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, 2002

Commission File Number 333-68632

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

Registrant's telephone number, including area code: (949) 852-3576

        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 Act). YES o NO ý

        Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 28, 2002: $0. Number of shares outstanding of the registrant's Common Stock as of March 27, 2003: 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

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 the $385 million term loan due 2006, 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 The Mission Group, which is a wholly owned subsidiary of Edison International. MEHC was formed to:

•

hold the common stock of EME;



•

incur the indebtedness under the senior secured notes and the term loan; and



•

use a portion of the proceeds from the senior secured notes and the term loan to pay a dividend to The Mission Group which in turn loaned the funds to Edison International to retire a portion of their debt obligations.

        On July 2, 2001, The Mission Group 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, the term loan 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. At December 31, 2002, MEHC had consolidated assets of $11.4 billion and total shareholder's equity of $736 million.

        As of December 31, 2002, consolidated debt of MEHC was $7.2 billion, including $911 million of debt maturing in December 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings Co. The $911 million of debt of Edison Mission Midwest Holdings maturing in December 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that it will be able to extend or refinance this debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in July 2001 or at all. MEHC's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements included in Part II of this annual report have been prepared on the basis that MEHC will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources—Risk Factors."

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.

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, are:

•

the ability of EME to declare and pay dividends;



•

EME's and its subsidiaries' ability to refinance debt, including $911 million of debt maturing in December 2003, or raise additional financing for their future cash requirements;



•

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



•

supply and demand for electric capacity and energy in the markets served by EME's generating units and the resultant prices and dispatch volumes;



•

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



•

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



•

political and business risks of international projects, including uncertainties associated with currency exchange rates, currency repatriation, expropriation, political instability, privatization efforts and other issues;



•

competition from other power plants, including new plants and technologies that may be developed in the future;



•

operating risks, including equipment failure, availability, heat rate and output;



•

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



•

the cost, availability and pricing of transmission services;



•

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



•

MEHC's and its subsidiaries' continued participation in the tax-allocation and payment agreements.

        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 Results of Operations and Financial Condition that appear in Part II of this annual report. Readers are urged to read this entire annual report, including the

2

information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect MEHC's business. The information contained in this 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 Business

Electric Power Industry

        Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. The Public Utility Regulatory Policies Act encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers, known as qualifying facilities, under certain conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent power producers, such as EME, developed in the United States. Beginning in the mid-1990s, industry restructuring and opening of retail markets to competition in several states led some utilities to divest generating assets, which created new opportunities for growth of independent power in the United States. In those jurisdictions that have deregulated retail markets, industry trends and regulatory initiatives resulted in a new set of market relationships in which independent generators and marketers compete with incumbent distribution utilities for sales to end-users, on the basis of price, reliability and other factors. As a result of the 2000-2001 California power crisis and related volatility in wholesale markets, some states have either discontinued or delayed implementation of initiatives involving deregulation and some utilities have delayed or cancelled plans to divest their generating assets. These developments have generally not affected the progress of industry restructuring in Illinois and Pennsylvania, where many of EME's power plants are located. However, as discussed further below, competition, regulatory uncertainty and lower wholesale energy prices have adversely affected independent power producers, including several of EME's subsidiaries. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Current Developments."

        The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity has also led to the development of significant new markets for independent power producers outside the United States. EME has developed or acquired power plants in the Asia Pacific region and in the Europe region as a result of these developments. However, as discussed below, the recent volatility in global energy markets has introduced considerable uncertainty as to the future rates of growth in the global independent power producers sector.

Competition and Market Condition Generally

        EME and its subsidiaries are subject to intense competition in the United States and overseas from energy marketers, utilities, industrial companies and other independent power producers. Over the past several years, the restructuring of energy markets has led to the sale of utility-owned assets to EME and its competitors. More recently, in response to market conditions, EME has changed its focus from acquisition and growth to operating, maintaining, and maximizing the value of its current asset base. Accordingly, EME has engaged in asset sales, has canceled or deferred new development, and has taken a number of actions to decrease capital expenditures, including cancellations of orders for new turbines, reductions in operating costs, and suspension of operations at several power plants. This trend reflects lower prices for electric generating capacity in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, and the decline of liquidity in the energy markets as a result of credit concerns.

3

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

        Amendments to the Public Utility Holding Company Act of 1935 made by the Energy Policy Act have increased the number of competitors in the domestic independent power industry by reducing restrictions applicable to projects that are not qualifying facilities under the Public Utility Regulatory Policies Act. The introduction of a new standard market design structure mandated by the Federal Energy Regulatory Commission in those regions not currently organized into centralized power markets and the continued expansion by utilities of unbundled retail distribution services could also lead to increased competition in the independent power market. See "—Regulatory Matters—Retail Competition."

Segment Information

        EME operates predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific and Europe. EME's plants are located in different geographic areas, which mitigates somewhat the effects of regional markets, regional economic downturns or unusual weather conditions. These regions take advantage of the increasing globalization of the independent power market. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 20. Business Segments."

4

Regional Overview of Business Segments

        As of December 31, 2002, EME had 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:

(3)

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

5

        As of December 31, 2002, EME had ownership or leasehold interests in the following international 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:

(3)

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

(4)

Minority interest in three power plants.

(5)

Minority interest in one power plant.

(6)

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

Americas

        As of December 31, 2002, EME had 28 operating power plants in this region, all of which are presently located in the United States and its territories. EME's Americas region is headquartered in Chicago, Illinois with additional offices located in Irvine, California, and Boston, Massachusetts. A description of EME's larger power plants and major investments in energy projects in the Americas region is set forth below.

6

Illinois Plants

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

        The Illinois Plants include the following:

(1)

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

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

Power Purchase Agreements

        On December 15, 1999, Midwest Generation entered into three separate five-year power purchase agreements with Commonwealth Edison that expire on December 31, 2004. In January 2001,

7

Commonwealth Edison assigned these agreements to Exelon Generation. Under these agreements, Midwest Generation has agreed to make the capacity of the power generation stations it purchased from Commonwealth Edison available to Exelon Generation. These agreements allow Midwest Generation to sell any excess electric energy, including energy not dispatched by Exelon Generation, to other purchasers under specified conditions. The power purchase agreements with Exelon Generation accounted for 41%, 43% and 49% of EME's consolidated operating revenues for 2002, 2001 and 2000, respectively. As discussed in detail below, Exelon Generation has released 4,548 MW of Midwest Generation's generating capacity from the power purchase agreements for 2003. 4,739 MW of Midwest Generation's generating capacity remains subject to power purchase agreements with Exelon Generation.

Coal-Fired Stations Power Purchase Agreement

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

        The agreement identifies the units that are contracted to Exelon Generation and for each contract year denominates them either as committed units or option units for that contract year. Committed units for each contract year remain subject to the agreement for that contract year, but Exelon Generation has the option to retain, subject to the agreement, all or part of the capacity of those units denominated as option units for a contract year. Any capacity of the option units which Exelon Generation does not elect to retain for a contract year is released from the terms of the agreement for that and subsequent contract years. The capacity of the committed units for both of 2003 and 2004 is 1,696 MW. For 2003, Exelon Generation has elected to retain 1,265 MW of the capacity of those units that were denominated as option units for that contract year. For contract year 2004, Exelon Generation has the option to terminate one or more option units by giving Midwest Generation notice of its exercise of its option by July 3, 2003.

        The following table lists the committed coal units, the option units for which Exelon Generation has exercised its call option for 2003 but which may be released for 2004, and the units which, as of January 1, 2003, were released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

8

Coal-Fired Units

(1)

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

(2)

Option units refer to those units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement. Exelon Generation continues to have a similar option related to these units for 2004.

(3)

Released units refer to those option units for which Exelon Generation has not exercised its right to purchase capacity and energy during 2003, and which are thus released from the terms of the power purchase agreement. Since January 1, 2003, the price for energy and capacity from these units has been based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

(4)

Operations currently suspended.

        The coal-fired units power purchase agreement sets forth different capacity charges for the summer months and the non-summer months. The capacity payments are based on the contracted amounts identified in the power purchase agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. If the group equivalent availability factor is higher than a specified threshold, then the adjustment factor calculation provides Midwest Generation with the opportunity to increase the normal monthly capacity payment, but if the group equivalent availability factor is lower than the minimum, then Midwest Generation is penalized by a loss in the monthly

9

capacity payment. The monthly capacity payment adjustment factor provides Midwest Generation with an incentive to maintain the individual units at high equivalent availabilities. The group equivalent availability factor required in the calculation for potentially achieving the full monthly capacity payment for the coal-fired units is 65% for the summer months and 55% for the non-summer months.

Collins Station Power Purchase Agreement

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

        Pursuant to the provisions of the agreement, Exelon Generation has elected to retain, for contract year 2003, 1,084 MW of capacity of the units at the Collins Station, thus releasing from the contract 1,614 MW of capacity. For contract year 2004, Exelon Generation has the option to terminate one or more option units by giving Midwest Generation notice of its exercise of its option by October 3, 2003.

10

        The following table lists the generating units at the Collins Station for which Exelon Generation has not exercised its option to terminate for 2003 but which may be released for 2004, and the generating units which, as of January 1, 2003, were, as a result of the exercise by Exelon Generation of its option to terminate, released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

Collins Station

(1)

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

(2)

Option units refer to those units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement. Exelon Generation continues to have a similar option related to these units for 2004.

(3)

Released units refer to those generating units for which Exelon Generation has exercised its right to terminate the power purchase agreement, and which are thus released from the terms of the power purchase agreement. Since January 1, 2003, the price for energy and capacity from these units has been based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

(4)

Operations currently suspended.

        The Collins Station power purchase agreement divides the capacity charges into summer months and non-summer months. The capacity payments are based on the contracted amounts identified in the agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. With respect to all electricity purchased under the agreement, Exelon Generation is obligated to pay: a monthly capacity charge for the reserved units which varies according to the time of year; a per megawatt-hour energy charge; various charges for start-up of the reserved units; low load charges that apply at any hour in which Exelon Generation schedules a reserved unit to operate at an output below a level specified in the agreement; and an annual settlement amount to the extent natural gas prices exceed a specified amount and Exelon Generation dispatches a minimum amount of electric energy.

Peaking Units Power Purchase Agreement

        Under the peaking units power purchase agreement, Exelon Generation purchases capacity and thus has the right to take from Midwest Generation electric energy generated by the peaking units. The

11

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

        Pursuant to the provisions of the agreement, Exelon Generation has elected to retain, for contract year 2003, 694 MW of capacity of the peaking units, thus releasing from the contract 250 MW of capacity. For contract year 2004, Exelon Generation has the option to terminate one or more option units by giving Midwest Generation notice of its exercise of its option by October 3, 2003.

        The following table shows the peaking units as to which Exelon Generation has not exercised its option to terminate for 2003 but which may be released for 2004, and the peaking units which were, as a result of the exercise by Exelon Generation of its option to terminate, released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

Peaking Units

(1)

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

(2)

Option units refer to those units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement. Exelon Generation continues to have a similar option related to these units for 2004.

(3)

Released units refer to those peaking units for which Exelon Generation has exercised its right to terminate the power purchase agreement, and which are thus released from the terms of the power purchase agreement. Since January 1, 2003 related to 113 MW and since January 1, 2002 related to 137 MW, the price for energy and capacity from these units has been based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

Illinois Power Markets

        For the past three years, Midwest Generation has derived substantially all of its revenue from the sale of energy and capacity to Exelon Generation under power purchase agreements. Midwest Generation's energy and capacity that are not purchased under power purchase agreements are generally sold at market prices to neighboring utilities, third-party electricity retailers and power marketers through a marketing affiliate.

        While an independent system operator does not yet oversee operations of the Commonwealth Edison control area, a number of other utilities in the region participate in the Midwest Independent System Operator, a Regional Transmission Organization authorized pursuant to FERC Order No. 2000, and a bilateral market is already present. The regional market is supported by open access transmission under various utility company transmission tariffs, the Midwest Independent System Operator Tariff, as well as retail access electricity tariffs currently available to end use customers in many states, including Illinois and Ohio. Open Access Transmission Tariffs and retail access tariffs allow companies which do

12

not own transmission and distribution systems to utilize the transmission and distribution systems of others to sell power at wholesale and retail on a non-discriminatory basis relative to the system owners. Such tariffs are vital to allow companies, such as Midwest Generation, which own or control generation but not transmission and distribution systems, to compete in the deregulated electricity markets. These documents provide a uniform set of standards that have been approved by regulatory agencies and are publicly available. Both Commonwealth Edison and American Electric Power are seeking to have their control areas placed under the operation of PJM Interconnection, LCC, which is commonly known as PJM, and, if they are successful, will be subject to the PJM Tariff and Market Rules. PJM is a prominent independent system operator providing system operations and market settlement throughout the Mid-Atlantic States. Consequently, Midwest Generation's plant operations and future power sales may conform to future PJM requirements. Some of Midwest Generation's coal units may have a portion of their revenue derived from forward sales to regional utilities and power marketers. The remainder of the available coal-fired generation output, together with available output from the Collins Station and the peaking units, may be sold on a spot basis.

        During 2003, the primary markets available to Midwest Generation for wholesale sales of electricity are expected to be "wholesale customer" and "over-the-counter." Wholesale customer transactions are bilateral sales for resale to regional buyers, including investor-owned utilities, municipal utilities, rural electric cooperatives and retail energy suppliers. Wholesale customer transactions include real-time, daily and longer term structured sales; they are not arranged through brokers and may be tailored to meet the specific requirements of wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include forward sales of electricity. The most liquid over-the-counter markets in the Midwest region are "Into Cinergy," and, to a lesser extent, "Into ComEd." Liquidity in the over-the-counter markets is lower than it has been in prior years as a consequence of the decision by many trading entities to discontinue operations and the financial problems of others resulting in far fewer creditworthy participants in these electricity markets.

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

        On December 11, 2002, Commonwealth Edison, American Electric Power and others filed with the Federal Energy Regulatory Commission seeking permission to include their transmission systems within the Regional Transmission Organization proposed by PJM. The effect of the filing would be to transfer functional control of such systems to PJM and to eliminate so-called rate pancaking for transmission and ancillary services over a region that would extend significantly beyond the current western boundaries of PJM and into electricity markets in the Midwest. Rate pancaking occurs when energy must move through multiple, separately priced transmission systems to travel from its point of production to its point of delivery, and each transmission owner along the line charges separately for the use of its system. The Federal Energy Regulatory Commission was requested by the parties to act on such filing by mid-February 2003. However, such action has now been delayed by the unanticipated

13

enactment of emergency legislation by the Virginia legislature that purports to prevent any Virginia utility (including American Electric Power's subsidiary, Appalachian Power Company) from transferring control of its transmission assets to PJM until July 2004. The effect of such enactment is to create uncertainty regarding the timing, and possibly the ultimate feasibility, of American Electric Power's and Commonwealth Edison's moving forward with their applications to place their transmission systems under the control of PJM. On March 14, 2003, the states of Pennsylvania, Ohio and Michigan filed a motion with the Federal Energy Regulatory Commission seeking an order granting immediate approval of the pending applications of Commonwealth Edison and American Electric Power to join PJM, or in the alternative for temporary control of such parties' transmission assets by PJM. On March 17, 2003, Commonwealth Edison filed a motion requesting immediate approval of such applications, and opposing any temporary measures of the sort suggested by Pennsylvania, Ohio and Michigan. The outcome of such efforts is uncertain.

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

Homer City Facilities

        On March 18, 1999, EME completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to acquire the 1,884 MW Homer City Electric Generating Station. These facilities consist of three coal-fired boilers and steam turbine-generator units, one coal preparation facility, an 1,800-acre site and associated support facilities in the mid-Atlantic region of the United States and have direct, high voltage interconnections to both PJM and the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly known as the NYISO. For a discussion of the risks related to the sale of electricity from the Homer City facilities, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—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 Results of Operations and Financial Condition—Off-Balance Sheet Transactions."

Major Investments in California Cogeneration Plants

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

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

        Midway-Sunset Cogeneration Plant—EME owns a 50% partnership interest in Midway Sunset Cogeneration Company, which owns a 225 MW natural gas-fired cogeneration facility located near Taft,

14

California, which EME refers to as the Midway-Sunset project. Midway-Sunset sells electricity to Southern California Edison, Aera Energy LLC and Pacific Gas & Electric Company under power purchase agreements that expire in 2009 and sells steam to Aera under a steam supply agreement that also expires in 2009.

        Sycamore 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 Texaco Exploration and Production Inc. under a steam supply agreement that also expires in 2007.

        Watson Cogeneration Plant—EME owns a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural gas-fired cogeneration facility located in Carson, California, which EME refers to as the Watson project. Watson Cogeneration sells electricity to Southern California Edison and to the adjacent BP refinery under power purchase agreements that expire in 2008 and sells steam to ARCO Products Company under a steam supply agreement that also expires in 2008. From January 2000 through December 2002, Watson Cogeneration sold electricity to CPC Cogeneration LLC, which in turn sold electricity to the BP refinery. EME owned a 49% interest in CPC Cogeneration. CPC Cogeneration was dissolved in December 2002 and its contract with the BP refinery was assigned back to Watson Cogeneration.

Other Americas Power Plants

        Sunrise Power Plant—EME owns a 50% interest in Sunrise Power Company, LLC, which owns a natural gas-fired facility currently under construction in Kern County, California, which EME refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001. Phase 2, conversion to a combined-cycle gas-fired facility (bringing the capacity to a total of 560 MW), is currently scheduled to be completed in July 2003. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. For further discussion related to this agreement, see "Item 3. Legal Proceedings—Regulatory Developments Affecting Sunrise Power Company."

        Brooklyn Navy Yard Cogeneration Plant—EME owns a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York, which EME refers to as the Brooklyn Navy Yard project. Brooklyn Navy Yard sells electricity and steam to Consolidated Edison Company of New York, Inc. under a power purchase agreement that expires in 2039.

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

        EcoEléctrica Power Plant—EME owns a 50% partnership interest in EcoEléctrica L.P., which owns a 540 MW power plant located Peñuelas, Puerto Rico, which EME refers to as the EcoEléctrica project. EcoEléctrica sells electricity to Puerto Rico Electric Power Authority under a power purchase agreement that expires in 2022 and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2022. See "Item 3. Legal Proceedings—EcoEléctrica Potential Environmental Proceeding" for more information regarding environmental matters.

15

Other Small Investments in Energy Projects

        EME also owns 50% investments in seven other small energy projects (less than 200 MW of net electric capacity) that are located in the United States. Each project sells electricity under a long-term power purchase agreement with the local electric utility.

Investment in Four Star Oil & Gas Company

        EME owns a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of ChevronTexaco Corp. Four Star Oil & Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. Under a long-term service contract, the majority of Four Star Oil & Gas's properties are operated through ChevronTexaco Exploration & Production Inc. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 8. Investments in Unconsolidated Affiliates" for financial information on EME's oil and gas investments.

Asia Pacific

        As of December 31, 2002, EME had 17 operating power plants in this region that are located in Australia, Indonesia, the Philippines, Thailand and New Zealand. EME's Asia Pacific region is headquartered in Singapore, with an additional office located in Australia. A description of EME's power plants, its investment in Contact Energy and investments in energy projects in the Asia Pacific region is set forth below.

Australia

        Loy Yang B Power Plant—EME owns a 1,000 MW coal-fired power station located in Traralgon, Victoria, Australia, which EME refers to as the Loy Yang B project. The project sells electricity to a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a system marginal price each half-hour. EME has entered into an agreement with the State Electricity Commission of Victoria, which agreement EME refers to as the State Hedge, that provides through October 31, 2016 for the project to receive a fixed price for a portion of its electricity in exchange for payment to the State of the system marginal price applicable to such portion. For further discussion of risks related to the sale of electricity from the Loy Yang B project, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

        Valley Power Peaker Power Plant—During 2002, EME completed construction of a 300 MW gas-fired peaker plant located adjacent to the Loy Yang B coal-fired power plant site, which EME refers to as the Valley Power Peaker project. The peaker units service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with a variety of generation and retail businesses. EME owns a 60% interest in the Valley Power Peaker project, with the remaining interest held by its 51.2%-owned affiliate, Contact Energy Limited.

        Kwinana Cogeneration Plant—EME owns a 70% interest in a 116 MW gas-fired cogeneration plant in Perth, Australia, which EME refers to as the Kwinana project. EME sells electricity to Western Power under a power purchase agreement that expires in 2021 and sells steam to the British Petroleum Kwinana refinery under a steam supply agreement which also expires in 2021.

16

New Zealand

        Contact Energy—EME owns a 51.2% majority interest in Contact Energy Limited. The remaining shares of Contact Energy are publicly held and traded on the New Zealand stock exchange. Contact Energy is the largest wholesaler and retailer of natural gas in New Zealand and generates about one-quarter of New Zealand's electricity. For further discussion of risks related to the sale of electricity from Contact Energy, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures." Contact Energy owns the following power plants:

(1)

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

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

Indonesia

        The Paiton Power Plant—EME owns a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia, which EME refers to as the Paiton project. Paiton Energy sells electricity to PT PLN, the state-owned electric utility company, under a power purchase agreement. On December 23, 2002, an amendment to the original power purchase agreement became effective, bringing to a close and resolving a series of disputes between Paiton Energy and PT PLN which began in 1999 and were caused, in large part, by the effects of the regional financial crisis in Asia and Indonesia. The amended power purchase agreement includes changes in the price for power and energy charged under the power purchase agreement, provides for payment over time of amounts unpaid prior to January 2002 and extends the expiration date of the power purchase agreement from 2029 to 2040. These terms have been in effect since January 2002 under a previously agreed Binding Term Sheet which was replaced by the power purchase agreement amendment. For a further discussion of the Paiton project and the restructuring of its financing arrangements, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Contingencies."

Philippines

        CBK Power Plants—In February 2001, EME purchased a 50% interest in CBK Power Co. Ltd. CBK Power has entered into a 25-year build-rehabilitate-operate-transfer agreement with National Power Corporation related to the 760 MW Caliraya-Botocan-Kalayaan hydroelectric project located in the Philippines, which EME refers to as the CBK project. CBK Power is paid capital recovery fees and

17

operations and maintenance fees for generating electricity and providing other services under the agreement. At December 31, 2002, 385 MW had been commissioned and were operational.

Thailand

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

Europe

        As of December 31, 2002, EME had 36 operating power plants in this region that are located in the U.K., Turkey, Spain and Italy. EME's Europe region is headquartered in London, England, with additional offices located in Italy and Spain. The London office was established in 1989. A description of EME's power plants and investments in energy projects in the Europe region is set forth below.

United Kingdom

        First Hydro Power Plants—EME's wholly owned subsidiary, First Hydro, owns two pumped storage stations in North Wales at Dinorwig and Ffestiniog which have a combined capacity of 2,088 MW, which EME refers to as the First Hydro project. Pumped storage stations consume electricity when it is comparatively less expensive in order to pump water for storage in an upper reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is higher. First Hydro sells electricity to electricity suppliers, other generators and into short-term markets. Additionally, it sells ancillary services to the system operator. For further discussion of issues related to the First Hydro project, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures" and "—Historical Distributions Received by Edison Mission Energy," as well as "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Financial Instruments."

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

Italy

        ISAB Power Plant—EME owns a 49% interest in ISAB Energy S.r.l. which owns a 518 MW integrated gasification combined cycle power plant in Sicily, Italy, which EME refers to as the ISAB project. ISAB sells electricity to Gestore Rete Transmissione Nazionale, Italy's state transmission company, under a power purchase agreement that expires in 2020. The ISAB project is located by an oil refinery owned by ERG Petroli SpA.

        Italian Wind Power Plants—In 2000, EME's wholly owned subsidiary, Edison Mission Wind Power Italy B.V., acquired a 50% interest in 13 power projects that are in operation in Italy by UPC International Partnership CV II, which EME collectively refers to as the Italian Wind project. The projects use wind to generate electricity from turbines, which is sold under fixed-price, long-term tariffs to Gestore Rete Transmissione Nazionale (GRTN). At December 31, 2002, the entire planned 303 MW had been commissioned and are operational. The project, however, is restricted to 283 MW as the project is awaiting 20 MW of transmission capacity to be interconnected to one of the sites. GRTN expects to complete the interconnection in the second quarter of 2003.

18

Spain

        Spanish Hydro Power Plants—EME's wholly owned subsidiary, Iberica de Energias, S.L., owns 18 small, run-of-the-river hydroelectric plants regionally dispersed in Spain totaling 86 MW, which EME refers to as the Spanish Hydro project. Iberica de Energias, S.L. sells electricity to Fuerzas Electricas de Cataluma, S.A. under concessions that have various expiration dates ranging from 2030 to 2065.

Turkey

        Doga Cogeneration Plant—EME owns an 80% interest in Doga Enerji, which owns a 180 MW gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. Doga Enerji sells electricity to Turkiye Elektrik Ticaret ve Taahhut, A.S., commonly known as TETAS, under a power purchase agreement that expires in 2018. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Contingencies" for information regarding regulatory developments affecting the Doga project.

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

Discontinued Operations

Lakeland Project

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

        On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings in the United Kingdom (similar to bankruptcy proceedings in the United States). As a result of these actions and their effect upon Norweb Energi Ltd. and EME's contractual arrangements with other parties, the Lakeland power plant suspended operations.

        In December 2002, the directors of Norweb Energi Ltd. appointed a liquidator to wind up its contractual rights and obligations. On December 4, 2002, Norweb Energi Ltd. provided a notice of disclaimer of the power sales agreement under Section 178 of the Insolvency Act 1986. The disclaimer effectively terminated the power sales agreement.

        On December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20, 2002, the Lakeland project lenders appointed Michael Thomas Seery and Michael Vincent McLoughlin, partners with KPMG LLP, as administrative receiver over the assets of Lakeland Power Ltd. The administrative receiver is appointed to take control of the affairs of Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of the power plant. The appointment of the administrative receiver requires the treatment of the Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Discontinued Operations."

        The bank loans of Lakeland Power Ltd. are non-recourse to EME. Furthermore, neither the defaults on these loans nor the institution of administrative proceedings cross-default to any other indebtedness of EME or its affiliates.

19

Ferrybridge and Fiddler's Ferry Plants

        On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. EME acquired the plants in 1999 from PowerGen UK plc. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in EME's consolidated financial statements. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Discontinued Operations."

Price Risk Management and Trading Activities

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

•

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



•

Trading—As part of its trading activities, EME seeks to generate profit from the volatility of the price of electricity, fuels and transmission by buying and selling contracts for their sale or provision, as the case may be, in wholesale markets under limitations approved by EME's Risk Management Committee. These trading activities generally occur in markets that are related to the price risk management activities described above. Edison Mission Marketing & Trading generally balances forward sales and purchase contracts and manages its exposure through a value at risk analysis. Edison Mission Marketing & Trading 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 has systems in place which monitor real time spot and forward pricing and perform option valuations. Edison Mission Marketing & Trading also has a wholesale power scheduling group that operates on a 24-hour basis.

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

        In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to factors beyond EME's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant

20

trading parties have completely withdrawn from the market or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also increase EME's credit risk. 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 may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

        EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place which limit the amount of total net exposure EME may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk management committee. EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the drivers of the risk. 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, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

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

21

Seasonality

        EME's third quarter income from continuing operations from its domestic energy projects are materially higher than income from continuing operations related to other quarters of the year because warmer weather during the summer months results in higher electric revenues being generated from the Homer City facilities and the Illinois Plants, and because a number of EME's domestic energy projects, located on the west coast, have power sales contracts that provide for higher payments during the summer months. By contrast, the First Hydro plants and Contact Energy have higher electric revenues during their winter months.

Regulatory Matters

General

        EME's operations are subject to extensive regulation by governmental agencies in each of the countries in which EME conducts operations. EME's domestic operating projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the ownership and operation of its projects, and the use of electric energy, capacity and related products, including ancillary services from its projects. Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operation of a project and the ownership of a project. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy producing facility and that the facility then operate in compliance with these permits and approvals. Furthermore, each of EME's international projects is subject to the energy and environmental laws and regulations of the foreign country in which the project is located. The degree of regulation varies by country and may be materially different from the regulatory regime in the United States.

        EME is subject to a varied and complex body of laws and regulations that are in a state of flux and which both public officials and private parties may seek to enforce. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures and may create a significant risk of expensive delays or significant loss of value in a project if it is unable to function as planned due to changing requirements or local opposition.

U.S. Federal Energy Regulation

        The Federal Energy Regulatory Commission has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission has regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935. The enactment of the Public Utility Regulatory Policies Act of 1978 and the adoption of regulations thereunder by the Federal Energy Regulatory Commission provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and the Public Utility Holding Company Act for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from the Public Utility Holding Company Act for exempt wholesale generators and foreign utility companies.

22

        A "qualifying facility" under the Public Utility Regulatory Policies Act is a cogeneration facility or a small power production facility that satisfies criteria adopted by the Federal Energy Regulatory Commission. In order to be a qualifying facility, a cogeneration facility must (i) sequentially produce both useful thermal energy, such as steam, and electric energy, (ii) meet specified operating standards, and energy efficiency standards when oil or natural gas is used as a fuel source and (iii) not be controlled, or more than 50% owned by one or more electric utilities (where "electric utility" is interpreted with reference to the Public Utility Holding Company Act definition of an "electric utility company"), electric utility holding companies (defined by reference to the Public Utility Holding Company Act definitions of "electric utility company" and "holding company") or affiliates of such entities.

        An "exempt wholesale generator" under the Public Utility Holding Company Act is an entity determined by the Federal Energy Regulatory Commission to be exclusively engaged, directly or indirectly, in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail.

        A "foreign utility company" under the Public Utility Holding Company Act is, in general, an entity located outside the United States that owns or operates facilities used for the generation, distribution or transmission of electric energy for sale or the distribution at retail of natural or manufactured gas, but that derives none of its income, directly or indirectly, from such activities within the United States.

        Federal Power Act—The Federal Power Act grants the Federal Energy Regulatory Commission exclusive 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 Federal Energy Regulatory Commission 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 Federal Energy Regulatory Commission to be workably competitive, may be market-based. As noted, most qualifying facilities are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the ratemaking jurisdiction of the Federal Energy Regulatory Commission thereunder, but the Federal Energy Regulatory Commission typically grants exempt wholesale generators the authority to charge market-based rates 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 Federal Energy Regulatory Commission jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the Federal Energy Regulatory Commission typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates. The Federal Energy Regulatory Commission has indicated its intention to review some of the waivers of financial reporting rules currently granted to some entities with market rate authority.

        Currently, in addition to the facilities owned or operated by EME, a number of its operating projects, including the Homer City facilities, the Illinois Plants, and Brooklyn Navy Yard facilities, are subject to the Federal Energy Regulatory Commission ratemaking regulation under the Federal Power Act. EME's future domestic non-qualifying facility independent power projects will also be subject to Federal Energy Regulatory Commission jurisdiction on rates.

        The Public Utility Holding Company Act—Unless exempt or found not to be a holding company by the Securities and Exchange Commission, a company that falls within the definition of a holding company must register with the Securities and Exchange Commission and become subject to Securities and Exchange Commission regulation as a registered holding company under the Public Utility Holding Company Act. "Holding company" is defined in Section 2(a)(7) of the Public Utility Holding Company

23

Act to include, among other things, any company that owns 10% or more of the voting securities of an electric utility company. "Electric utility company" is defined in Section 2(a)(3) of the Public Utility Holding Company Act to include any company that owns or operates facilities used for generation, transmission or distribution of electric energy for sale. Exempt wholesale generators and foreign utility companies are not deemed to be electric utility companies, and ownership or operation of qualifying facilities does not cause a company to become an electric utility company. Securities and Exchange Commission precedent also indicates that it does not consider "paper facilities," such as contracts and tariffs used to make power sales, to be facilities used for the generation, transmission or distribution of electric energy for sale, and power marketing activities will not, therefore, result in an entity being deemed to be an electric utility company.

        A registered holding company is required to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. In addition, a registered holding company will require Securities and Exchange Commission approval for the issuance of securities, other major financial or business transactions (such as mergers) and transactions between and among the holding company and holding company subsidiaries.

        Edison International, EME's ultimate parent company, is a holding company because it owns Southern California Edison, an electric utility company. However, Edison International is exempt from registration pursuant to Section 3(a)(1) of the Public Utility Holding Company Act, because the public utility operations of the holding company system are predominantly intrastate in character. Consequently, EME is not a subsidiary of a registered holding company, so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another of the exemptions enumerated in Section 3(a). EME is not a holding company under the Public Utility Holding Company Act, because its interests in power generation facilities are exclusively in qualifying facilities, facilities owned by exempt wholesale generators and facilities owned by foreign utility companies. All international projects and specified U.S. projects that EME might develop or acquire will be non-qualifying facility independent power projects. EME intends for each project to qualify as an exempt wholesale generator or as a foreign utility company. Loss of exempt wholesale generator, qualifying facility or foreign utility company status for one or more projects could result in EME's becoming a holding company subject to registration and regulation under the Public Utility Holding Company Act and could trigger defaults under the covenants in EME's project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and could cause certain of EME's project agreements and other contracts to be voidable.

        Public Utility Regulatory Policies Act of 1978—The Public Utility Regulatory Policies Act provides two primary benefits to qualifying facilities. First, as discussed above, ownership of qualifying facilities will not cause a company to be deemed an electric utility company for purposes of the Public Utility Holding Company Act. In addition, all cogeneration facilities that are qualifying facilities are exempt from most provisions of the Federal Power Act and regulations of the Federal Energy Regulatory Commission thereunder. Second, the Federal Energy Regulatory Commission regulations promulgated under the Public Utility Regulatory Policies Act require that electric utilities purchase electricity generated by qualifying facilities at a price based on the purchasing utility's avoided cost, and that the utilities sell back up power to the qualifying facility on a nondiscriminatory basis. The Federal Energy Regulatory Commission's regulations define "avoided cost" as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from the qualifying facility or qualifying facilities, the utility would generate itself or purchase from another source. The Federal Energy Regulatory Commission's regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs. While it has been common for utilities to enter into long-term contracts with qualifying facilities in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions, increasing competition and the

24

development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner.

        If one of the projects in which EME has an interest were to lose its status as a qualifying facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation under the Public Utility Holding Company Act and the Federal Power Act. As a result, the project could become subject to rate regulation by the Federal Energy Regulatory Commission under the Federal Power Act, and EME could inadvertently become a holding company under the Public Utility Holding Company Act. Under Section 26(b) of the Public Utility Holding Company Act, any project contracts that are entered into in violation of the Public Utility Holding Company Act, including contracts entered into during any period of non-compliance with the registration requirement, could be determined by the courts or the 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 Federal Energy Regulatory Commission would be required. In addition, the project would be required to cease selling electricity to any retail customers, in order to qualify for exempt wholesale generator status, and could become subject to additional state regulation. Loss of qualifying facility status by one project could also potentially cause other projects with the same partners to lose their qualifying facility status to the extent those partners became electric utilities, electric utility holding companies or affiliates of such companies for purposes of the ownership criteria applicable to qualifying facilities. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, EME cannot provide assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME's business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards for maintaining qualifying facility status or that eliminated or reduced the benefits, such as the mandatory purchase provisions of the Public Utility Regulatory Policies Act and exemptions currently enjoyed by qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties being levied against EME, or claims by a utility customer for the refund of payments previously made.

        EME endeavors to develop its qualifying facility projects, monitor regulatory compliance by these projects and choose its customers in a manner that minimizes the risks of losing these projects' qualifying facility status. However, some factors necessary to maintain qualifying facility status are subject to risks of events outside EME's control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a qualifying facility could cause a facility to fail to meet the requirements regarding the minimum level of useful thermal energy output. Upon the occurrence of this type of event, EME would seek to replace the thermal energy customer or find another use for the thermal energy that meets the requirements of the Public Utility Regulatory Policies Act.

        Natural Gas Act—Many of the domestic operating facilities that EME owns, operates or has investments in use natural gas as their primary fuel. Under the Natural Gas Act, the Federal Energy Regulatory Commission has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The Federal Energy Regulatory Commission has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce.

25

Recent Foreign Regulatory Matters

        See the discussion on recent foreign regulatory matters in "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures."

Transmission of Wholesale Power

        Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others. This transmission service over the lines of intervening transmission owners is also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the Federal Energy Regulatory Commission when the entity providing the wheeling service is a jurisdictional public utility under the Federal Power Act.

        Until 1992, the Federal Energy Regulatory Commission's ability to compel wheeling was very limited, and the availability of voluntary wheeling service could be a significant factor in determining whether a site was viable for project development. The Federal Energy Regulatory Commission's authority under the Federal Power Act to require electric utilities to provide transmission service on a case-by-case basis to qualifying facilities, exempt wholesale generators, and other power generators was expanded substantially by the Energy Policy Act. Furthermore, in 1996 the Federal Energy Regulatory Commission issued Order No. 888, in which the Commission asserted the power, under its authority to eliminate undue discrimination in transmission, to compel all jurisdictional public utilities under the Federal Power Act to file open access transmission tariffs consistent with a pro forma tariff drafted by the Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission subsequently issued 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 Federal Energy Regulatory Commission 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 issuing Order No. 888 et al., the Federal Energy Regulatory Commission determined that the open-access rules set forth in the order would apply to transmission with respect to wholesale sales and also with respect to retail transactions where the transmission component had been unbundled from the retail sale by state regulatory action or voluntarily by the utility making the retail sale. The Commission declined to assert jurisdiction over retail transmission service whose costs were included in the delivered price of energy to the end user (i.e., costs that remained "bundled" into the retail sale). Subsequent court appeals of Order No. 888 were brought by parties challenging the order on the basis that the Commission had no authority to regulate the transmission of unbundled retail sales and by parties challenging the Commission's failure to include the transmission of bundled retail sales in the order. On June 30, 2000, the U.S. Court of Appeals for the District of Columbia Circuit upheld the decision by the Federal Energy Regulatory Commission in both respects, finding that the Commission did have jurisdiction to regulate transmission of unbundled retail transactions, and that it was not required to assert jurisdiction over transmission embedded in bundled retail sales. In an opinion issued on March 4, 2002, the Supreme Court affirmed the decision of the U.S. Court of Appeals.

        While Order No. 888 was pending judicial review, it became apparent to the Federal Energy Regulatory Commission that relying exclusively on the Order No. 888 requirement to file open access tariffs was not having the desired effects of eliminating discriminatory behavior by transmission-owning utilities and promoting the development of competitive wholesale electricity markets. Accordingly, in an effort to remedy the shortcomings it perceived, the Commission, on December 20, 1999, issued Order No. 2000, which required all jurisdictional transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing functional control over their transmission assets under a

26

Regional Transmission Organization, or RTO, meeting certain criteria set forth in the order. Although Order No. 2000 did not mandate that a utility join an RTO, it set forth various incentives for voluntary action by utilities to take such action and required them to explain in detail their reasons for deviating from the objectives set forth in the order. RTOs meeting the Commission's criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential attributes, such as regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring capability, and other features. In subsequent orders, the Commission has progressively tightened its policies in favor of RTO formation, by such means as an explicit proposal that approvals of market-based rate authority for affiliates of utilities owning transmission should be tied to such utilities' placing functional control over their transmission assets in an RTO meeting the criteria of Order No. 2000.

        On July 31, 2002, the Federal Energy Regulatory Commission 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 (SMD) that would provide a "level playing field" for all entities that seek to participate in wholesale electric markets. The SMD proposal includes a number of features that, taken together, should provide a flexible transmission service and an open and transparent spot market design that convey the right pricing signals for investment in transmission and generation facilities, and for other purposes. Comments on certain features of the SMD proposal were filed by interested parties in October 2002 and during the first quarter of 2003. The SMD proposal has also engendered considerable comment, and in some cases opposition, including in Congress, and the anticipated timetable for issuance of a final rule is now unclear. The Federal Energy Regulatory Commission recently indicated its intention to publish a "White Paper" in April 2003 setting forth its plans for SMD implementation. Whether adopted in its current or a modified form, it may take several years before the SMD model becomes fully operational in all regions of the country. These and other regulatory initiatives by the Federal Energy Regulatory Commission are ongoing, and it is not possible to predict the extent of future developments or how they might affect the wholesale power business.

Retail Competition

        In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of many states have considered whether to open the retail electric power market to competition. Retail competition is possible when a customer's local utility agrees, or is required, to unbundle its distribution service (for example, the delivery of electric power through its local distribution lines) from its transmission and generation service (for example, the provision of electric power from the utility's generating facilities or wholesale power purchases). Several state commissions and legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution service, which is called retail wheeling, and phasing in retail wheeling over the next several years.

        The competitive pricing environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, EME expects that most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with qualifying facilities and exempt wholesale generators. On the other hand, qualifying facilities and exempt wholesale generators may be subject to pressure to lower their contract prices in an effort to reduce the stranded investment costs of their utility customers. Recent volatility in California and other regional power markets has resulted in several states slowing, and in some cases reversing, their plans to allow retail competition.

27

Environmental Matters and Regulations

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

Employees

        MEHC has no full-time employees. At December 31, 2002, EME and its subsidiaries employed 2,662 people, all of whom were full-time employees and 180, 148 and 1,022 of whom were covered by collective bargaining agreements in the United Kingdom, Australia and the United States, respectively.

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.

ITEM 2. PROPERTIES

        MEHC's principal office is in Irvine, California.

        EME leases its principal office in Irvine, California. This lease covers approximately 147,000 square feet. The term of the lease for approximately 65,500 square feet expires on December 31, 2004 with two five-year options to extend. The term of the lease for the balance of approximately 81,500 square feet expires on December 31, 2004 with no options to extend. EME also leases office space in Chicago, Illinois; Chantilly, Virginia and Boston, Massachusetts. The Chicago lease is for approximately 51,000 square feet and expires on December 31, 2009. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010. The Boston lease is for approximately 42,000 square feet and expires on July 31, 2007. At December 31, 2002, approximately 30% of the above space was either available for sublease or subleased.

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

28

Description of Properties

ITEM 3. LEGAL PROCEEDINGS

Brooklyn Navy Yard Project

        Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. A wholly owned subsidiary of EME owns 50% of the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $137 million. Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the construction turnkey agreement. Trial was scheduled for October 21, 2002, and rescheduled for January 2003. In December 2002, the parties held mediation sessions and settled the litigation. A settlement agreement was executed on January 17, 2003, which was followed by the dismissal of both the New York and the California litigation and release of the writs of attachment.

EcoEléctrica Potential Environmental Proceeding

        EME owns an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. On August 15, 2002, the U.S. Department of

29

Justice notified EcoEléctrica that it was preparing to bring a federal court action for violations of the Clean Air Act and regulations promulgated thereunder, and requested a meeting with EcoEléctrica to discuss and possibly settle the matter. The initial meeting with the Department of Justice took place on January 15, 2003. Settlement discussions have continued in 2003.

Regulatory Developments Affecting Sunrise Power Company

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

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

        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. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions are still pending.

30

Paiton Labor Suit

        In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and the former President Director of PT PLN are also named as defendants in the suit. The union seeks to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement then in effect between Paiton Energy and its lenders, as well as damages and other relief. On April 16, 2002 the Central Jakarta District Court dismissed the lawsuit against Paiton Energy and the other defendants on the basis that the PLN Labor Union was not authorized under the law to bring such an action. The PLN Labor Union filed an appeal on April 23, 2002. In order for the Appeals Court to hear any appeal on the matter, the District Court must have certified its judgment and forwarded it to the Appeals Court.

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

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

        Inapplicable.

31

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, The Mission Group, a wholly owned subsidiary of Edison International. There is no market for the common stock. Dividends on the common stock will be paid when declared by MEHC's board of directors. MEHC's wholly owned subsidiary, Edison Mission Energy (EME), made cash dividend payments to MEHC's parent, The Mission Group, totaling $65 million and $88 million during 2001 and 2000, respectively. MEHC paid two dividends to The Mission Group: (i) $811.2 million from the proceeds of the issuance of 13.5% senior secured notes and the term loan, and (ii) $31.5 million from dividends received from EME after July 2, 2001. EME did not pay or declare any dividends to MEHC during 2002.

        During the first two years of MEHC's operations, when debt interest payments will be funded with restricted cash, MEHC is permitted to distribute to its direct parent, The Mission Group dividends MEHC receives 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 after July 15, 2003 are 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 contractual obligations (including its corporate credit facility), charter documents, business and tax considerations, and restrictions imposed by applicable law.

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

•

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



•

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

        EME's interest coverage ratio for the four quarters ended December 31, 2002 was 2.36 to 1. For more information on these restrictions, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition—Edison Mission Energy's Interest Coverage Ratio."

32

ITEM 6. SELECTED FINANCIAL DATA

(1)

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

33

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

        The following discussion contains forward-looking statements. These statements are based on 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—Risk Factors."

        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 the $385 million term loan due 2006, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes or the term loan.

GENERAL

        MEHC was formed as a wholly owned subsidiary of The Mission Group, which is a wholly owned subsidiary of Edison International. MEHC was formed to:

•

hold the common stock of EME;



•

incur the indebtedness under the senior secured notes and the term loan; and



•

use a portion of the proceeds from the senior secured notes and the term loan to pay a dividend to The Mission Group which in turn loaned the funds to Edison International to retire a portion of their debt obligations.

        On July 2, 2001, The Mission Group 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, the term loan 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.

        EME is an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. EME also conducts price risk management and energy trading activities in power markets open to competition. Edison International is EME's ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States.

        As of December 31, 2002, EME owned or leased interests in 28 domestic and 53 international operating power plants with an aggregate generating capacity of 23,561 megawatts (MW), of which EME's share was 18,688 MW. At that date, one domestic and two international power plants, totaling 615 MW of generating capacity, of which EME's anticipated share will be approximately 308 MW, were in construction.

Current Developments

        A number of significant developments during late 2001 and 2002 have adversely affected independent power producers and subsidiaries of major integrated energy companies that sell a sizable

34

portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries, as discussed below. These developments included lower market prices in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their obligations. In response to these developments, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial new development, significant reduction in or elimination of trading activities, decreases in capital expenditures, including cancellations of orders for new turbines, and reductions in operating costs. In early 2003, wholesale energy prices have increased primarily due to colder-than-normal weather and increases in the prices for natural gas. However, the recent changes in wholesale energy prices may or may not continue throughout 2003. See "—Market Risk Exposures" for more information regarding forward market prices.

EME's Situation

        Because of the 2000-2001 California power crisis and its indirect effect on EME and its subsidiaries, EME de-emphasized the development and acquisition of projects and focused primarily on enhancing the performance of its existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, EME completed the sale of several non-strategic project investments. During 2002, EME undertook a further effort to reduce corporate overhead and other expenditures across the organization and to reduce debt.

        In 2002, EME was affected by lower wholesale prices of energy and capacity, particularly at its Homer City facilities in Pennsylvania, and by the diminished ability to enter into forward contracts for the sale of power primarily from these facilities because of the credit constraints affecting EME and many of its counterparties. See "—Market Risk Exposures—Americas—Homer City Facilities."

        EME's Illinois Plants were largely unaffected by these developments in 2002, because Exelon Generation was under contract to buy substantially all of the capacity from these units during the entire year. However, as permitted by the power purchase agreements, Exelon Generation advised EME that it will not purchase under contract 2,684 MW of capacity from EME's coal-fired units and 1,864 MW of capacity from EME's Collins Station and small peaking units during 2003 and 2004. Exelon Generation has the further right to release 1,265 MW of capacity from EME's coal-fired units and 1,778 MW of capacity from EME's Collins Station and small peaking units for 2004. As a result, beginning in 2003, the portion of EME's generation that will be sold into the wholesale markets has significantly increased, thereby increasing EME's merchant risk. See "—Market Risk Exposures—Americas—Illinois Plants."

        As a result of these and other factors, both Moody's Investors Service and Standard & Poor's Rating Service downgraded MEHC's credit rating, EME's credit rating and the credit rating of its largest subsidiary, Edison Mission Midwest Holdings, to below investment grade. See "—Liquidity and Capital Resources—Edison Mission Energy's Credit Ratings." Furthermore, MEHC's independent accountants' audit opinion for the year ended December 31, 2002, contains an explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that MEHC will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance Edison Mission Midwest Holdings' $911 million of debt due in December 2003 raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty. Within Item 8, see "Report of Independent Accountants" and "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Financial Instruments."

35

        Against this background, EME has undertaken a number of actions to reduce its commitments and expenditures, thereby improving its cash flow. These actions include:

•

a reduction in its capital expenditure program by an aggregate of $363 million over the next five years as the result of the cancellation of an outstanding order for nine turbines and suspension of work on two selective catalytic reduction systems (commonly referred to as SCRs) for its Powerton Station;



•

suspension, beginning in January 2003, of operations at Units 1 and 2 of its Will County plant and Units 4 and 5 of its Collins Station in Illinois in order to reduce operating costs;



•

termination of the obligation of EME's subsidiary, Midwest Generation, to install 500 MW of new generating capacity in Chicago in exchange for a series of payments and other consideration. See "—Contractual Obligations, Commitments and Contingencies—Chicago In-City Obligation;"



•

suspension of new business development activities; and



•

implementation of plans to reduce annual general and administrative expenses by approximately $25 million.

        In addition, EME continues to review the possibility of asset sales, but believes that current market conditions may inhibit its ability to obtain prices commensurate with its valuation of those investments which EME might offer for sale. For a discussion of risk factors that affect EME's business, see "—Risk Factors." For a discussion of EME's current financial condition, see "—Liquidity and Capital Resources."

Disposition of Investments in Energy Plants

        During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River plants and its 30% interest in the Harbor plant. Proceeds received from the sales were $44 million. During the second half of 2001, EME recorded asset impairment charges of $32 million related to these plants based on the expected sales proceeds. No gain or loss was recorded from the sale of its interests in these plants during the first quarter of 2002.

36

RESULTS OF OPERATIONS

CONSOLIDATED OPERATING RESULTS

Net Income Summary

        Net income is comprised of the following components:

        MEHC's loss from continuing operations in 2002 was $93 million compared to $49 million in 2001. The 2002 increase in loss from continuing operations from 2001 was due to a full year of interest expense in 2002 compared to a half year of interest expense in 2001, related to MEHC's $800 million senior secured notes and borrowings of $385 million under a term loan, both entered into on July 2, 2001. MEHC had no comparable results in 2000.

        EME's income from continuing operations in 2002 was $96 million compared to $83 million in 2001 and $65 million in 2000. The 2002 increase in income from continuing operations from 2001 was primarily due to improved operating results at EME's Illinois Plants and the Loy Yang B plants, income from the Paiton project in Indonesia, and lower state income taxes, partially offset by lower west coast energy prices, unplanned outages at the Homer City facilities, 2001 gains related to gas swaps from EME's oil and gas activities and net after-tax charges and credits during 2002 totaling $50 million. These after-tax charges and credits include a $66 million after-tax write-down of assets related to the cancellation of turbine orders, the suspension of the SCR major capital improvements project at the Powerton Station, an impairment of goodwill, and a $27 million after-tax loss from a settlement agreement that terminates the obligation to build additional generation in Chicago, partially offset by a gain of $43 million, after tax, from the settlement of a postretirement employee benefit liability.

        The 2001 increase in income from continuing operations from 2000 reflects higher energy prices for the Big 4 projects and increased earnings from oil and gas activities, partially offset by lower energy prices and capacity payments in the United Kingdom, after-tax charges of $38 million related to the phantom stock option plan in 2000, and $15 million, after tax, related to a loss on the termination of a portion of EME's Master Turbine Lease in 2001.

        EME's loss from discontinued operations in 2002 was $57 million compared to $1.2 billion in 2001 and income of $38 million in 2000. The 2002 loss from discontinued operations primarily represents an after-tax asset impairment charge of $77 million related to the Lakeland project in the United Kingdom. The 2001 loss includes an after-tax asset impairment charge of $1.2 billion related to the Ferrybridge and Fiddler's Ferry project in the United Kingdom. The 2000 income from discontinued operations is related to the operations of Lakeland and Ferrybridge and Fiddler's Ferry projects in the United Kingdom.

37

Operating Revenues

        Operating revenues increased 11% in 2002 from 2001 and increased 14% in 2001 from 2000. Operating revenues in 2002 increased from 2001 primarily due to consolidating Contact Energy operating revenue for a full year in 2002 as compared to a partial year in 2001 (EME's ownership interest increased to 51%, effective June 1, 2001), increased revenues from the Illinois Plants and the First Hydro plant, partially offset by decreased revenues from Homer City. Operating revenues in 2001 increased from 2000 primarily due to consolidating Contact Energy operating revenue for the first five months of 2001, as compared to the equity method of accounting in 2000, and higher revenues at Homer City, partially offset by lower revenues from First Hydro.

        Operating revenues includes net gains (losses) from risk management and energy trading activities of $27 million in 2002, $36 million in 2001, and $(17) million in 2000. Net gains and (losses) from price risk management activities result from recording derivatives at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133) or applicable generally accepted accounting principles prior to adoption of SFAS No. 133. Included in net gains (losses) from price risk management were:

•

$(1) million in 2002, $45 million in 2001 and $(87) million in 2000 related to hedging a portion of EME's gas price risk related to its share of gas production in Four Star, an oil and gas company in which EME has a minority interest and which is accounted for under the equity method. Although EME believes that these financial instruments hedge its gas price risk, hedge accounting is not permitted for transactions or investments accounted for on the equity method, and thus EME is required to record changes in fair value of these positions through the income statement.



•

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



•

$(1) million in 2002, $(21) million in 2001 and $6 million in 2000 related to hedging EME's anticipated fuel purchases at the Illinois Plants that also did not qualify for hedge accounting under SFAS No. 133.

        Net gains from energy trading activities were $42 million in 2002, $10 million in 2001, and $62 million in 2000.The increase in net gains from energy trading activities in 2002 from 2001 was primarily due to completing the restructuring of a power sales agreement with an unaffiliated electric utility during the first quarter of 2002. As part of the transaction, an EME subsidiary purchased the power sales agreement held by a third party, modified its terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over their term, net gains of $22 million were recorded in 2002 attributable to the fair value of the contracts (generally referred to as mark-to-market accounting). Net gains in 2002 also increased from 2001 as a result of realized gains from transmission congestion contracts. Net gains in 2001 decreased from 2000 primarily due to a reduction in trading activity in 2001 resulting from the adverse impact of the California power crisis on EME's credit, as well as higher gains in 2000 due to the volatility of power prices in the west coast trading markets during the fourth quarter of 2000.

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

38

Operating Expenses

        Fuel costs increased $129 million in 2002 from 2001, and increased $47 million in 2001 from 2000. Fuel costs in 2002 increased from 2001 primarily due to consolidating Contact Energy fuel costs for a full year in 2002 as compared to a partial year in 2001 (EME's ownership interest increased to 51%, effective June 1, 2001), increased pumping power costs from the First Hydro plant and increased fuel costs from the Illinois Plants, partially offset by decreased fuel costs from Homer City. Fuel costs in 2001 increased from 2000 primarily due to consolidating Contact Energy operating revenue for a partial year in 2001 as compared to the equity method of accounting in 2000 (EME's ownership interest increased to 51%, effective June 1, 2001), partially offset by lower fuel costs at the Illinois Plants.

        Plant operations and transmission costs increased $58 million in 2002 from 2001, and increased $184 million in 2001 from 2000. Transmission costs were $186 million in 2002, $99 million in 2001 and $33 million in 2000. The increases in transmission costs were primarily due to consolidating Contact Energy, effective June 1, 2001.

        Plant operating leases increased $73 million in 2002 from 2001, and increased $46 million in 2001 from 2000. The 2002 and 2001 increases were due to the sale-leaseback transactions for the Homer City and Powerton-Joliet power facilities. There were no comparable lease costs for the Homer City facilities through the period ended December 2001 and the Powerton-Joliet power facilities through the period ended August 2000. See "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions," for discussion of the financial impact of sale-leaseback transactions.

        Depreciation and amortization expense decreased $16 million in 2002 from 2001, and decreased $9 million in 2001 from 2000. The 2002 and 2001 decreases are primarily due to lower depreciation expense from Homer City and the Illinois Plants related to the sale-leaseback transaction from Homer City in December 2001 and the Powerton-Joliet power facilities in August 2000.

        Long-term incentive compensation expense consists of charges related to EME's terminated phantom option plan. Long-term incentive compensation expense increased $62 million in 2001 compared to 2000. The 2001 increase was due to a reduction in the liability for previously accrued incentive compensation by approximately $60 million recorded during 2000 and additional 2002 and 2001 compensation expense related to deferred payments and annual vesting of benefits. The 2000 reduction resulted from the lower valuation implicit in the August 2000 exchange offer pursuant to which the phantom option plan was terminated compared to the value previously accrued.

        The settlement of postretirement employee benefit liability relates to a retirement health care and other benefits plan for represented employees at the Illinois Plants that expired on June 15, 2002. In October 2002, Midwest Generation reached an agreement with its union-represented employees on new benefits plans, which extend from January 1, 2003 through June 30, 2005. Midwest Generation continued to provide benefits at the same level as those in the expired agreement until December 31, 2002. The accounting for postretirement benefits liabilities has been determined on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that Midwest Generation assumed, for accounting purposes, that it would provide for postretirement health care benefits to union-represented employees following conclusion of negotiations to replace the current benefits agreement, even though Midwest Generation had no legal obligation to do so. Under the new agreement, postretirement health care benefits will not be provided. Accordingly, Midwest Generation treated this as a plan termination under SFAS No. 106 and recorded a pre-tax gain of $71 million during the fourth quarter of 2002.

        Asset impairment and other charges were $131 million in 2002 and $59 million in 2001. Asset impairment and other charges in 2002 consisted of $61 million related to the write-off of capitalized costs associated with the termination of the turbines from Siemens Westinghouse, $45 million in

39

settlement of the In-City Obligation (refer to "—Contractual Obligations, Commitments and Contingencies—Chicago In-City Obligation," for further discussion), and $25 million related to the write-off of capitalized costs associated with the suspension of the Powerton Station SCR major capital environmental improvements project at the Illinois Plants. Asset impairment and other charges in 2001 consisted of $34 million to write down to the estimated net proceeds from the planned sale of the Commonwealth Atlantic, Gordonsville, Harbor and James River projects and $25 million related to a loss on the termination of a portion of EME's Master Turbine Lease. There were no comparable asset impairment and other charges in 2000.

        Administrative and general expenses decreased $7 million in 2002 from 2001 and increased $13 million in 2001 from 2000. The 2002 decrease was primarily due to lower business development costs. There were no material changes in 2001 administrative and general expenses from 2000. EME recorded a pre-tax charge of approximately $13 million in 2002 and $9 million in 2001 against earnings for severance and other related costs, which resulted from a series of actions undertaken to reduce administrative and general operating costs, including reductions in management and administrative personnel.

Other Income (Expense)

        Equity in income from unconsolidated affiliates decreased 24% in 2002 from 2001 and increased 40% in 2001 from 2000. The 2002 decrease was primarily due to a decrease in EME's share of income from the Big 4 projects and Four Star Oil & Gas, partially offset by an increase in EME's share of income from the Paiton Energy and ISAB projects. The 2001 increase was primarily due to an increase in EME's share of income from the Big 4 projects and the ISAB project. EME's third quarter equity in income from its domestic energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's domestic energy projects, located on the west coast, have power sales contracts that provide for higher payments during the summer months.

        Interest and other income decreased $14 million in 2002 from 2001, and increased $10 million in 2001 from 2000. The 2002 decrease was primarily due to lower interest income and foreign exchange losses from EME's intercompany loans. The 2001 increase was primarily due to higher interest income from interest earned on funds placed into an escrow account from the sale of the senior secured notes and the term loan.

        Gains on sale of assets were $5 million, $41 million and $26 million in 2002, 2001 and 2000, respectively. The gain on sale of assets in 2002 represents the sale of a development project in the United Kingdom during December 2002. Proceeds from the sale were $6 million. Gains on sale of assets for 2001 and 2000 included:

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

40

        Interest expense decreased $13 million in 2002 compared to 2001 and increased $73 million in 2001 compared to 2000. The 2002 decrease was due to a combination of the following: a reduction of $830 million in bonds assumed by the lessor in the sale-leaseback transaction of the Homer City facilities in December 2001, a reduction of $350 million in EME's corporate debt from the proceeds of such transaction and lower borrowings by EME combined with lower interest rates on variable rate debt generally tied to LIBOR, partially offset by higher interest margins as a result of EME's and Edison Mission Midwest Holdings' credit downgrades. See "—Liquidity and Capital Resources—Edison Mission Energy's Credit Ratings." In addition, the 2002 decrease in interest expense at EME was almost entirely offset by a full year of interest expense related to MEHC's $800 million senior secured notes and borrowings of $385 million under a term loan, both entered into on July 2, 2001. MEHC had no comparable interest expense for the first six months of 2001. The 2001 increase primarily reflects the issuance of MEHC's $800 million senior secured notes on July 2, 2001 and MEHC's borrowings of $385 million under a term loan entered into on July 2, 2001.

        Dividends on mandatorily redeemable preferred securities decreased $10 million in 2001 compared to 2000. The 2001 decrease reflects the redemption of the NZ$400 million EME Taupo preferred securities in July 2001.

Income Taxes

        MEHC had effective tax provision (benefit) rates of (200)% in 2002, 54% in 2001, and 53% in 2000. The effective income tax benefit rate in 2002 is due to additional state tax benefits recorded by EME, net of federal income taxes, of $32 million resulting from changes in estimates of the 2001 and 2002 tax-allocation calculation completed by Edison International. Under the tax-allocation agreement, EME's current state tax benefit is generally determined by using Edison International's combined state tax liability and calculating the difference between including and excluding EME's taxable income or losses and state apportionment factors. During the third quarter of 2002, Edison International substantially completed preparation of its 2001 combined state income tax returns and changed its 2002 estimated state income tax projection. EME expects that approximately $9 million of this benefit will not be paid until 2005. There was no significant change in the effective income tax rate in 2001 from 2000.

Minority Interest

        Minority interest expense increased $5 million in 2002 from 2001 and increased $19 million in 2001 from 2000. Minority interest primarily relates to 49% ownership of Contact Energy by the public in New Zealand. The 2002 and 2001 increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that increased EME's ownership interest from 43% to 51%.

Discontinued Operations

Lakeland Project

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

        On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings in the United Kingdom (similar to bankruptcy proceedings in the United States). As a result of these actions and

41

their effect upon Norweb Energi Ltd. and EME's contractual arrangements with other parties, the Lakeland power plant suspended operations.

        In December 2002, the directors of Norweb Energi Ltd. appointed a liquidator to wind up its contractual rights and obligations. On December 4, 2002, Norweb Energi Ltd. provided a notice of disclaimer of the power sales agreement under Section 178 of the Insolvency Act 1986. The disclaimer effectively terminated the power sales agreement.

        On December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20, 2002, the Lakeland project lenders appointed Michael Thomas Seery and Michael Vincent McLoughlin, partners with KPMG LLP, as administrative receiver over the assets of Lakeland Power Ltd. The administrative receiver is appointed to take control of the affairs of Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of the power plant. The appointment of the administrative receiver requires the treatment of the Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Discontinued Operations."

        The bank loans of Lakeland Power Ltd. are non-recourse to EME. Furthermore, neither the defaults on these loans nor the institution of administrative proceedings cross-default to any other indebtedness of EME or its affiliates.

        The events related to the Lakeland project resulted in an impairment charge of $92 million ($77 million after tax) and a provision for bad debts of $1 million, after tax, in the fourth quarter of 2002 arising from the write-down of the Lakeland power plant and related claims under the power sales agreement (an asset group under SFAS No. 144) to their fair market value. Due to EME's loss of control arising from the appointment of the administrative receiver, EME no longer consolidates the activities of Lakeland Power Ltd.

        The following table is a condensed income statement of the Lakeland project for the three years ended December 31, 2002.

(1)

The year ended December 31, 2002 includes an impairment charge of $92 million discussed above.

Ferrybridge and Fiddler's Ferry Project

        On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed

42

specified liabilities associated with the plants. The sale was the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. The early repayment of the projects' existing debt facility of £682 million at December 21, 2001 resulted in a loss of $28 million, after tax, attributable to the write-off of unamortized debt issue costs. EME recorded an after-tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.

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

        Effective January 1, 2001, EME recorded a $6 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of EME's activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges under SFAS No. 133. EME could not conclude that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, the majority of Ferrybridge and Fiddler's Ferry's energy contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

        Effective January 1, 2000, EME recorded a $4 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting for major maintenance costs. Through December 31, 1999, EME accrued for major maintenance costs incurred during the period at the Ferrybridge and Fiddler's Ferry power plants between overhauls (referred to as "accrue in advance" accounting method). In March 2000, EME voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred.

Cumulative Effect of Change in Accounting Principle

Discussion of Initial Adoption of SFAS No. 142

        During the third quarter of 2002, EME completed the steps necessary for the adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." EME concluded that the goodwill related to the Citizens Power LLC acquisition was impaired as discussed under "—New Accounting Standards." Retroactive to January 1, 2002, EME recorded a $14 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 142.

Accounting for Derivatives and SFAS No. 133

        EME's primary market risk exposures arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency exchange rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures. Effective January 1, 2001, MEHC adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also requires that changes in the derivative's fair value be recognized currently in earnings unless specific

43

hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

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

        On January 1, 2001, EME recorded a $250 thousand, after tax, increase to income from continuing operations and a $230 million, after tax, decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in quantities that are expected to be sold in the normal course of business. This modification had two significant impacts:

•

As a result of the new interpretation, EME's Homer City forward sales contracts qualified for the normal sales and purchases exception commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, EME eliminated the value of the Homer City forward sales contracts from its consolidated balance sheet. The cumulative effect of this change in accounting is reflected as a $16 million, after tax, decrease to other comprehensive income in 2001.



•

For the period between January 1, 2001 and June 30, 2001, EME applied the normal sales and purchases exception for long-term commodity contracts that included both selling and purchasing electricity by its First Hydro plant. However, the criteria applicable to the buyer of power outlined under Statement No. 133 Implementation Issue Number C15 precluded the contracts from qualifying under the normal sales and purchases exception as of July 1, 2001 because First Hydro is not contractually obligated to maintain sufficient capacity to meet electricity needs of a customer. Accordingly, EME recorded a $15 million, after tax, increase to income from continuing operations as the cumulative effect of change in accounting for derivatives in the consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of these contracts were reflected in net gains (losses) from price risk management in EME's consolidated income statement.

        Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded a net loss of approximately $2 million and $1 million in 2002 and 2001, respectively, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from price risk management and energy trading in its consolidated income statement.

Accounting for Major Maintenance Costs

        Through December 31, 1999, EME accrued for major maintenance costs incurred during the period between overhauls (referred to as "accrue in advance" accounting method). In March 2000, EME voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," EME recorded a $22 million, after tax, increase to income from continuing operations, as the cumulative effect of change in accounting for major maintenance costs during the quarter ended March 31, 2000.

44

REGIONAL OPERATING RESULTS

        EME operates predominantly in one line of business, electric power generation, organized by three geographic regions: Americas, Asia Pacific, and Europe.

        Operating revenues are derived from EME's majority-owned domestic and international entities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the following project results, except as described below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation.

        Equity in income from unconsolidated affiliates relates to energy projects where EME's ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which EME has a significant influence but in which it does not have a controlling interest. With respect to entities accounted for under the equity method, EME recognizes its proportional share of the income or loss of such entities.

        MEHC uses the word "earnings" in this section to describe EME's income from continuing operations before income taxes and minority interest.

Americas