Back to GetFilings.com

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, 2004

Commission File Number 333-68632

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

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

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

None
(Title of Class)

        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. 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 30, 2004: $0. Number of shares outstanding of the registrant's Common Stock as of March 10, 2005: 1,000 shares (all shares held by an affiliate of the registrant).

DOCUMENTS INCORPORATED BY REFERENCE

        Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.

TABLE OF CONTENTS

i

PART I

       Mission Energy Holding Company, which is referred to as MEHC in this annual report, did not conduct any business prior to its formation on June 8, 2001. All MEHC's substantive operations are currently conducted by Edison Mission Energy, which is referred to as EME in this annual report, and its subsidiaries and investments.

       The presentation of information below pertaining to EME and its consolidated subsidiaries should not be understood to mean that EME has agreed to pay or become liable for any debt of MEHC. EME and MEHC are separate entities with separate obligations. MEHC is the sole obligor on the $800 million of 13.50% senior secured notes due 2008, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes.

ITEM 1.    BUSINESS

The Company

       MEHC was formed as a wholly owned subsidiary of Edison Mission Group Inc., which is a wholly owned subsidiary of Edison International. MEHC was formed to hold the common stock of EME. On July 2, 2001, Edison Mission Group Inc. contributed to MEHC all the outstanding common stock of EME. The contribution of EME's common stock to MEHC has been accounted for as a transfer of ownership of companies under common control, which is similar to a pooling of interest. This means that MEHC's historical financial results of operations and financial position will include the historical financial results and results of operations of EME and its subsidiaries as though MEHC had such ownership throughout the periods presented. MEHC's only substantive liabilities are its obligations under the senior secured notes and corporate overhead, including fees of its legal counsel, auditors and other advisors. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments.

       During 2004 and early 2005, EME completed the sale of substantially all its international assets totaling 6,452 MW as part of the restructuring plan announced during the fourth quarter of 2003 designed to reduce debt and improve liquidity. Highlights of these activities are described below.

•

On September 30, 2004, EME completed the sale of its 51.2% interest in Contact Energy Limited to Origin Energy New Zealand Limited.

•

On December 16, 2004, EME completed the sale of the stock and related assets of MEC International B.V. to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), which is referred to as IPM in this annual report. The sale of MEC International B.V. included the sale of EME's ownership interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico.

•

On January 10, 2005, EME completed the sale of its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) hydroelectric power project located in the Philippines to CBK Projects B.V.

•

On February 3, 2005, EME completed the sale of its 25% equity interest in the Tri Energy project to IPM.

       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 Estimates" for further details on EME's asset sales.

1

       MEHC is incorporated under the laws of the State of Delaware. MEHC's headquarters and principal executive offices are located at 2600 Michelson Drive, Suite 1700, Irvine, California 92612, and its telephone number is (949) 852-3576.

       Mission Energy Holding Company's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports are electronically filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and are available on the Securities and Exchange Commission's internet web site at http://www.sec.gov.

Forward-Looking Statements

       This annual report on Form 10-K contains forward-looking statements that reflect MEHC's current expectations and projections about future events based on MEHC's knowledge of present facts and circumstances and assumptions about future events. Other information distributed by MEHC 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 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 MEHC or its subsidiaries, include:

•

the ability of EME to declare and pay dividends;

•

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;

•

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

•

general political, economic and business conditions;

•

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;

•

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;

•

the cost and availability of transmission services;

•

the cost and availability of required emission allowances;

•

weather conditions, natural disasters and other unforeseen events; and

•

MEHC'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 MEHC's business. The information contained in this

2

annual report is subject to change without notice, and MEHC is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by MEHC with the Securities and Exchange Commission.

Description of the Industry

Electric Power Industry

       The United States electric industry, including companies engaged in providing generation, transmission, distribution and ancillary services, has undergone significant deregulation, which has led to increased competition. Until the enactment of the Public Utility Regulatory Policies Act of 1978, referred to as PURPA in this annual report, utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. PURPA 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.

       As part of the regulatory developments discussed above, the Federal Energy Regulatory Commission, referred to as the FERC in this annual report, encouraged the formation of independent systems operators (ISOs) and regional transmission organizations (RTOs). In those areas where ISOs and RTOs have been formed, market participants have expanded access to transmission service. ISOs and RTOs may also operate real-time and day ahead energy and ancillary service markets, which are governed by FERC-approved tariffs and market rules. The development of markets into which independent power producers are able to sell has reduced their dependence on bilateral contracts with electric utilities. See further discussion of regulations under "Regulatory Matters—U.S. Federal Energy Regulation."

       EME's largest power plants are located in Illinois and Pennsylvania and sell power into PJM Interconnection, LLC, commonly referred to as PJM. PJM is the largest centrally dispatched electric control area in North America. As reported on the PJM website (www.pjm.com) on March 1, 2005, PJM consists of about 1,000 generating units with a total installed capacity of approximately 137,490 MW, serves approximately 45.3 million people, and covers portions of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, Illinois, Indiana, Kentucky, Michigan, Ohio, Tennessee, West Virginia and Virginia. PJM operates the wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators which indicate the minimum prices a bidder is willing to accept to be dispatched at various incremental generation levels. PJM conducts both day-ahead and real-time energy markets. PJM's energy markets are based on locational marginal pricing, which establishes hourly prices at specific locations throughout PJM. Locational marginal pricing is determined by considering a number of factors, including generator bids, load requirements, transmission congestion and transmission losses. PJM requires all load serving entities to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM also determines the amount of capacity available from each specific generator and operates capacity markets. PJM's capacity markets have a single market-clearing price. Load serving entities and generators, such as EME's subsidiaries Midwest Generation, LLC (Midwest Generation) and EME Homer City Generation L.P. (EME Homer City), may participate in PJM's capacity markets or transact capacity on a bilateral basis.

3

Competition and Market Condition Generally

       EME is subject to intense competition from energy marketers, utilities, industrial companies and other independent power producers. In prior years, the restructuring of energy markets 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 decommissioning of operations at several power plants.

       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 and availability of fuel and the presence of transmission constraints. EME's customers include large electric utilities or regional distribution companies. In some cases, the electric utilities and distribution companies have their own generation capacity, including nuclear generation, that affects the amount of generation available to meet demand and may affect the price of electricity in a particular market.

       The proposed introduction of a new standard market design structure by 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."

Operating Segments

       EME continues to operate in one line of business, electric power generation, with all of its continuing operations located in the United States, except the Doga project in Turkey. Operating revenues are primarily related to the sale of power generated from the Illinois Plants and Homer City facilities. EME is headquartered in Irvine, California with additional offices located in Chicago, Illinois and Boston, Massachusetts. As a result of the sale of EME's interest in Contact Energy Limited and most of the remainder of its portfolio of international assets (which made up the reportable segments in Asia Pacific and Europe), EME does not meet the criteria for segment reporting.

4

Overview of Domestic Facilities

       As of December 31, 2004, EME's continuing operations consisted of ownership or leasehold interests in the following domestic operating power plants:

(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)

Electric purchaser abbreviations are as follows:

       A description of EME's larger power plants and major investments in energy projects is set forth below. 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.

Illinois Plants

       On December 15, 1999, Midwest Generation completed a transaction with Commonwealth Edison Company (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 in this annual report. 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.

5

       The Illinois Plants include the following:

(1)

Operations at Will County Station Units 1 and 2 (310 MW) were returned to service in late 2004 after being suspended since January 2003.

(2)

Since September 30, 2004, all Collins Station units ceased operations and were decommissioned by the fourth quarter of 2004. For more information on the Collins Station, see below.

(3)

In September 2004, management completed an analysis of future competitiveness in the expanded PJM marketplace of eight of its small peaking units in Illinois. Based on this analysis and regulatory approval, planning efforts are in progress to decommission six of its eight remaining small peaking units.

       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. In April 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity investor and received title to the Collins Station as part of the transaction. On September 30, 2004, Midwest Generation permanently ceased operations of the Collins Station. By the fourth quarter of 2004, the Collins Station was decommissioned and all units were permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered. See "Termination of the Collins Station Lease" section in Item "7. Management's Discussion and Analysis of Financial Condition and Results of Opeations—Liquidity and Capital Resources."

       In August 2000, EME completed sale-leaseback transactions involving its Powerton and Units 7 and 8 of its Joliet power facilities. EME sold these assets to third parties and entered into long-term leases of the facilities from these third parties to repay corporate debt while maintaining control of the use of the power plants during the terms of the leases. See "Off-Balance Sheet Transactions" section in "Item 7.

6

Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

Illinois Power Markets

       In connection with the acquisition of the Illinois Plants, Midwest Generation entered into three separate five-year power purchase agreements with Commonwealth Edison, which were subsequently assigned to its affiliate, Exelon Generation Company LLC (Exelon Generation). The Collins Station power purchase agreement was terminated on September 30, 2004 and the other two power purchase agreements expired on December 31, 2004. During each of 2000, 2001 and 2002, approximately 99% of Midwest Generation's energy and capacity revenues were derived under the power purchase agreements. In 2003 and 2004, the percentage decreased to approximately 65% and 53%, respectively, with the balance coming from sales by Midwest Generation into the wholesale power markets.

       Beginning in 2005, all the energy and capacity from the Illinois Plants are sold under terms, including price and quantity, negotiated by Edison Mission Marketing & Trading, Inc., an EME subsidiary engaged in the power marketing and trading business, with customers through a combination of bilateral agreements, forward energy sales and spot market sales. These arrangements generally have terms of two years or less. Thus, EME is subject to market risks related to the price of energy and capacity from the Illinois Plants. As discussed further below, sales of electricity from the Illinois Plants now include sales into PJM. Capacity prices for merchant energy sales within PJM are, and are expected in the near term to remain, substantially lower than those Midwest Generation received under the power purchase agreements with Exelon Generation.

       Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants were 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 have historically been 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. "Into ComEd" and "Into AEP" were bilateral markets for the sale or purchase of electrical energy for future delivery. Due to geographic proximity, "Into ComEd" was the primary market for Midwest Generation.

       On May 1, 2004 and October 1, 2004, respectively, operational control of the control area systems of Commonwealth Edison and AEP was transferred to PJM, which is now the primary market available to Midwest Generation. This transfer resulted in the conversion of the "Into ComEd" and "Into AEP" trading hubs to locational marginal pricing, which has further facilitated transparency of prices and provided liquidity to support risk management strategies. 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. However, liquidity in all of these markets has been adversely affected by the financial problems of trading and marketing entities.

       Following the transfer of control of the control area systems of Commonwealth Edison and AEP to PJM, sales of electricity from the Illinois Plants now include bilateral and spot sales into PJM, with spot

7

sales being based on locational marginal pricing. These sales into the expanded PJM replaced sales previously made as bilateral sales and spot sales "Into ComEd" and "Into AEP." The Northern Illinois Hub is the primary trading hub for Midwest Generation produced power due to geographic proximity and high pricing correlation to the plants' output locations.

       The Midwest Independent Transmission System Operator, an RTO authorized pursuant to the FERC's Order No. 2000, commonly referred to as the MISO, which will control the former control areas of Alliant Energy Corporation (Wisconsin Power and Light Co. and Interstate Power and Light Co.), Aquila, Inc., Ameren Corporation, Cinergy Corp., Kentucky Utilities Company, LG&E Energy LLC, Vectren Corporation and Xcel Energy, Inc., among others, is scheduled to begin operation of its locational marginal pricing market on April 1, 2005. It is anticipated that the opening of the MISO market will provide increased liquidity in the Midwest electricity markets. "Into Cinergy" will become a locational marginal pricing location in MISO at that time. See "Regulatory Matters" for a more detailed discussion of recent developments regarding Commonwealth Edison and AEP joining PJM. See "—Transmission" below for additional discussion.

       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."

Transmission

       Historically, sales of power produced by Midwest Generation required using transmission that had to be obtained from Commonwealth Edison. An ISO did not yet oversee operations of the Commonwealth Edison control area; however, effective May 1, 2004 such operations were placed under the control of PJM. Furthermore, the transmission system of AEP was integrated into PJM on October 1, 2004, which linked the Northern Illinois and eastern portions of the PJM system and permitted the Illinois Plants to be dispatched into the broader PJM market. In addition, a number of other utilities in the region participate in the MISO 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 MISO. The open access transmission tariffs of the MISO 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's 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.

       On November 18, 2004, the FERC issued an order eliminating regional through and out transmission rates in the region encompassed by PJM (as recently expanded) and the MISO. The effect of this order was to eliminate so-called rate pancaking between PJM and the MISO. 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. At the same time, the FERC also imposed a transitional revenue recovery mechanism which has created controversy and some continuing uncertainty as to the impact of such mechanism on transactions in the region. The mechanism required the filing of tariffs by PJM and the MISO imposing a "Seams Elimination Cost Adjustment" (SECA) to be in effect until May 1, 2006, to compensate the "new PJM companies"—AEP, Commonwealth Edison and Dayton Power & Light, among others—for lost revenues attributable to such elimination. On November 30, 2004, the FERC clarified that SECAs can be recovered for lost revenues associated with elimination on intra-RTO pancaking.

8

       The response to the November 18 and November 30 orders from the parties liable for the SECAs has been strongly negative, and a rehearing has been sought by a broad range of interests that are opposed to the imposition of SECAs. Although both PJM and the MISO have made tariff filings with the FERC that purport to comply with such order and eliminate through and out transmission rates as of December 1, 2004, numerous protests to such filings have been made, challenging SECAs on legal and equitable grounds and demanding evidentiary hearings by the FERC. In its tariff filing, PJM imposes SECAs only on load-serving entities, and not on other transmission customers such as Midwest Generation, but the MISO tariff provision imposes SECAs on all such customers. That provision does not directly affect Midwest Generation because it is not a transmission customer of the MISO; however, the issue of which entities should bear SECAs is one of the many points that have been raised in the protests described above and have become the subject of hearings ordered by the FERC.

       Pending further orders of the FERC and/or the outcome of the hearings described above, under the provisions of the PJM tariff as filed, Midwest Generation is currently not subject to SECAs with respect to its sales of power within PJM. It is not possible, however, to predict the outcome of the hearings or to rule out the possibility that Midwest Generation could be ordered in the future to pay SECAs with respect to sales within PJM after December 1, 2004.

       For further discussion of the market 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."

Fuel Supply

       Coal is used to fuel 5,621 MW of Midwest Generation's generating capacity. The coal is purchased from several suppliers that operate mines in the Southern Powder River Basin of Wyoming. The coal is purchased under a number of supply agreements ranging from one year to four years in length. The total volume of coal consumed annually is largely dependent on the amount of generation and ranges between 16 million to 20 million tons.

       All coal is transported under long-term transportation agreements with the Union Pacific Railroad and various delivering carriers. As of December 31, 2004, Midwest Generation leased approximately 3,800 railcars to transport the coal from the mines to the generating stations and the leases have remaining terms that range from as short as 6 months up to 15 years, with options to extend the leases for or purchase some railcars at the end of the terms. The coal is transported nearly 1,200 miles from the mines to the stations.

       Coal for the Fisk and Crawford Stations is first shipped by rail to the Will County Station where it is transferred from the railcars, blended as necessary to meet station specifications, and loaded into river barges. These barges are towed to the stations by an independent contractor under a transportation agreement with Midwest Generation.

       Approximately 255 MW of Midwest Generation's peaking capacity is in the form of simple cycle combustion turbines at the Fisk and Waukegan Stations. These units are fueled with distillate fuel oils.

       See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies," for additional discussion of contractual commitments related to Midwest Generation's fuel supply and coal transportation contracts.

9

Emission Allowances

       Certain state and federal environmental laws require power plant operators to hold or obtain emission allowances equal, on an annual basis, to their plants' emissions of nitrogen oxide or sulfur dioxide. Emission allowances were acquired as part of the acquisition of the Illinois Plants. Additional allowances are purchased by Midwest Generation when operations make this necessary and are sold by Midwest Generation when it has more than needed for planned levels of operation.

       See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for a discussion of price risks related to the purchase or sale of emission allowances.

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 (referred to as Units 1, 2 and 3 in this annual report), one coal cleaning facility, water supply provided by a reservoir known as Two Lick Dam and associated support facilities in the mid-Atlantic region of the United States. The Homer City generating units 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. The NYISO was established in 1999 to operate a competitive, non-discriminatory wholesale power market in response to the FERC's Open Access Rules and includes bid-based electricity and transmission usage markets. The market-clearing price for NYISO's day-ahead and real-time energy markets is set by supplier generation bids and customer demand bids. For a discussion of the market 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."

       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—Liquidity and Capital Resources—Off-Balance Sheet Transactions."

Fuel Supply

       Units 1 and 2 typically consume approximately 3.3 million tons of mid-range sulfur coal per year. Approximately 90% to 95% of this coal is obtained under contracts with suppliers within approximately 100 miles of the Homer City facilities and the remainder is purchased in the spot market. All of this coal is delivered to the site by truck. The raw coal purchased for consumption by Units 1 and 2 is cleaned in the Homer City coal cleaning facility, which has the capacity to clean up to 5 million tons of coal per year.

       Unit 3 consumes approximately 2 million tons of coal per year. EME Homer City purchases the majority of its Unit 3 coal from local suppliers under long-term contracts. All coal purchased for Unit 3 is delivered to the site by truck. A wet scrubber flue gas desulfurization system for Unit 3 enables this

10

unit to be able to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control.

       See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies," for additional discussion of contractual commitments related to EME Homer City's fuel supply contracts.

Emission Allowances

       Certain state and federal environmental laws require power plant operators to hold or obtain emission allowances equal, on an annual basis, to their plants' emissions of nitrogen oxide or sulfur dioxide. Emission allowances were acquired as part of the acquisition of the Homer City facilities. Additional allowances are purchased by EME Homer City when operations make this necessary and are sold by EME Homer City when it has more than needed for planned levels of operation.

       See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for a discussion of price risks related to the purchase or sale of emission allowances.

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 "Mission Energy Holding Company 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 August 2005 and sells steam to Texaco Exploration and Production Inc. (TEPI), a wholly owned subsidiary of ChevronTexaco Corporation, under a steam supply agreement that expires in June 2005. As of December 31, 2004, the partnership was in negotiations to continue electricity and steam sales (to Southern California Edison and TEPI, respectively) beyond the expiration of the current agreements. Although the partnership expects to reach agreements with both Southern California Edison and TEPI, the combined revenues of these arrangements are likely to be substantially below those provided under the current agreements.

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

11

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 TEPI 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 BP West Coast Products LLC 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 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 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 in June 2001, which expires in 2012. For further discussion related to this agreement, see "Item 3. Legal Proceedings—Sunrise Power Company Lawsuits."

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 steam 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. Three of these

12

projects sell electricity to Pacific Gas & Electric Company under 15-year power purchase agreements which expire in 2007. Mid-Set Cogeneration's power purchase and steam sales agreements expired in May 2004. Mid-Set Cogeneration is continuing to sell electricity to Pacific Gas & Electric under the "as available" rates and is selling steam to TEPI under an extension of the expired steam sales agreement. As of December 31, 2004, negotiations were underway to secure new power purchase and steam sales agreements for this project.

American Bituminous Power Plant

       EME owns a 50% interest in American Bituminous Power Partners, L.P., which owns an 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.

International Project

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 Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Contingencies" for information regarding regulatory developments affecting the Doga project.

       During the third quarter of 2004, EME reclassified its international activities which were then under contracts for sale as discontinued operations. Subsequently, EME completed the sale of these operations as described above, except for the Doga project, which is no longer under a contract for sale. While EME continues to seek to sell its ownership interest in this project, there is no assurance that such efforts will result in a sale during the twelve-month period prescribed under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." As a result, EME reclassified the Doga project to continuing operations during the fourth quarter of 2004, and, accordingly, it is reflected as part of continuing operations for all periods presented.

Discontinued Operations

       For a description of discontinued operations see "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Discontinued Operations."

Price Risk Management and Trading Activities

       EME's 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. 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

13

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.

       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. 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.

       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 requires counterparties to pledge collateral when deemed necessary. EME uses published credit 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

14

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, and 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 identify, 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 when necessary through margining arrangements (agreements to provide or receive collateral based on changes in the market price of the underlying contract under specific terms) or letters of credit or guarantees. 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 Estimates—Risks Related to the Business."

Significant Customer

       In the past three fiscal years, EME derived a significant source of its revenues from the sale of energy and capacity generated at the Illinois Plants to Exelon Generation primarily under three power purchase agreements, which began on December 15, 1999. The Collins Station power purchase agreement was terminated on September 30, 2004 and the other power purchase agreements expired on December 31, 2004. Exelon Generation accounted for approximately 36%, 40% and 66% of EME's consolidated operating revenues for the years ended December 31, 2004, 2003 and 2002, respectively.

       For the year ended December 31, 2004, approximately 15% of EME's consolidated operating revenues generated at the Homer City facilities and Illinois Plants was from sales to BP Energy Company, a third-party customer. An investment grade affiliate of BP Energy has guaranteed payment of amounts due under the related contracts.

Insurance

       EME maintains insurance policies consistent with those normally carried by companies engaged in similar business and owning similar properties. EME's insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boilers, machinery breakdowns, and the perils of earthquake and flood, subject to specific sublimits. EME also carries general liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations, automobile liability insurance and excess liability insurance.

15

Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size. However, no assurance can be given that EME's insurance will be adequate to cover all losses.

Seasonality

       EME's third quarter electric revenues are materially higher than revenues related to other quarters of the year. Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Homer City facilities and the Illinois Plants are generally higher during the third quarter of each year.

       EME's third quarter equity in income from its 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 energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer months.

Regulatory Matters

General

       EME's operations are subject to extensive regulation by governmental agencies. EME's 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.

       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, or PUHCA. The enactment of PURPA 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 PUHCA for the owners of qualifying

16

facilities. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from PUHCA for exempt wholesale generators and foreign utility companies.

       A "qualifying facility" under PURPA 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 PUHCA definition of an "electric utility company"), electric utility holding companies (defined by reference to the PUHCA definitions of "electric utility company" and "holding company") or affiliates of such entities.

       An "exempt wholesale generator" under PUHCA 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 PUHCA 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 FERC's ratemaking jurisdiction 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.

       As of December 31, 2004, a number of EME's operating projects, including the Homer City facilities and the Illinois Plants, were 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.

Public Utility Holding Company Act of 1935

       Edison International, EME's ultimate parent company, is a holding company because it owns Southern California Edison, an electric utility company. However, Edison International and its subsidiaries are exempt for all provisions, except Section 9(a)(2), of the Public Utility Holding Company

17

Act of 1935 (PUHCA) on the basis that Edison International and Southern California Edison are incorporated in the same state and their utility businesses are predominantly intrastate in character and carried on substantially in their state of incorporation. Section 9(a)(2) provides, in substance, that Edison International may not directly or indirectly acquire 5% or more of the voting securities of a public utility company other than Southern California Edison, unless the acquisition has been approved by the Securities and Exchange Commission. 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 PUHCA, because its interests in power generation facilities are exclusively in qualifying cogeneration facilities, facilities owned by exempt wholesale generators and facilities owned by foreign utility companies. All projects that EME might develop or acquire will be non-qualifying facility independent power projects. Loss of exempt wholesale generator, qualifying cogeneration 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 PUHCA 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

       PURPA provides two primary benefits to qualifying facilities. First, ownership of qualifying cogeneration facilities will not cause a company to be deemed an electric utility company for purposes of PUHCA. 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 PURPA 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 had 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 cogeneration facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation under PUHCA 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 PUHCA. Under Section 26(b) of PUHCA, any project contracts that are entered into in violation of PUHCA, including contracts entered into during any period of non-compliance with the registration requirement, could be determined by the courts or the Securities and Exchange Commission to be void. If a project were to lose its qualifying facility status, 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

18

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 PURPA 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, or claims by a utility customer for the refund of payments previously made.

       EME endeavors to monitor regulatory compliance by its qualifying facility projects 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 PURPA.

       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 PUHCA and reform of PURPA. A number of other proposals have been introduced in Congress that relate to restructuring electricity markets. Different versions of such legislation passed both houses of Congress late in the 108th Congress (2003-2004) but no comprehensive energy legislation was enacted. Similar comprehensive legislation has been introduced in the 109th Congress (2005-2006), but the chances for passage of such legislation remain unclear at this time. Efforts were made in the 108th Congress to enact portions of the comprehensive energy bill on an individual basis, but, with the exception of certain tax provisions, they were unsuccessful because the Congressional leadership and administration opposed such efforts. Similar efforts are possible in the 109th Congress, but their chances for success remain unclear at this time.

Natural Gas Act

       Many of the 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.

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

19

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 PURPA, power marketers and those qualifying as exempt wholesale generators under PUHCA 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 an 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.

       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 included 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

20

proposal were filed by interested parties in October 2002 and during the first quarter of 2003. The SMD proposal engendered considerable comment, and in some cases opposition, including in the U.S. Congress.

       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.

       See "Overview of Domestic Facilities—Transmission" for further discussion of developments and other transmission issues affecting the Illinois Plants.

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—Liquidity and Capital Resources—Environmental Matters and Regulations."

Employees

       MEHC has no full-time employees. At December 31, 2004, EME and its subsidiaries employed 1,768 people, including:

•

approximately 727 employees at the Illinois Plants covered by a collective bargaining agreement governing wages, certain benefits and working conditions. This collective bargaining agreement is due to expire on December 31, 2005. Midwest Generation also has a separate collective bargaining agreement governing retirement, health care, disability and insurance benefits that expires on June 15, 2006. Most of Midwest Generation's employees were employees of Commonwealth Edison prior to Midwest Generation's acquisition of its power generation assets from Commonwealth Edison; and

•

approximately 195 employees at the Homer City facilities covered by a collective bargaining agreement governing wages, benefits and working conditions. This collective bargaining agreement expires on December 31, 2006. The majority of the technical staff at EME Homer City's facilities was retained after completing the acquisition.

MEHC's and EME's Relationship with Certain Affiliated Companies

       Both MEHC and EME are indirect subsidiaries 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.

21

ITEM 2.    PROPERTIES

       MEHC's principal office is in Irvine, California.

       EME leases its principal office in Irvine, California. This lease covers approximately 87,000 square feet and expires on December 31, 2005. EME also leases office space in Chicago, Illinois; Chantilly, Virginia; Fairfax, Virginia; Boston, Massachusetts; and Washington D.C. The Chicago lease is for approximately 41,000 square feet and expires on December 31, 2014. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010. The Fairfax lease is for approximately 16,000 square feet and expires on September 30, 2005. The Boston lease is for approximately 37,000 square feet and expires on July 31, 2007. The Washington D.C. lease is immaterial. At December 31, 2004, approximately 22% of the above space was subleased.

       The following table shows, as of December 31, 2004, the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of MEHC'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

(1)

Plant was sold on January 10, 2005. See "—The Company" for additional details.

ITEM 3.    LEGAL PROCEEDINGS

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

22

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 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 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. 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 removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants expect to file a responding pleading by April 2005. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

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

       Inapplicable.

23

PART II

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

       All the outstanding common stock of Mission Energy Holding Company (MEHC) is, as of the date hereof, owned by MEHC's direct parent, Edison Mission Group Inc., 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 MEHC's board of directors. MEHC did not pay any dividends in 2004, 2003 and 2002. MEHC's wholly owned subsidiary, Edison Mission Energy (EME), amended its certificate of incorporation and bylaws in May 2004 to eliminate the so-called "ring-fencing" provisions that were implemented in early 2001 during the California energy crisis, which had included restrictions on dividends. EME made cash dividend payments totaling $74 million and declared a dividend payable to MEHC totaling $305 million during 2004. A total of $360 million in dividends was paid in January 2005, which included the $305 million dividend payment. EME did not pay or declare any dividends to MEHC during 2003 and 2002.

       During the first two years of MEHC's operations, when debt interest payments were funded with restricted cash, MEHC was permitted to distribute to its direct parent, Edison Mission Group Inc., dividends MEHC received from EME, less MEHC's overhead costs subject to compliance with limitations contained in the senior secured notes indenture and in the term loan. Limitations on MEHC's ability to pay dividends and make other distributions to its parent are now significantly more restrictive than the restrictions applicable during the first two years of its operations. Dividends from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax considerations, and restrictions imposed by applicable law.

24

ITEM 6.    SELECTED FINANCIAL DATA

       All of EME's international operations are accounted for as discontinued operations, except the Doga project. Continuing operations include EME's Illinois Plants and Homer City facilities, equity investments in power projects primarily located in California, the Doga project in Turkey, corporate interest expense and general and administrative expenses. 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 Estimates—Management's Overview" for more information about the sale of EME's international operations and loss on lease termination, asset impairment and other charges in 2004 and 2003, and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Continuing Operations—Cumulative Effect of Change in Accounting Principle" for further explanation of accounting changes.

(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

25

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.

(3)

Assets decreased in 2004 compared to 2003 due to the completion of the sale of substantially all of EME's international assets.

26

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 Mission Energy Holding Company's (MEHC'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."

       The presentation of information below pertaining to Edison Mission Energy (EME) and its consolidated subsidiaries should not be understood to mean that EME has agreed to pay or become liable for any debt of MEHC. EME and MEHC are separate entities with separate obligations. MEHC is the sole obligor on the 13.50% senior secured notes due 2008, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes.

       The MD&A is presented in four major sections:

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

Management's Overview

MEHC as a Holding Company

       MEHC has a 100% ownership interest in EME, which itself operates through its subsidiaries and affiliates. EME continues to operate predominantly in one line of business, electric power generation with all of its continuing operations located in the United States. MEHC has no business activities other than through its ownership interest in EME. During 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008 and borrowed $385 million under a term loan (as discussed below, $100 million of the term loan was repaid in July 2004 and the remaining $285 million of the term loan was repaid in January 2005). MEHC's ability to honor its obligations under the senior secured notes is entirely dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group Inc., and ultimately Edison International. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." Dividends from EME are limited based on its earnings and cash flow, business and tax considerations, and restrictions imposed by applicable law.

       On April 5, 2004, the lenders under MEHC's $385 million term loan exercised their right to require MEHC to repurchase $100 million of the principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The $100 million of principal, plus interest, was repaid on July 2, 2004. The

27

remaining $285 million of principal, plus interest, was paid on January 3, 2005. The senior secured notes 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 would result in a change in control of EME. Since the beginning of 2004, MEHC's principal source of liquidity has been cash dividends from EME.

       EME has not guaranteed the senior secured notes 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 the 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.

Dividends to MEHC

       In 2004, EME made dividend payments of $74 million to MEHC. These payments were used together with cash on hand to meet the Term Loan Put-Option payment discussed above. In January 2005, EME made total dividend payments of $360 million to MEHC. A portion of these payments was used to repay the remaining $285 million of the term loan plus interest discussed above.

       EME amended its certificate of incorporation and bylaws in May 2004 to eliminate the so-called "ring-fencing" provisions that were implemented in early 2001 during the California energy crisis, which had included restrictions on dividends.

Dividend Restriction in EME's Corporate Credit Agreement

       On April 27, 2004, EME replaced its $145 million corporate credit agreement with a new $98 million secured corporate credit agreement. As of December 31, 2004, EME had no borrowings outstanding under this credit agreement. EME would not be able to make a distribution if an event of default were to occur and be continuing after giving effect to the distribution.

EME 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. 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. As of December 31, 2004, EME's subsidiaries and affiliates owned or leased interests in 18 power plants.

       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,

28

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, MEHC. Distributions to EME from projects are generally only available after all current debt service obligations at the project level have been paid and are further restricted by contractual restrictions on distributions included in the documentation evidencing the project level debt obligations.

EME Restructuring Activities

       During 2004, EME completed the restructuring of indebtedness related to the Illinois Plants and completed the sale of most of its international operations. These transactions were undertaken as part of a restructuring plan that was announced in late 2003.

Refinancing of Indebtedness Associated with the Illinois Plants

       In April 2004, Midwest Generation, LLC (Midwest Generation) completed a private offering of $1 billion aggregate principal amount of its 8.75% second priority senior secured notes due 2034. Concurrently with the issuance of the notes, Midwest Generation borrowed $700 million under a new first priority senior secured term loan facility. Midwest Generation also entered into a new five-year $200 million working capital facility that replaced a prior facility. Midwest Generation used the proceeds of the notes issuance and the term loan to refinance $693 million of indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which had been guaranteed by Midwest Generation and was due in December 2004, and to make the termination payment under the Collins Station lease described below.

       Also in April 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax) due to termination of the lease and the planned decommissioning of the asset. Following the termination of the Collins Station lease, Midwest Generation permanently ceased operations at the Collins Station and decommissioned the plant.

Disposition of International Operations

       EME's international operations, except the Doga project, are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. EME financial statements and the discussion set forth herein have been adjusted to this format of reporting.

       EME has now completed the sale of most of its international operations through the following transactions:

•

In September 2004, EME sold its 51.2% interest in Contact Energy Limited (Contact Energy) to Origin Energy New Zealand Limited. Consideration from the sale of Mission Energy Universal Holdings was NZ$1,101.4 million (approximately US$739 million) in cash and NZ$535 million

29

(approximately US$359 million) of assumed debt. (See "Results of Operations—Discontinued Operations.")

•

In December 2004, EME sold ten projects representing most of its remaining international power generation portfolio owned by a wholly owned Dutch subsidiary, MEC International B.V., to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to in this annual report as IPM. Consideration from the sale of its Dutch holding company and related assets was $2.0 billion. (See "Results of Operations—Discontinued Operations.")

•

In January 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to CBK Projects B.V., the purchasing entity designated by its partner, for $104 million.

•

In February 2005, EME sold its 25% equity interest in the Tri Energy project to IPM for approximately $20 million.

       In connection with the above transactions, together with cash in hand, EME:

•

Repaid $800 million of indebtedness arranged in December 2003 to provide interim financing until asset sales were completed.

•

Made distributions to MEHC (in January 2005) totaling $360 million which were subsequently used primarily to repay the remaining $285 million portion of the term loan.

•

Repaid EME's junior subordinated debentures (in January 2005) and consequently repaid the monthly income preferred securities (MIPS) of $150 million.

       A substantial portion of the proceeds derived from the above transactions has been retained by EME to meet future debt obligations, support working capital requirements and for other corporate purposes discussed further below. At February 28, 2005, EME had corporate cash and cash equivalents of $1.8 billion. While EME will continue to seek to sell its ownership interest in the Doga project, there is no assurance that such efforts will result in a sale.

EME Domestic Operations

       EME's domestic project portfolio may be grouped into two categories: contracted plants and merchant plants. At December 31, 2004, EME owned interests in 11 contracted power plants that sell a majority of their power to customers under long-term sales arrangements (greater than five years) consisting of power purchase agreements or hedge contracts. While operating these projects involves 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 seven merchant power plants (the Illinois Plants and the Homer City facilities) which operate in whole or in part without long-term sales arrangements. EME's merchant plants represent approximately 88% 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 Company LLC (Exelon Generation), all of these contracts had expired 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.

       Beginning in 2003, a significant factor affecting merchant generators was the substantial increase in the price of natural gas, especially when compared to the less volatile cost of coal. For the years 2003 and 2004, natural gas prices at Henry Hub (a major natural gas trading hub) averaged $5.48 and $5.91, respectively, per million British thermal units, commonly referred to as MMBtu, compared to $3.37 per

30

MMBtu for 2002. Based upon data from the New York Mercantile Exchange (NYMEX) as of December 28, 2004, the calendar year 2005 forward natural gas price at Henry Hub was $6.34 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). The increase in natural gas prices was a positive factor for low-cost merchant coal facilities in markets dominated by gas-fired plants and somewhat positive for coal facilities in those markets more dependent on low-cost coal and nuclear facilities. These conditions adversely affected certain of the Illinois Plants, specifically the Collins Station and small peaking units. A description of these market forces and the risks associated with them is included under "Market Risk Exposures."

Expansion of PJM in Illinois

       The Illinois Plants are located within the service territory of Exelon Generation's affiliate, Commonwealth Edison Company (Commonwealth Edison), which on April 27, 2004 was granted approval by the Federal Energy Regulatory Commission (FERC) to join PJM Interconnection, LLC (PJM) effective May 1, 2004. On October 1, 2004, American Electric Power (AEP) was also integrated into PJM. As a result, as of October 1, 2004, Midwest Generation has direct access to a fully interconnected market that covers twelve states and the District of Columbia, and serves a peak load of over 107,000 MW over 49,300 miles of transmission lines. For further discussion, see "Item 1. Business—Regulatory Matters."

Overview of EME's 2004 Financial Performance from Continuing Operations

       EME's financial performance from continuing operations in 2004 and 2003 included a number of important items:

•

The second quarter of 2004 included a $954 million (pre-tax) loss on termination of the lease related to the Collins Station and the return of its ownership to EME and related inventory reserves. Management concluded that the Collins Station was not economically competitive in the current marketplace given the current generation overcapacity in the region and ceased operations effective September 30, 2004. EME recorded a $7 million (pre-tax) loss in the third quarter of 2004 related to the impairment of the Collins Station plant assets and related inventory reserves. By the fourth quarter of 2004, the Collins Station was decommissioned and all units were permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered.

•

The third quarter of 2004 included a charge of $29 million (pre-tax) related to the impairment of six small peaking units in Illinois. In September 2004, management completed an analysis of future competitiveness in the expanded PJM marketplace of its eight small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight units. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less than the book value of the units resulting in an impairment. The 2003 results include a $245 million (pre-tax) loss related to the impairment of these small peaking units. By the fourth quarter of 2004, planning efforts were in progress to decommission the six peaking units.

•

The 2004 results include a pre-tax gain of $47 million from the sale of the company owning EME's interests in Four Star Oil & Gas Company, partially offset by a $4 million loss on the sale of the company holding EME's interest in the Brooklyn Navy Yard project.

•

The 2003 results include a $53 million (pre-tax) loss related to the write-down of EME's investment in the Brooklyn Navy Yard project due to its planned disposition.

31

•

The 2003 results include a $6 million (pre-tax) loss related to the write-down of EME's investment in the Gordonsville project, which was sold in the fourth quarter of 2003.

       Excluding these items, EME's 2004 income from continuing operations was $13 million compared to $91 million during 2003. Key items affecting EME's operating performance included:

•

A reduction in earnings from the Homer City facilities due in part to:

•

lower generation and availability factor for the Homer City facilities in 2004 as compared to 2003. Planned and unplanned outages were higher during 2004 as compared to 2003, including the unplanned outage related to Unit 1 in the first quarter of 2004;

•

increased fuel costs from higher priced sulfur dioxide (SO2) emission allowances and higher maintenance costs related to the outages discussed above; and

•

temporary fuel supply interruptions during the third quarter of 2004 which were managed through a reduction of off-peak generation and spot purchases of higher priced coal.

•

A decrease in earnings from the Illinois Plants due in large part to:

•

a $56 million (pre-tax) charge recorded during the fourth quarter of 2004 related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999. For further discussion, see "Indemnities Provided as Part of the Acquisition of the Illinois Plants" in "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies;" and

•

higher interest expense from new indebtedness incurred in 2004 compared to 2003.

       Partially offset by:

•

lower plant operating lease costs due to the termination of the Collins Station lease in April 2004;

•

lower fuel costs from the sale of excess SO2 emission allowances resulting from higher market prices; and

•

higher energy revenues in 2004 from increased merchant generation at higher prices offsetting the lower capacity payments received under the power purchase agreements with Exelon Generation as a result of Exelon Generation's prior year election to reduce the number of units under contract; energy revenues increased $98 million and capacity revenues decreased $91 million during 2004 compared to 2003.

Management Focus

       Management's focus in 2005 is on the following key items:

•

Transition to Primarily Domestic Operations — With the sale of EME's international operations, management intends to complete a review of its organization and operations and ensure that resources are effectively and efficiently aligned with business requirements.

•

Asset Optimization — With the Illinois Plants and the Homer City facilities being the largest portion of EME's domestic operations, efforts will continue from 2004 to ensure that gross margin from these plants is optimized.

•

Risk Management — Management's goal is to reduce the volatility of its earnings and cash flow and, thus, improve the predictability of operating results. To do this, management is evaluating

32

strategies for a combination of short-term sales, longer-term bilateral contracts, and potential participation in utility auctions for basic generation services (sometimes called "BGS Auctions"). Implementation of these strategies would be undertaken through EME's marketing and trading subsidiary by entering into forward contracts to reduce market risk and enhance the predictability of revenues from the Illinois Plants and the Homer City facilities. Implementation of these strategies 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.

•

Liability Management — Management intends to focus on reducing EME's leverage by repaying debt at maturity and repurchasing existing debt where early retirement is considered beneficial, thereby increasing financial flexibility for future growth.

•

New Investments — With the greater financial stability resulting from the sale of EME's international operations, management intends to evaluate and make new investments where appropriate.

Dispositions of Investments in Other Energy Plants

       On January 7, 2004, EME completed the sale of 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, to Medicine Bow Energy Corporation. Proceeds from the sale were approximately $100 million. EME recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

       On March 31, 2004, EME completed the sale of 100% of its stock of Mission Energy New York, Inc., which in turn owned a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., to a third party for a sales price of 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 and a pre-tax loss of approximately $4 million during the first quarter of 2004 due to changes in the terms of the sale.

Risks Related to the Business

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. The senior secured notes 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 would result in a change in control of EME which could have a material adverse effect on EME. See "Item 1. Business—EME's Relationship With Certain Affiliated Companies—MEHC." Dividends from EME are limited based on its earnings and cash flow, the terms of restrictions contained in EME's corporate credit facility, business and tax considerations and restrictions imposed by applicable law. For a discussion of contractual restrictions that could constrain the ability of EME's subsidiaries to pay dividends or distributions to EME, see "Liquidity and Capital Resources—Dividend Restrictions in Major Financings."

       If MEHC 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

33

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 agreement to which MEHC is a party may be terminated by the immediate parent company of MEHC 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 did not participate in the tax-allocation agreement, it would not be entitled to receive tax-allocation payments if payments were due under the agreement. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement."

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 PJM are:

•

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

•

the cost of emission credits or allowances;

•

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

•

transmission congestion in and to PJM which could limit the prices at which uncontracted energy can be sold;

•

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

•

weather conditions prevailing in PJM from time to time; and

•

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 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. 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

34

location, zoning, land use and operation of a project. For more information, see "Item 1. Business—Regulatory Matters."

       There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on EME's 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.

       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 potential role in climate change. The adoption of laws and regulations to implement carbon dioxide controls could adversely affect EME's coal-fired plants. 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 emission allowances or make some units uneconomical to maintain or operate. In addition, EME has an equity interest in and operates an electric generating plant in Turkey, which plant could be impacted by greenhouse gas emission reduction requirements under the Kyoto Protocol if Turkey ratifies the Protocol. 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."

35

The ability of EME's largest subsidiary, Midwest Generation, LLC, to make distributions is restricted.

       Midwest Generation, which owns or leases the Illinois Plants, has entered into financing documents that contain restrictions on its ability to pay dividends. 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 regardless of whether or not Midwest Generation makes distributions to EME. If EME were not able to satisfy its obligations under the intercompany notes, it would result in a default under the financing documents of EME and Midwest Generation. This could have a material adverse effect on the results of operations and cash flow of EME.

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

       As of December 31, 2004, consolidated debt of EME was $3.7 billion. In addition, EME's subsidiaries have $5.0 billion of long-term lease obligations that are due over a period ranging up to 30 years. 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.

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 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 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 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.

36

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

       The operation of power generation facilities involves many operating and market risks, including:

•

performance below expected levels of output or efficiency;

•

changes in the cost or availability of fuel, emissions credits or allowances, transmission, insurance, supplies or raw materials;

•

interruptions in fuel supply;

•

disruptions in the transmission of electricity;

•

breakdown or failure of equipment or processes;

•

imposition of new regulatory requirements;

•

employee work force factors, including strikes, work stoppages or labor disputes;

•

violation of permit requirements; and

•

operator error or catastrophic events such as terrorist activities, fires, tornadoes, explosions, floods or other similar occurrences affecting power generation facilities.

       There is no assurance that the occurrence of one or more of the events listed above would not significantly decrease or eliminate revenues generated by EME's projects or significantly increase the costs of operating them. Equipment and plant warranties and insurance may not be adequate to cover lost revenues or increased expenses. A decrease or elimination in revenues generated by the facilities or an increase in the costs of operating them could decrease or eliminate funds available to meet EME's obligations as they become due and could have a material adverse effect on EME. A default under a financing obligation of a project entity could result in a loss of EME's interest in the project.

Critical Accounting 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.

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.

37

       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 include 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, credit 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 of 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 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 2004 and 2003, EME recorded impairment charges of $35 million and $304 million, respectively, related to specific assets included in continuing

38

operations. See "Results of Continuing Operations—Earnings from Consolidated Operations—Illinois Plants" and "Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Asset Impairment Charges."

Off-Balance Sheet Financing

       EME has entered into sale-leaseback transactions related to the Powerton and Joliet plants in Illinois and the Homer City facilities in Pennsylvania. See "Liquidity and Capital Resources—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. The sale-leaseback transactions of these power plants were complex matters that involved management judgment to determine compliance with 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."

Pensions and Other Postretirement Benefits

       Pension and other postretirement obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are important elements of plan expense and liability measurement. Additionally, health care cost trend rates are critical assumptions for postretirement health care plans. These critical assumptions are evaluated at least annually. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

       The discount rate enables EME to state expected future cash flows at a present value on the measurement date. At the December 31, 2004 measurement date, EME used discount rates of 5.5% for pensions and 5.75% for postretirement benefits other than pensions (PBOP) that represented the market interest rate for high-quality fixed income investments.

       To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. The expected rate of return on plan assets was 7.5% for pensions. Actual returns on the pension plan assets were 12.2%, 5.0% and 11.9% for the one-year, five-year and ten-year periods ended December 31, 2004, respectively.

39

Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.

       At December 31, 2004, EME's pension plans had a $153 million projected benefit obligation (PBO), a $123 million accumulated benefit obligation (ABO) and $77 million in plan assets. A 1% decrease in the discount rate would increase the PBO by $14 million, and a 1% increase would decrease the PBO by $13 million, with corresponding changes in the ABO. A 1% decrease in the expected rate of return on plan assets would increase pension expense by $1 million.

       Annually, EME reviews all pension plans to determine if the ABO exceeds the fair value of the plan's assets. If the ABO exceeds the fair value of the plan assets, EME records an additional minimum pension liability, with a corresponding charge to other comprehensive income. EME may incur additional minimum pension liabilities in future periods.

       At December 31, 2004, EME's PBOP plans had a $58 million PBO. Total expense for these plans was $4 million for 2004. Increasing the health care cost trend rate by 1% would increase the accumulated obligation as of December 31, 2004 by $11 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost trend rate by 1% would decrease the accumulated obligation as of December 31, 2004 by $9 million and annual aggregate service and interest costs by $1 million.

       See "Results of Operations—New Accounting Pronouncements" for information on the effects of FASB Staff Position 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003."

Asset Dispositions and Contract Indemnities

       During 2004, EME completed the sale of the majority of its international operations and recorded a gain on sale. Computing the after-tax gain on sale involved a number of critical accounting estimates requiring management's judgment, including determining the fair value of contract indemnities and income taxes under new regulations as described below:

•

The asset sale agreements contain indemnities from EME to the purchasers, including indemnification for pre-closing environmental liabilities and for pre-closing foreign taxes imposed with respect to operations of the assets prior to the sale. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. Under Financial Accounting Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," EME recorded the fair value of the contract indemnities as a liability.

•

Prior to completion of the sale of the international projects, EME paid a dividend from its Dutch holding company. On October 22, 2004, The American Jobs Creation Act of 2004 was enacted which, among other things, included a provision to exclude from Federal income taxes 85% of dividends repatriated from foreign subsidiaries for permitted purposes. While announced by the Internal Revenue Service, its detailed guidance on how these provisions will be interpreted has not yet been issued.

       At December 31, 2004, EME recorded a liability of $158 million related to the above matters which was included in determining the gain on sale of the international projects.

       In addition to the foregoing items related to asset sales, Midwest Generation has agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses

40

less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in a supplemental agreement (see "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Commercial Commitments"). Midwest Generation engaged an independent actuary with extensive experience in performing asbestos studies to estimate future losses based on the claims experience and other information available. In calculating future losses, the actuary made various assumptions, including, but not limited to, the settlement of future claims under the supplemental agreement with Commonwealth Edison as described above, the distribution of exposure sites, and that the filing date of asbestos claims will not be after 2045. At December 31, 2004, Midwest Generation had $69 million recorded as a liability related to this contract indemnity.

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 12 to the "Mission Energy Holding Company 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.

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

41

RESULTS OF OPERATIONS

Introduction

       This section discusses operating results in 2004, 2003 and 2002. In 2004, all of EME's international operations are accounted for as discontinued operations. Continuing operations include EME's Illinois Plants and Homer City facilities, equity investments in power projects primarily located in California, corporate interest expense and general and administrative expenses. This section also discusses the effect of new accounting pronouncements on EME's consolidated financial statements. It is organized under the following headings:

Net Income Summary

       Net income (loss) is comprised of the following components:

       MEHC's loss from continuing operations in 2004 was $98 million compared to $99 million in 2003 and $93 million in 2002. There was no significant change in loss from continuing operations in 2004 from 2003. The 2003 increase in loss from continuing operations was primarily due to lower interest income and higher consulting fees in 2003.

       EME's 2003 loss from a change in accounting principle resulted from the adoption of a new accounting standard for asset retirement obligations. EME's 2002 loss from a change in accounting principle results from the adoption of a new accounting standard for goodwill. See "Results of Continuing Operations—Cumulative Effect of Change in Accounting Principle" for further discussion of these changes in accounting.

42

       EME's income (loss) from continuing operations for the three years ended December 31, 2004 is comprised of:

       EME's income from continuing operations, excluding discrete items, in 2004 was $13 million compared to $91 million in 2003 and $53 million in 2002. The 2004 decrease was primarily attributable to lower earnings due to the absence of earnings from Four Star Oil & Gas during 2004 (sold on January 7, 2004), lower earnings from EME's Homer City facilities due to lower generation and higher fuel costs related to emission allowances and lower earnings from EME's Illinois Plants primarily due to a $56 million charge related to a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois plants prior to their acquisition in 1999.

       The 2003 increase in income from continuing operations, excluding discrete items, was primarily attributable to higher earnings from EME's Homer City facilities due to higher energy prices, improved profitability of EME's interest in Four Star Oil & Gas and the Big 4 projects due to higher natural gas prices, and the start of operations at Phase 2 of the Sunrise project in June 2003. Partially offsetting these items were lower capacity revenues at EME's Illinois Plants.

Results of Continuing Operations

Overview

       EME operates in one line of business, electric power generation. Operating revenues are primarily related to the sale of power generated from the Illinois Plants and Homer City facilities. Intercompany

43

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 accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

       MEHC uses the words "earnings" or "losses" in this section to describe EME's income or loss from continuing operations before income taxes.

       The following section provides a summary of the operating results for the three years ended December 31, 2004 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

(1)

Income before taxes of Doga represents both EME's 80% ownership and the ownership of minority interest holders on a calendar year basis. The interests of minority shareholders in the after-tax earnings of Doga are reflected in a separate line item in the consolidated statements of income.

44

Earnings from Consolidated Operations

Illinois Plants

(1)

The Illinois Plants sold excess SO2 emission allowances to the Homer City facilities at fair market value. Sales were $26 million in 2004, $10 million in 2003 and $5 million in 2002. These sales reduced fuel costs.

(2)

This table summarizes key performance measures related to coal-fired generation, which represents the majority of the operations of the Illinois Plants.

(3)

In 2003 and 2004, equivalent availability was reported on an operating basis as certain units became merchant.

45

(4)

In 2002, all units were under contract and equivalent availabilities shown are as calculated under the contract. Certain forced outages are considered non-curtailing or "excused" under the power purchase agreement if they occur during low demand periods. As such, these equivalent availabilities can be 1% to 4% higher than the actual equivalent availabilities calculated under an operating basis.

(5)

The availability factor is determined by the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. Equivalent availability captures the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shut down. The coal plants are not available during periods of planned and unplanned maintenance.

(6)

Midwest Generation generally refers to unplanned maintenance as a forced outage.

       Losses from the Illinois Plants increased $769 million in 2004 compared to 2003, and decreased $344 million in 2003 compared to 2002. Discrete items affecting the income (loss) of the Illinois Plants include:

•

$961 million loss recorded in 2004 related to the termination of the Collins Station lease and the return of ownership of the Collins Station to EME, and the impairment of plant assets and related inventory reserves. Management concluded that the Collins Station was not economically competitive in the marketplace given generation overcapacity and ceased operations effective September 30, 2004.

•

$29 million loss recorded in 2004 related to the impairment of six of the eight small peaking units in Illinois. In September 2004, management completed an analysis of future competitiveness of its eight small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight units. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less than the book value of the units, resulting in an impairment charge under SFAS No. 144.

•

$245 million loss recorded in 2003 related to the impairment of all eight of the small peaking units in Illinois that resulted from a revised long-term outlook for capacity revenues from the peaking units. The lower capacity revenue outlook was the result of a number of factors, including higher long-term natural gas prices and generation overcapacity.

•

$45 million charge in 2002 related to the settlement agreement with Commonwealth Edison that terminated the obligation to build 500 MW of additional gas-fired generation.

•

$25 million charge in 2002 related to the write-off of capitalized costs associated with the suspension of the Powerton Station SCR major capital improvement project.

•

$71 million gain in 2002 from settlement of postretirement employee benefit liability related to a retirement health care and other benefits plan for union-represented employees at the Illinois Plants that expired on June 15, 2002.

       Earnings from the Illinois Plants, excluding the above discrete items, decreased $24 million in 2004 compared to 2003, and $98 million in 2003 compared to 2002. The 2004 decrease in earnings is due to the following factors:

•

a $56 million charge related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999 (for further discussion, see "Indemnities Provided as Part of the Acquisition of the Illinois Plants" in "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies"); and

•

higher interest expense from new indebtedness incurred in 2004 compared to 2003.

46

       Partially offset by:

•

lower plant operating lease costs due to the termination of the Collins Station lease in April 2004;

•

lower fuel costs resulting from the sale of excess SO2 emission allowances at higher market prices; and

•

higher energy revenues in 2004 from increased merchant generation at higher prices which offset the lower capacity payments received under the power purchase agreements with Exelon Generation. Accordingly, energy revenues increased $98 million and capacity revenues decreased $91 million during 2004 compared to 2003.

       The 2003 decrease in earnings is primarily due to an approximately $221 million decrease in capacity revenue resulting from the reduction in megawatts contracted under the power purchase agreements with Exelon Generation, partially offset by an approximately $126 million increase in energy revenue due to the shift to merchant generation. The merchant generation currently earns minimal capacity revenues but earns higher energy revenues due to higher average realized energy prices as compared to the energy prices set forth in the power purchase agreements previously in effect.

       During 2003 and 2004, the Illinois Plants had one unit at the Collins Station available for sale into the wholesale power market. Due to the substantial increase in natural gas prices in 2003 and 2004, the marginal cost of generation generally exceeded the spot price for energy. As a result, merchant sales from the Collins Station were minimal during 2003 and 2004. In addition, the Illinois Plants permanently ceased operations at all units at the Collins Station on September 30, 2004 after termination of the lease.

       Losses from price risk management were $4 million, $3 million and $1 million in 2004, 2003 and 2002, respectively. The 2004 losses primarily related to power contracts that did not qualify for hedge accounting under SFAS No. 133. The 2003 losses primarily reflect a mark-to-market adjustment for $3 million related to an option in which Midwest Generation had to purchase energy from Calumet Energy Team LLC, which is accounted for as a derivative under SFAS No. 133. The 2002 losses were primarily due to the realized loss recognized on futures contracts that expired in August 2002 that did not qualify for hedge accounting under SFAS No. 133.

       The earnings (losses) of the Illinois Plants included interest income of $113 million, $113 million and $119 million in 2004, 2003 and 2002, respectively, related to loans to EME. In August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes. See "Management's Overview, Risks Related to the Business and Critical Accounting Estimates—Critical Accounting Estimates—Off-Balance Sheet Financing" for further discussion of these leases.

47

Homer City

(1)

The Homer City facilities purchased SO2 emission allowances from the Illinois Plants at fair market value. Purchases were $26 million in 2004, $10 million in 2003 and $5 million in 2002. These purchases are included in fuel costs.

(2)

The availability factor is determined by the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. The coal plants are not available during periods of planned and unplanned maintenance.

(3)

Homer City generally refers to unplanned maintenance as a forced outage.

       Earnings from Homer City decreased $60 million in 2004 compared to 2003 and increased $100 million in 2003 compared to 2002. The 2004 decrease in earnings is primarily due to increased losses related to price risk management activities and an increase in fuel costs from higher priced SO2 emission allowances (these factors are discussed further below). Homer City also had lower energy revenues in 2004 due to lower generation and availability, which was mostly offset by increased average realized energy prices. During the first quarter of 2004, an unplanned outage at Unit 1 contributed to lower generation and higher maintenance costs. During the third quarter of 2004, coal deliveries under contracts with four fuel suppliers to Homer City were temporarily interrupted. As a result of these interruptions, Homer City reduced generation during off-peak periods when power prices were lower and

48

purchased coal from alternative suppliers at spot prices which were substantially higher than the contract prices from these four fuel suppliers. See "—Contractual Obligations, Commitments and Contingencies—Contractual Obligations—Fuel Supply Dispute" for more information regarding the fuel supply interruptions and the dispute with two of the suppliers.

       The price of emission allowances, particularly SO2 allowances issued through the Acid Rain Program of the United States Environmental Protection Agency, also increased substantially in 2004. The average cost of SO2 allowances increased from $170 per ton during 2003 to $436 per ton in 2004. The market for SO2 allowances also experienced increased volatility, with prices ranging from $220 to $740 per ton (in contrast to a range of $100 to $220 between 1998 and 2003). These developments have been attributed to reduced numbers of both allowance sellers and prior vintage allowances. The total cost to purchase SO2 emission allowances during 2004 increased to $43 million from $15 million in 2003.

       The 2003 increase in earnings is due to increased generation and higher energy prices. The increase in generation primarily resulted from an unplanned outage on Unit 3 and extended outages on Units 1 and 2 during the first half of 2002. On February 10, 2002, Homer City experienced a major unplanned outage due to a collapse of the SCR ductwork of one of the units, known as Unit 3. The unit was restored to operation on April 4, 2002 and operated with the SCR bypassed until June 19, 2003, when it was returned to service. As a result of the Unit 3 ductwork collapse, EME reviewed the similar structures on Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002 and Unit 2 returned to service on June 26, 2002.