Edison Mission Midwest Holdings, to take advantage of business opportunities as they arise, to grow their business and compete effectively, or to develop and implement any refinancing plans in respect of their indebtedness. See "—EME and its subsidiaries have a substantial amount of indebtedness, including short-term indebtedness and long-term lease obligations," for further discussion.

        In addition, in connection with the entry into new financings or amendments to existing financing arrangements, EME's and its subsidiaries' financial and operational flexibility may be further reduced as a result of more restrictive covenants, requirements for security and other terms that are often imposed on sub-investment grade entities.

EME's international projects are subject to risks of doing business in foreign countries.

        EME's international projects are subject to political and business risks, including uncertainties associated with currency exchange rates, currency repatriation, expropriation, political instability and other issues that have the potential to restrict the projects from making dividends or other distributions and against which EME may not be fully capable of insuring. See "—Market Risk Exposures—Foreign Exchange Rate Risk."

        Generally, the uncertainty of the legal structure in some foreign countries could make it more difficult to enforce rights under agreements relating to the projects. In addition, the laws and regulations of some countries may limit the ability to hold a majority interest in some of the projects. The economic crisis in Indonesia during 1998 necessitated a restructuring of the power purchase agreement between PLN, the state-owned electric utility, and the Paiton project and the project debt agreements. During 2002 and the first quarter of 2003, the restructuring of these agreements was completed. However, as a result of the restructuring, the project's expected dividends have been delayed until at least 2006.

General operating risks and catastrophic events may adversely affect EME's projects.

        The operation of power generating plants involves many risks, including start-up problems, the breakdown or failure of equipment or processes, performance below expected levels of output, the inability to meet expected efficiency standards, operator errors, strikes, work stoppages or labor disputes and catastrophic events such as terrorist activities, earthquakes, landslides, fires, floods, explosions or similar calamities. The occurrence of any of these events could significantly reduce revenues generated by EME's projects or increase their generating expenses. Equipment and plant warranties and insurance may not be adequate to cover lost revenues or increased expenses and, as a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under a financing obligation of a project entity could result in a loss of EME's interest in the project.

Critical Accounting Policies and Estimates

Introduction

        The accounting policies described below are viewed by management as "critical" because their correct application requires the use of material judgments and estimates and they have a material impact on EME's results of operations and financial position.

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Derivative Financial Instruments and Hedging Activities

        EME uses derivative financial instruments for price risk management activities and trading purposes. Derivative financial instruments are mainly utilized to manage exposure from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates. EME follows Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), which requires derivative financial instruments to be recorded at their fair value unless an exception applies. SFAS No. 133 also requires that changes in a derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.

        Management's judgment is required to determine if a transaction meets the definition of a derivative and, if yes, whether the normal sales and purchases exception applies or whether individual transactions qualify for hedge accounting treatment. The majority of EME's power sales and fuel supply agreements related to its generation activities either: (1) do not meet the definition of a derivative as they are not readily convertible to cash, or (2) qualify as normal purchases and sales and are, therefore, recorded on an accrual basis.

        Derivative financial instruments used for trading purposes includes forwards, futures, options, swaps and other financial instruments with third parties. EME records at fair value derivative financial instruments used for trading. The majority of EME's derivative financial instruments with a short-term duration (less than one year) are valued using quoted market prices. In the absence of quoted market prices, derivative financial instruments are valued considering time value of money, volatility of the underlying commodity, and other factors as determined by EME. Resulting gains and losses are recognized in net gains (losses) from price risk management and energy trading in the accompanying consolidated income statements in the period of change. Assets from price risk management and energy trading activities include the fair value of open financial positions related to derivative financial instruments recorded at fair value, including cash flow hedges, that are "in-the-money" and the present value of net amounts receivable from structured transactions. Liabilities from price risk management and energy trading activities include the fair value of open financial positions related to derivative financial instruments, including cash flow hedges, that are "out-of-the-money" and the present value of net amounts payable from structured transactions.

        Determining the fair value of derivatives under SFAS No. 133 is a critical accounting estimate because the fair value of a derivative is susceptible to significant change resulting from a number of factors, including: volatility of energy prices, credits risks, market liquidity and discount rates. See "—Market Risk Exposures," for a description of risk management activities and sensitivities to change in market prices.

        EME enters into master agreements and other arrangements in conducting price risk management and trading activities with a right of setoff in the event of bankruptcy or default by the counterparty. Such transactions are reported net in the balance sheet in accordance with FASB Interpretation No. 39, "Offsetting Amounts Related to Certain Contracts."

Impairment

Long-Lived Assets

        EME follows Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). EME evaluates long-lived assets

48

whenever indicators of impairment exist. This accounting standard requires that if the undiscounted expected future cash flow from a company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be recognized in the financial statements. The amount of impairment is determined by the difference between the carrying amount and fair value of the asset.

        The assessment of impairment is a critical accounting estimate because significant management judgment is required to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. Factors EME considers important, which could trigger an impairment, include operating losses from a project, projected future operating losses, the financial condition of counterparties, or significant negative industry or economic trends.

        During the second quarter of 2003, EME assessed the impairment of its Illinois Plants. EME has grouped the Illinois Plants into two asset groups: coal-fired power plants and the small peaker plants. Management judgment was required to make this assessment based on the lowest level of cash flow that was viewed by management as largely independent of each other. The expected future undiscounted cash flow from EME's merchant power plants is a critical accounting estimate because: (1) estimating future prices of energy and capacity in wholesale energy markets is susceptible to significant change, and (2) the forecast is over an extended time period due to the estimated useful life (15 to 33.75 years) of power plants, and (3) the impact of an impairment on EME's consolidated financial position and results of operations would be material. The expected undiscounted future cash flow from the small peaker plants did not exceed the carrying value of that asset group. The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5% discount rate. The impairment charge relating to the peaking plants resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market.

        In addition to the asset impairment charge related to the small peaking plants in 2003, EME's indirect subsidiary, Midwest Generation, also reported an impairment charge of $475 million, after tax, related to the 2,698 MW gas-fired Collins Station in its second quarter report on Form 10-Q. The impairment charge resulted from a write-down of the book value of the Collins Station capitalized assets from $858 million to an estimated fair market value of $78 million. The impairment charge by Midwest Generation is not reflected in the operating results of EME because the lease related to the Collins Station is treated in EME's financial statements as an operating lease and not as an asset and, therefore, is not subject to impairment for accounting purposes. See "—Liquidity and Capital Resources—EME Recourse Debt to Recourse Capital Ratio."

        During the fourth quarter of 2002, an impairment charge of $92 million ($77 million after tax) was recorded by EME's subsidiary holding the Lakeland power plant due to the change in financial condition of TXU Europe and its subsidiaries, one of which was counterparty to a long-term power purchase agreement (considered an indicator of impairment under SFAS No. 144). Management's judgment was required to determine the asset group, which was determined as the power plant and claim under the power purchase agreement. Furthermore, a management estimate was required to determine the fair value of the asset group as the expected undiscounted future cash flow was less than the carrying value of the asset. See "—Consolidated Operating Results—Discontinued Operations," for further discussion.

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        EME also would record an impairment charge if a decision is made to dispose of an asset and the fair value is less than EME's book value. SFAS No. 144 requires the following criteria to be met to classify an asset held for sale:

1.

management approves the action and commits to a plan to sell an asset. This is generally evidenced by the signing of an asset sales agreement or board of directors approval;



2.

the long-lived asset (asset group) is generally deemed to be available for immediate sale and EME's conditions for sale is subject only to the terms and conditions customary for sale of such assets;



3.

management has actively engaged in a program to locate a buyer and has initiated other such actions required to complete the plan to sell the asset;



4.

the sale is probable and the transfer of the asset is expected to be completed within one year;



5.

the asset is being marketed at a price that is believed to be reasonable in relation to fair value;



6.

management believes that it is unlikely that significant changes to the plan that asset will be made or that the plan will be withdrawn.

        EME has engaged investment bankers to market for sale its international project portfolio which commenced during the first quarter of 2004. Completion of the sale of all or part of EME's international project portfolio is contingent on receiving acceptable offers in terms of both price and terms and conditions related to risk factors. Due to the uncertainty regarding completion of the sale of all or part of the international project portfolio through the current offering process, management has concluded that it has not met all of the requirements listed above at December 31, 2003. EME's book value of its international project portfolio was approximately $2.2 billion at December 31, 2003. There is no assurance that EME will be able to sell these assets at or above book value.

        During 2003, EME met the asset held for sale criteria of SFAS No. 144 regarding its investment in the Gordonsville and Brooklyn Navy projects and recorded an impairment based on the net proceeds expected from the sale of $6 million and $53 million, respectively.

        EME operates several power plants under leases as described below under "Off-Balance Sheet Financing." Under generally accepted accounting principles as currently interpreted, EME is not required to record a loss if future cash flows from use of an asset under lease are less than the expected minimum lease payments. This accounting issue has been discussed in EITF No. 99-14, "Recognition by a Purchaser of Losses on Firmly Committed Executory Contracts," without reaching a consensus. Future minimum lease payments on the Collins Station are estimated to be $1.3 billion. As a result, if the accounting guidance in this area were to change, EME could be required to record a loss on this lease, depending on an assessment of future expected cash flow at the time such guidance was changed.

Idle Facilities

        Due to lower wholesale prices for energy during 2002 and 2003 (see "—Market Risk Exposures—Commodity Price Risk"), EME has suspended operations of four units at the Illinois Plants (Units 1 and 2 at Will County and Units 4 and 5 at the Collins Station). EME continues to record depreciation on such assets during the period that EME has suspended operations. Accounting for these units as idle facilities requires management's judgment that these units will return to service. EME has continued the maintenance of these units in order to return them to service when market conditions improve on a sustained basis and future environmental uncertainties are resolved. If market conditions do not improve on a sustained basis, environmental uncertainties are not resolved or are resolved unfavorably, or if a decision is made not to return them to service due to other factors, EME could sell

50

or decommission one or more of these units. Such a decision could result in a loss on sale or a write-down of the carrying value of these assets.

Goodwill

        EME follows Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangibles" (SFAS No. 142). EME evaluates goodwill whenever indicators of impairment exist, but at least annually on October 1 of each year. EME's goodwill is primarily related to the acquisitions of Contact Energy and First Hydro. EME determined through a fair value analysis conducted by third parties that the fair value of the Contact Energy and First Hydro reporting units was in excess of book value. Accordingly, no impairment of the goodwill related to these reporting units was recorded upon adoption of this standard.

        Determining the fair value of the reporting unit under SFAS No. 142 is a critical accounting estimate because: (1) it is susceptible to change from period to period since it requires assumptions regarding future revenues and costs of operations and discount rates over an indefinite life, and (2) the impact of recognizing an impairment on EME's consolidated financial position and results of operations would be material. EME has engaged third parties to conduct appraisals of the fair value of the major reporting units with goodwill on October 1, 2003 (the annual impairment testing date). The fair value of the First Hydro and Contact Energy reporting units set forth in these appraisals exceeded the carrying value.

Off-Balance Sheet Financing

        EME has entered into sale-leaseback transactions related to the Collins, Powerton and Joliet plants in Illinois and the Homer City facilities in Pennsylvania. See "—Contractual Obligations, Commitments and Contingencies—Operating Lease Obligations." Each of these transactions was completed and accounted for by EME as an operating lease in its consolidated financial statements in accordance with Statement of Financial Accounting Standards No. 98 "Sale-Leaseback Transactions Involving Real Estate" (SFAS No. 98), which requires, among other things, that all of the risk and rewards of ownership of assets be transferred to a new owner without continuing involvement in the assets by the former owner other than as normal for a lessee. Completion of sale-leaseback transactions of these power plants is a complex matter involving management judgment to determine compliance with the provision SFAS No. 98, including the transfer of all of the risk and rewards of ownership of the power plants to the new owner without EME's continuing involvement other than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original acquisition of the assets or to repay indebtedness previously incurred for the acquisition. Each of these leases uses special purpose entities.

        Based on existing accounting guidance, EME does not record these lease obligations in its consolidated balance sheet. If these transactions were required to be consolidated as a result of future changes in accounting guidance, it would: (1) increase property, plant and equipment and long-term obligations in the consolidated financial position, and (2) impact the pattern of expense recognition related to these obligations as EME would likely change from its current straight-line recognition of rental expense to an annual recognition of the straight-line depreciation on the leased assets as well as the interest component of the financings which is weighted more heavily toward the early years of the obligations. The difference in expense recognition would not affect EME's cash flows under these transactions. See "—Liquidity and Capital Resources—Off-Balance Sheet Transactions—Sale-Leaseback Transactions." Also see "—Liquidity and Capital Resources—Agreement In Principle to Terminate the Collins Station Lease."

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Income Taxes

        SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109), requires the asset and liability approach for financial accounting and reporting for deferred income taxes. EME uses the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. See Note 14 to the "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements" for additional details.

        As part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes in each of the jurisdictions in which it operates. This process involves estimating actual current tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within EME's consolidated balance sheet. EME does not provide for federal income taxes or tax benefits on the undistributed earnings or losses of its international subsidiaries because earnings either are reinvested indefinitely or would not be subject to additional taxes if repatriated. At December 31, 2003, EME reviewed the undistributed earnings of its international subsidiaries and concluded:

•

Its international holding company, MEC International B.V., had negative retained earnings under U.S. generally accepted accounting principles and negative accumulated earnings and profits for federal income tax purposes.



•

Distributions of lower tier international subsidiaries to MEC International B.V. are either not taxable or could be distributed without additional income taxes.



•

MEC International B.V had outstanding indebtedness to domestic subsidiaries of EME totaling $445 million at December 31, 2003 which could be repaid without incurring additional income taxes.

        For additional information regarding EME's accounting policies, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Summary of Significant Accounting Policies."

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RESULTS OF OPERATIONS

Consolidated Operating Results

Net Income Summary

        Net income is comprised of the following components:

        EME's income from continuing operations in 2003 was $28 million compared to $96 million in 2002 and $83 million in 2001. The 2003 decrease in income from continuing operations was primarily due to asset impairment charges of $182 million, after tax, described below, reduction in revenue from EME's Illinois Plants, lower earnings from EME's First Hydro plant, and lower state tax benefits than in 2002. Partially offsetting these items were net charges and credits in 2002 totaling $50 million, after tax, described below, higher U.S. energy prices, the start of operations at Phase 2 of the Sunrise project in June 2003, and increased earnings from Contact Energy and the Paiton project.

        The $182 million after-tax impairment charges included a $150 million, after tax, loss related to eight small peaking plants in Illinois recorded in the second quarter of 2003, and a $32 million, after tax, loss from the write-down of EME's investment in the Brooklyn Navy Yard project due to its planned disposition recorded in the fourth quarter of 2003. The impairment charge relating to the peaking plants resulted from a revised long-term outlook for capacity revenues. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. Since capacity value represents a key revenue component for these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets to their estimated fair market value.

        The 2002 increase in income from continuing operations from 2001 was primarily due to improved operating results at EME's Illinois Plants and the Loy Yang B plants, income from the Paiton project in Indonesia, and lower state income taxes, partially offset by lower West Coast energy prices, unplanned outages at the Homer City facilities, 2001 gains related to gas swaps from EME's oil and gas activities and net charges and credits during 2002 totaling $36 million, after tax. These after-tax charges and credits include a $52 million after-tax write-off of capitalized costs related to the termination of equipment purchase contracts and the write-off of capitalized costs associated with the suspension of the SCR major capital improvements project at the Powerton Station, and a $27 million after-tax loss from a settlement agreement that terminated the obligation to build additional generation in Chicago, partially offset by a gain of $43 million, after tax, from the settlement of a postretirement employee benefit liability.

        EME's income from discontinued operations in 2003 was $1 million compared to loss from discontinued operations of $57 million in 2002 and $1.2 billion in 2001. The 2002 loss from discontinued operations primarily represents an after-tax asset impairment charge of $77 million related to the Lakeland project in the United Kingdom. The 2001 loss includes an after-tax asset impairment charge of $1.2 billion related to the Ferrybridge and Fiddler's Ferry project in the United Kingdom.

        EME's 2003 loss from a change in accounting principle results from the adoption of a new accounting standard for asset retirement obligations. EME's 2002 loss from a change in accounting

53

principle results from the adoption of a new accounting standard for goodwill. EME's 2001 gain from a change in accounting principle results from the adoption of an accounting standard as amended and interpreted on derivative instruments. See "—Cumulative Effect of Change in Accounting Principle" for further discussion of these changes in accounting.

Operating Revenues

        Operating revenues increased 16% in 2003 from 2002, and increased 11% in 2002 from 2001. Operating revenues in 2003 increased from 2002 primarily due to increased electric revenues from Contact Energy primarily due to higher wholesale electricity prices, higher generation, and an increase in the value of the New Zealand dollar compared to the U.S. dollar. In addition, operating revenues increased in 2003 due to increased electric revenues from the Homer City facilities due to increased generation and higher energy prices. Partially offsetting these increases were lower capacity revenues from the Illinois Plants due to a reduction in megawatts under contract with Exelon Generation in 2003.

        Operating revenues in 2002 increased from 2001 primarily due to consolidating Contact Energy operating revenue for a full year in 2002 as compared to a partial year in 2001 (EME's ownership interest increased to 51%, effective June 1, 2001), increased revenues from the Illinois Plants and the First Hydro plant, partially offset by decreased revenues from Homer City.

        Net gains (losses) from price risk management and energy trading activities are comprised of:

        Net gains and (losses) from price risk management activities result from recording derivatives at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). Included in net gains (losses) from price risk management were:

•

$11 million in 2003 and $(2) million in 2002 related to the ineffective portion of Homer City forward electricity contracts, which are derivatives that qualify as cash flow hedges under SFAS No. 133, effective April 1, 2002.



•

$4 million in 2003, $(400) thousand in 2002 and $(3) million in 2001 related to the change in the market value of electricity and financial contracts entered into by Contact Energy.



•

$(10) million in 2003, $(9) million in 2002 and $3 million in 2001 related to the change in market value of commodity contracts entered into by the First Hydro plant for the purchase and sale of electricity that is recorded at fair value under SFAS No. 133, with changes in fair value recorded through the income statement, effective July 1, 2001.



•

$(1) million in 2002 and $(21) million in 2001 related to hedging EME's anticipated fuel purchases at the Illinois Plants that did not qualify for hedge accounting under SFAS No. 133.



•

$(1) million in 2002 and $45 million in 2001 related to hedging a portion of EME's gas price risk related to its share of gas production in Four Star, an oil and gas company in which EME has a minority interest and which is accounted for under the equity method. Although EME believes that these financial instruments hedge its gas price risk, hedge accounting is not

54

permitted for transactions or investments accounted for on the equity method, and thus EME is required to record changes in fair value of these positions through the 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, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $13 million, $(2) million and $(1) million in 2003, 2002 and 2001, respectively, representing the amount of the ineffective portion of the cash flow hedges. The ineffective gain during 2003 from Homer City was primarily attributable to decreases in the difference between energy prices at PJM West Hub (where EME's subsidiary enters into forward contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the Homer City busbar). In addition, Homer City recognized ineffective gains related to forward contracts that expired during 2003. See "—Market Risk Exposures—Americas" for more information regarding forward market prices.

        The 2003 net gains from energy trading activities were primarily the result of net gains from transmission congestion contracts and other power contracts in markets where EME has power plants. The increase in net gains from energy trading activities in 2002 from 2001 was primarily due to the completion of the restructuring of the power sales agreement described below and as a result of realized gains from transmission congestion contracts. As part of the restructuring transaction, an EME subsidiary purchased the power sales agreement held by a third party, modified its terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over their term, net gains of $22 million were recorded in 2002 attributable to the fair value of the contracts (generally referred to as mark-to-market accounting).

        EME's third quarter electric revenues are generally materially higher than revenues related to other quarters of the year because warmer weather during the summer months results in higher electric revenues being generated from the Homer City facilities and the Illinois Plants. By contrast, the First Hydro plants generally have higher electric revenues during their winter months.

Operating Expenses

        Fuel costs increased 17% in 2003 from 2002, and increased 16% in 2002 from 2001. The 2003 increase was primarily due to increased generation from the Homer City facilities and increased fuel costs from Contact Energy primarily due to higher gas prices and an increase in the value of the New Zealand dollar compared to the U.S. dollar. The 2003 increase in Homer City generation was primarily the result of outages experienced during the first two quarters of 2002. Fuel costs in 2002 increased from 2001 primarily due to consolidating Contact Energy fuel costs for a full year in 2002 as compared to a partial year in 2001 (EME's ownership interest increased to 51%, effective June 1, 2001), increased pumping power costs from the First Hydro plant and increased fuel costs from the Illinois Plants, partially offset by decreased fuel costs from Homer City.

        Plant operations and transmission costs increased $147 million in 2003 from 2002, and increased $58 million in 2002 from 2001. Transmission costs were $267 million in 2003, $187 million in 2002 and $100 million in 2001. The 2003 increase in transmission costs was primarily due to higher retail sales generated by Contact Energy and an increase in the value of the New Zealand dollar compared to the U.S. dollar. The 2002 increase in transmission costs was primarily due to consolidating Contact Energy, effective June 1, 2001.

        Plant operating leases increased $73 million in 2002 from 2001. The 2002 increase was due to the sale-leaseback transaction for the Homer City facilities. There were no comparable lease costs for the Homer City facilities through the period ended December 2001. See "—Off-Balance Sheet

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Transactions—Sale-Leaseback Transactions," for discussion of the financial impact of sale-leaseback transactions.

        Depreciation and amortization expense increased $43 million in 2003 from 2002, and decreased $16 million in 2002 from 2001. The 2003 increase was primarily due to higher depreciation expense from Contact Energy associated with the Taranaki Station acquisition. Also contributing to the 2003 increase was additional depreciation expense resulting from the termination of the Midwest Generation equipment lease in August 2002. The 2002 decrease was primarily due to lower depreciation expense from Homer City related to the sale-leaseback transaction from Homer City in December 2001.

        The settlement of postretirement employee benefit liability in 2002 relates to a retirement health care and other benefits plan for union-represented employees at the Illinois Plants that expired on June 15, 2002. In October 2002, Midwest Generation reached an agreement with its union-represented employees on new benefits plans, which extend from January 1, 2003 through June 15, 2006. Midwest Generation continued to provide benefits at the same level as those in the expired agreement until December 31, 2002. The accounting for postretirement benefits liabilities has been determined on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that Midwest Generation assumed, for accounting purposes, that it would provide for postretirement health care benefits to union-represented employees following conclusion of negotiations to replace the current benefits agreement, even though Midwest Generation had no legal obligation to do so. Under the new agreement, postretirement health care benefits will not be provided. Accordingly, Midwest Generation treated this as a plan termination under SFAS No. 106 and recorded a pre-tax gain of $71 million during the fourth quarter of 2002.

        Asset impairment and other charges were $304 million in 2003, $131 million in 2002 and $59 million in 2001. Asset impairment charges in 2003 consisted of $245 million related to the impairment of eight small peaking plants owned by EME's wholly owned subsidiary, Midwest Generation, in Illinois, $53 million to write-down the estimated net proceeds from the planned sale of the Brooklyn Navy Yard project, and $6 million related to the write-down of EME's investment in the Gordonsville project due to its planned disposition (refer to "—Dispositions" for further discussion). The impairment charge relating to the peaking plants resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. See "—Market Risk Exposures—Illinois Plants." The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5% discount rate.

        Asset impairment and other charges in 2002 consisted of $61 million related to the write-off of capitalized costs associated with the termination of equipment purchase contracts with Siemens Westinghouse, $45 million from a settlement agreement that terminated the obligation to build additional generation in Chicago, and $25 million related to the write-off of capitalized costs associated with the suspension of the Powerton Station SCR major capital environmental improvements project at the Illinois Plants. Asset impairment and other charges in 2001 consisted of $34 million to write-down the estimated net proceeds from the planned sale of the Commonwealth Atlantic, Gordonsville, Harbor and James River projects and $25 million related to a loss on the termination of a portion of EME's Master Turbine Lease.

        Administrative and general expenses increased $5 million in 2003 from 2002, and decreased $12 million in 2002 from 2001. The 2003 increase was primarily due to debt restructuring costs of $15 million recorded in 2003, mostly offset by charges for severance and other related costs of

56

$13 million recorded in 2002. The 2002 decrease was primarily due to lower business development costs and lower long-term incentive compensation expense recorded in 2002.

Other Income (Expense)

        Equity in income from unconsolidated affiliates increased 30% in 2003 from 2002, and decreased 24% in 2002 from 2001. The 2003 increase was primarily due to an increase in EME's share of income from the Big 4 projects, Four Star Oil & Gas and the Sunrise project. The 2002 decrease was primarily due to a decrease in EME's share of income from the Big 4 projects and Four Star Oil & Gas, partially offset by an increase in EME's share of income from the Paiton Energy and ISAB projects. EME's third quarter equity in income from its domestic energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's domestic energy projects, located on the West Coast, have power sales contracts that provide for higher payments during the summer months.

        Interest and other income decreased $10 million in 2003 from 2002, and decreased $17 million in 2002 from 2001. The 2003 and 2002 decreases were primarily due to lower interest income and higher foreign exchange losses from EME's intercompany loans.

        Gains on sale of assets were $13 million, $5 million and $41 million in 2003, 2002 and 2001, respectively. The gain on sale of assets in 2003 and 2002 represents the sale of development projects in Thailand and the United Kingdom during December 2003 and December 2002, respectively. Proceeds from the sales were $13 million and $6 million, respectively. Gains on sale of assets for 2001 included:

        Gain on early extinguishment of debt of $10 million in 2001 is attributable to the extinguishment of debt that was assumed by third-party lessors in the Homer City sale-leaseback transaction on December 7, 2001. EME reclassified this amount in the fourth quarter of 2002 due to the early adoption of SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections."

        Interest expense increased $46 million in 2003 from 2002, and decreased $90 million in 2002 from 2001. The 2003 increase was due to a combination of the following:

•

higher interest costs at the Illinois Plants due to a downgrade of the credit rating of Edison Mission Midwest Holdings. See "—Liquidity and Capital Resources—Credit Ratings;"



•

higher levels of borrowings at Contact Energy related to the Taranaki Station acquisition; and



•

change in classification of dividend payments on preferred securities to interest expense from dividends on preferred securities, commencing July 1, 2003. See "—New Accounting Standards—Statement of Financial Accounting Standards No. 150."

        The 2002 decrease in interest expense was due to a combination of the following:

•

a reduction of $830 million in bonds assumed by the lessor in the sale-leaseback transaction of the Homer City facilities in December 2001 and a reduction of $350 million in corporate debt from the proceeds of such transaction; and



•

lower borrowings combined with lower interest rates on variable rate debt generally tied to LIBOR, partially offset by higher interest costs as a result of EME's and Edison Mission Midwest Holdings' credit downgrades.

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Income Taxes

        EME had effective tax provision (benefit) rates of (57)% in 2003, 24% in 2002 and 47% in 2001. The lower effective income tax rate in 2003 from 2002 is due to income tax benefits related to the impairment charges. During the second quarter of 2003, EME recorded a tax benefit of $98 million relating to the impairment of the small peaking plants in Illinois and its Gordonsville project. The Turkish corporate tax rate decreased from 33% to 30%, retroactive to January 1, 2003, as a result of legislation passed in April 2003. In accordance with SFAS No. 109, "Accounting for Income Taxes," the reductions in the Turkish income tax rates resulted in an increase in income tax expense of approximately $4 million during the second quarter of 2003 due to a reduction in deferred tax assets.

        The lower effective income tax rate in 2002 from 2001 is due to additional state tax benefits recorded by EME, net of federal income taxes, of $32 million resulting from changes in estimates of the 2001 and 2002 tax-allocation calculation completed by Edison International. Under the tax-allocation agreement, EME's current state tax benefit is generally determined by using Edison International's combined state tax liability and calculating the difference between including and excluding EME's taxable income or losses and state apportionment factors. During the third quarter of 2002, Edison International substantially completed preparation of its 2001 combined state income tax returns and changed its 2002 estimated state income tax projection. EME expects that approximately $9 million of this benefit will not be paid until 2005.

Minority Interest

        Minority interest expense increased $12 million in 2003 from 2002, and increased $5 million in 2002 from 2001. Minority interest primarily relates to 49% ownership of Contact Energy by the public in New Zealand.

Discontinued Operations

Lakeland Project

        EME's Lakeland project operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom. The assets of the project were owned by EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe).

        On December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20, 2002, the Lakeland project lenders appointed an administrative receiver over the assets of Lakeland Power Ltd. An administrative receiver was appointed to take control of the affairs of Lakeland Power Ltd. and was given a wide range of powers (specified in the U.K. Insolvency Act), including authorizing the sale of the power plant. On May 14, 2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the project.

        EME ceased to consolidate the activities of Lakeland Power Ltd. once the administrative receiver had been appointed. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors with any residual amount distributed to EME's subsidiary that owns the outstanding shares of Lakeland Power Ltd. There is no assurance that there will be any cash available to distribute from the ultimate resolution of this claim. See "Edison

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Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 8. Discontinued Operations."

        During the year ended December 31, 2003, EME recorded losses of $2 million from discontinued operations related to administrative expenses incurred as part of the close-out activities relating to the Lakeland project. In the fourth quarter of 2002, EME recorded an impairment charge of $92 million ($77 million after tax) and a provision for bad debts of $1 million, after tax, arising from the write-down of the Lakeland power plant and related claims under the power sales agreement (an asset group under SFAS No. 144) to their fair market value.

Ferrybridge and Fiddler's Ferry Project

        On December 21, 2001, EME 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. The sale is the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. 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. EME recorded an after-tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. 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.

        During 2003, EME recorded gains of $3 million from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale of the power plants, partially offset by losses related to taxes. During 2002, EME recorded a loss of $2 million from discontinued operations primarily due to a $7 million loss on settlement of the pension plan related to previous employees of the Ferrybridge and Fiddler's Ferry project, partially offset by an insurance recovery from claims filed prior to the sale of the power plants. The loss on settlement of the pension plan arose from the election by former employees in March 2002 to transfer to American Electric Power's new pension plan and the subsequent transfer of pension assets and liabilities in December 2002 in accordance with the terms of the sale agreement.

        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 million at December 21, 2001 resulted in a loss of $28 million, after tax, attributable to the write-off of unamortized debt issue costs.

        Effective January 1, 2001, EME recorded a $6 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of EME's 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. EME could not conclude 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 Ferrybridge and Fiddler's Ferry's energy contracts were recorded at fair value with subsequent changes in fair value being recorded through the income statement.

Cumulative Effect of Change in Accounting Principle

Statement of Financial Accounting Standards No. 143

        Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related

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long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

Statement of Financial Accounting Standards No. 142

        Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. EME commenced its annual evaluation of goodwill on October 1, 2003. During the third quarter of 2002, EME concluded that fair value of the goodwill related to the Citizens Power LLC acquisition was impaired by $14 million, net of $9 million of income tax benefit and, accordingly, reported this amount as a cumulative change in accounting. In accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002.

Statement of Financial Accounting Standards No. 133

        Effective January 1, 2001, EME 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.

        On January 1, 2001, EME recorded a $250 thousand, after tax, increase to net income and a $230 million, after tax, decrease to other comprehensive income as the cumulative effect of the adoption 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:

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As a result of the new interpretation, EME's 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, EME eliminated the value of the Homer City forward sales contracts from its consolidated balance sheet. The cumulative effect of this change in accounting is reflected as a $16 million, after tax, decrease to other comprehensive income in 2001.



•

For the period between January 1, 2001 and June 30, 2001, EME applied the normal sales and purchases exception for long-term commodity contracts that included both selling and purchasing electricity by its 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, EME recorded a $15 million, after tax, increase to net income as the cumulative effect of change in accounting for derivatives in the consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of these contracts were reflected in net gains (losses) from price risk management in EME's consolidated income statement.

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Regional Operating Results

Overview

        EME operates predominantly in one line of business, electric power generation, organized by three geographic regions: Americas, Asia Pacific, and Europe. Operating revenues are derived from EME's majority-owned domestic and international entities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the following project results, except as described below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation. Equity in income from unconsolidated affiliates relates to energy projects where EME's 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 EME has a significant influence but in which it does not have a controlling interest. With respect to entities accounted for under the equity method, EME recognizes its proportional share of the income or loss of such entities.

        EME uses the word "earnings" or "losses" in this section to describe income or loss from continuing operations before income taxes and minority interest.

Americas

General

        The following section provides a summary of the Americas Region's operating results for the three years ended December 31, 2003 together with discussions of significant factors contributing to these results.