Back to GetFilings.com

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2004

Commission File Number 000-24890

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

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

Common Stock, par value $0.01 per share

(Title of Class)

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

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

       Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES  / /    NO  /x/

       Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 30, 2004: $0. Number of shares outstanding of the registrant's Common Stock as of March 10, 2005: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

i

PART I

ITEM 1.    BUSINESS

The Company

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

       EME was formed in 1986 with two domestic operating power plants. As of December 31, 2004, EME's continuing operations consisted of owned or leased interests in 18 operating power plants with an aggregate net physical capacity of 9,914 megawatts (MW), of which EME's capacity pro rata share was 8,834 MW.

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

•

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

•

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

•

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

•

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

       See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview, Risks Related to the Business and Critical Accounting Estimates" for further details on EME's asset sales.

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

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

1

Forward-Looking Statements

       This annual report on Form 10-K contains forward-looking statements that reflect EME's current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events. Other information distributed by EME that is incorporated in this annual report, or that refers to or incorporates this annual report, may also contain forward-looking statements. In this annual report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "intends," "plans," "probable" and variations of such words and similar expressions are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact EME or its subsidiaries, include:

•

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

•

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

•

general political, economic and business conditions;

•

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

•

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

•

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

•

the cost and availability of fuel and fuel transportation services;

•

the cost and availability of transmission services;

•

the cost and availability of required emission allowances;

•

weather conditions, natural disasters and other unforeseen events; and

•

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

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

Description of the Industry

Electric Power Industry

       The United States electric industry, including companies engaged in providing generation, transmission, distribution and ancillary services, has undergone significant deregulation, which has led to

2

increased competition. Until the enactment of the Public Utility Regulatory Policies Act of 1978, referred to as PURPA in this annual report, utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. PURPA encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from specified types of non-utility power producers, known as qualifying facilities, under specified conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent power producers, such as EME, developed in the United States.

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

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

Competition and Market Condition Generally

       EME is subject to intense competition from energy marketers, utilities, industrial companies and other independent power producers. In prior years, the restructuring of energy markets led to the sale of utility-owned assets to EME and its competitors. More recently, in response to market conditions, EME has changed its focus from acquisition and growth to reducing debt and operating, maintaining, and maximizing the value of its current asset base. Accordingly, EME has engaged in asset sales, has canceled, deferred or sold new development projects, and has taken a number of actions to decrease

3

capital expenditures, including reductions in operating costs and decommissioning of operations at several power plants.

       Where EME sells power from plants from which the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, EME is subject to market fluctuations in prices based on a number of factors, including the amount of capacity available to meet demand, the price and availability of fuel and the presence of transmission constraints. EME's customers include large electric utilities or regional distribution companies. In some cases, the electric utilities and distribution companies have their own generation capacity, including nuclear generation, that affects the amount of generation available to meet demand and may affect the price of electricity in a particular market.

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

Operating Segments

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

4

Overview of Domestic Facilities

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

(1)

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

(2)

Electric purchaser abbreviations are as follows:

       A description of EME's larger power plants and major investments in energy projects is set forth below. In addition to the facilities and power plants that EME owns, EME uses the term "its" in regard to facilities and power plants that EME or an EME subsidiary operates under sale-leaseback arrangements.

Illinois Plants

       On December 15, 1999, Midwest Generation completed a transaction with Commonwealth Edison Company (Commonwealth Edison), now a subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel power plants located in Illinois, which are collectively referred to as the Illinois Plants in this annual report. These power plants are located in the Mid-America Interconnected Network,

5

which has transmission connections to the East Central Area Reliability Council and other regional markets.

       The Illinois Plants include the following:

(1)

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

(2)

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

(3)

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

       As part of the purchase of the Illinois Plants, EME assigned its right to purchase the Collins Station to third-party entities and Midwest Generation simultaneously entered into a long-term lease arrangement of the Collins Station with these third-party entities. In April 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity investor and received title to the Collins Station as part of the transaction. On September 30, 2004, Midwest Generation permanently ceased operations of the Collins Station. By the fourth quarter of 2004, the Collins Station was decommissioned and all units were permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered. See "Termination of the Collins Lease" section in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

6

       In August 2000, EME completed sale-leaseback transactions involving its Powerton and Units 7 and 8 of its Joliet power facilities. EME sold these assets to third parties and entered into long-term leases of the facilities from these third parties to repay corporate debt while maintaining control of the use of the power plants during the terms of the leases. For more information on these transactions, see "Off-Balance Sheet Transactions" section in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

Illinois Power Markets

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

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

       Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants were direct "wholesale customers" and broker-arranged "over-the-counter customers." Wholesale customer transactions are bilateral sales to regional buyers, including investor-owned utilities, municipal utilities, rural electric cooperatives and retail energy suppliers. Wholesale customer transactions include real-time, daily and longer term structured sales; they are not arranged through brokers and may be tailored to meet the specific requirements of wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include forward sales of electricity. The most liquid over-the-counter markets in the Midwest region have historically been sales into the control area of Cinergy, referred to as "Into Cinergy," and, to a lesser extent, sales into the control areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. "Into ComEd" and "Into AEP" were bilateral markets for the sale or purchase of electrical energy for future delivery. Due to geographic proximity, "Into ComEd" was the primary market for Midwest Generation.

       On May 1, 2004 and October 1, 2004, respectively, operational control of the control area systems of Commonwealth Edison and AEP was transferred to PJM, which is now the primary market available to Midwest Generation. This transfer resulted in the conversion of the "Into ComEd" and "Into AEP" trading hubs to locational marginal pricing, which has further facilitated transparency of prices and provided liquidity to support risk management strategies. Performance of transactions in these markets is subject to contracts that generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit assessment, parent company guarantees, letters of

7

credit and cash margining arrangements. However, liquidity in all of these markets has been adversely affected by the financial problems of trading and marketing entities.

       Following the transfer of control of the control area systems of Commonwealth Edison and AEP to PJM, sales of electricity from the Illinois Plants now include bilateral and spot sales into PJM, with spot sales being based on locational marginal pricing. These sales into the expanded PJM replaced sales previously made as bilateral sales and spot sales "Into ComEd" and "Into AEP." The Northern Illinois Hub is the primary trading hub for Midwest Generation produced power due to geographic proximity and high pricing correlation to the plants' output locations.

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

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

Transmission

       Historically, sales of power produced by Midwest Generation required using transmission that had to be obtained from Commonwealth Edison. An ISO did not yet oversee operations of the Commonwealth Edison control area; however, effective May 1, 2004 such operations were placed under the control of PJM. Furthermore, the transmission system of AEP was integrated into PJM on October 1, 2004, which linked the Northern Illinois and eastern portions of the PJM system and permitted the Illinois Plants to be dispatched into the broader PJM market. In addition, a number of other utilities in the region participate in the MISO where a bilateral market with a single rate for transmission within the RTO already exists. The regional market is further supported by open access transmission under various utility company transmission tariffs that are not within the MISO. The open access transmission tariffs of the MISO and others in the region allow Midwest Generation to utilize their transmission and distribution systems to sell power at wholesale on a non-discriminatory basis relative to the system's owners. Such tariffs are vital to allow Midwest Generation to compete in the deregulated electricity markets because they provide a uniform set of prices and standards of transmission service that have been approved by regulatory agencies and are publicly available.

       On November 18, 2004, the FERC issued an order eliminating regional through and out transmission rates in the region encompassed by PJM (as recently expanded) and the MISO. The effect of this order was to eliminate so-called rate pancaking between PJM and the MISO. Rate pancaking occurs when energy must move through multiple, separately priced transmission systems to travel from its point of production to its point of delivery, and each transmission owner along the line charges separately for the use of its system. At the same time, the FERC also imposed a transitional revenue recovery mechanism which has created controversy and some continuing uncertainty as to the impact of such mechanism on transactions in the region. The mechanism required the filing of tariffs by PJM and the MISO imposing

8

a "Seams Elimination Cost Adjustment" (SECA) to be in effect until May 1, 2006, to compensate the "new PJM companies"—AEP, Commonwealth Edison and Dayton Power & Light, among others—for lost revenues attributable to such elimination. On November 30, 2004, the FERC clarified that SECAs can be recovered for lost revenues associated with elimination on intra-RTO pancaking.

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

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

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

Fuel Supply

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

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

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

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

9

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

Emission Allowances

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

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

Homer City Facilities

       On March 18, 1999, EME completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to acquire the 1,884 MW Homer City Electric Generating Station. These facilities consist of three coal-fired boilers and steam turbine-generator units (referred to as Units 1, 2 and 3 in this annual report), one coal cleaning facility, water supply provided by a reservoir known as Two Lick Dam and associated support facilities in the mid-Atlantic region of the United States. The Homer City generating units have direct, high voltage interconnections to both PJM and the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly known as the NYISO. The NYISO was established in 1999 to operate a competitive, non-discriminatory wholesale power market in response to the FERC's Open Access Rules and includes bid-based electricity and transmission usage markets. The market-clearing price for NYISO's day-ahead and real-time energy markets is set by supplier generation bids and customer demand bids. For a discussion of the market risks related to the sale of electricity from the Homer City facilities, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

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

10

Fuel Supply

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

       Unit 3 consumes approximately 2 million tons of coal per year. EME Homer City purchases the majority of its Unit 3 coal from local suppliers under long-term contracts. All coal purchased for Unit 3 is delivered to the site by truck. A wet scrubber flue gas desulfurization system for Unit 3 enables this unit to be able to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control.

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

Emission Allowances

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

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

Big 4 Projects

       EME owns partnership investments in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, as described below. These projects have similar economic characteristics and have been used, collectively, to obtain bond financing by Edison Mission Energy Funding Corp., a special purpose entity. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Summary of Significant Accounting Policies," for discussion of EME's accounting for this entity. Due to similar economic characteristics and the bond financing related to its equity investments, EME views these projects collectively and refers to them as the Big 4 projects.

Kern River Cogeneration Plant

       EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Kern River project. Kern River Cogeneration sells electricity to Southern California Edison Company

11

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

Midway-Sunset Cogeneration Plant

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

Sycamore Cogeneration Plant

       EME owns a 50% partnership interest in Sycamore Cogeneration Company, which owns and operates a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Sycamore project. Sycamore Cogeneration sells electricity to Southern California Edison under a power purchase agreement that expires in 2007 and sells steam to TEPI under a steam supply agreement that also expires in 2007.

Watson Cogeneration Plant

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

Other Power Plants

Sunrise Power Plant

       EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired facility in Kern County, California, which EME refers to as the Sunrise project. The Sunrise project was constructed in two phases. Phase 1 achieved commercial operation in June 2001 and consisted of a 320 MW simple-cycle peaking facility. Phase 2, a combined-cycle gas-fired facility, converted the simple-cycle peaking facility to a 572 MW combined cycle plant. Phase 2 achieved commercial operation in June 2003. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources in June 2001, which expires in 2012. For further discussion related to this agreement, see "Item 3. Legal Proceedings—Sunrise Power Company Lawsuits."

March Point Cogeneration Plant

       EME owns a 50% partnership interest in March Point Cogeneration Company, which owns a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, which EME refers to as the March Point project. The March Point project consists of two phases. Phase 1 is an 80 MW gas

12

turbine cogeneration facility and Phase 2 is a 60 MW gas turbine combined cycle facility. March Point Cogeneration sells electricity to Puget Sound Energy, Inc. under a power purchase agreement that expires in 2011 and sells steam to Equilon Enterprises, LLC under a steam supply agreement that also expires in 2011.

Westside Power Plants

       EME owns partnership investments in Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, and Sargent Canyon Cogeneration Company. Due to similar economic characteristics, EME views these projects collectively and refers to them as the Westside projects. EME owns a 50% partnership interest in each of the companies listed above and each company owns a 38 MW natural gas-fired cogeneration facility located in California. Three of these projects sell electricity to Pacific Gas & Electric Company under 15-year power purchase agreements which expire in 2007. Mid-Set Cogeneration's power purchase and steam sales agreements expired in May 2004. Mid-Set Cogeneration is continuing to sell electricity to Pacific Gas & Electric under the "as available" rates and is selling steam to TEPI under an extension of the expired steam sales agreement. As of December 31, 2004, negotiations were underway to secure new power purchase and steam sales agreements for this project.

American Bituminous Power Plant

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

International Project

Doga Cogeneration Plant

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

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

Discontinued Operations

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

13

Price Risk Management and Trading Activities

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

•

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

•

Trading—As part of its trading activities, EME seeks to generate profit from the volatility of the price of electricity, fuels and transmission by buying and selling contracts for their sale or provision, as the case may be, in wholesale markets under limitations approved by EME's Risk Management Committee. These trading activities generally occur in markets that are related to the price risk management activities described above. Edison Mission Marketing & Trading generally balances forward sales and purchase contracts. Edison Mission Marketing & Trading's activities have included restructuring of power sales and power supply agreements for third parties, although these activities are not currently being pursued. Collectively, Edison Mission Marketing & Trading refers to these as its trading activities and records these transactions in what it calls its proprietary book.

       Edison Mission Marketing & Trading is divided into front-, middle-, and back-office segments, with specified duties segregated for control purposes. Edison Mission Marketing & Trading also has a wholesale power scheduling group that operates on a 24-hour basis.

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

       To manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform pursuant to the terms

14

of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever possible to mitigate its exposure to counterparty risk. EME requires counterparties to pledge collateral when deemed necessary. EME uses published credit ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

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

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

Significant Customer

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

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

15

Insurance

       EME maintains insurance policies consistent with those normally carried by companies engaged in similar business and owning similar properties. EME's insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boilers, machinery breakdowns, and the perils of earthquake and flood, subject to specific sublimits. EME also carries general liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations, automobile liability insurance and excess liability insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size. However, no assurance can be given that EME's insurance will be adequate to cover all losses.

Seasonality

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

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

Regulatory Matters

General

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

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

16

U.S. Federal Energy Regulation

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

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

       An "exempt wholesale generator" under PUHCA is an entity determined by the FERC to be exclusively engaged, directly or indirectly, in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail.

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

Federal Power Act

       The Federal Power Act grants the FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the FERC to revoke or modify previously approved rates after notice and opportunity for hearing. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be workably competitive, may be market based. As noted, most qualifying facilities are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the FERC's ratemaking jurisdiction thereunder, but the FERC typically grants exempt wholesale generators the authority to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, the Federal Power Act grants the FERC jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.

17

       As of December 31, 2004, a number of EME's operating projects, including the Homer City facilities and the Illinois Plants, were subject to the FERC ratemaking regulation under the Federal Power Act. EME's future domestic non-qualifying facility independent power projects will also be subject to the FERC jurisdiction on rates.

Public Utility Holding Company Act of 1935

       Edison International, EME's ultimate parent company, is a holding company because it owns Southern California Edison, an electric utility company. However, Edison International and its subsidiaries are exempt for all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (PUHCA) on the basis that Edison International and Southern California Edison are incorporated in the same state and their utility businesses are predominantly intrastate in character and carried on substantially in their state of incorporation. Section 9(a)(2) provides, in substance, that Edison International may not directly or indirectly acquire 5% or more of the voting securities of a public utility company other than Southern California Edison, unless the acquisition has been approved by the Securities and Exchange Commission. Consequently, EME is not a subsidiary of a registered holding company so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another of the exemptions enumerated in Section 3(a).

       EME is not a holding company under PUHCA, because its interests in power generation facilities are exclusively in qualifying cogeneration facilities, facilities owned by exempt wholesale generators and facilities owned by foreign utility companies. All projects that EME might develop or acquire will be non-qualifying facility independent power projects. Loss of exempt wholesale generator, qualifying cogeneration facility or foreign utility company status for one or more projects could result in EME's becoming a holding company subject to registration and regulation under PUHCA and could trigger defaults under the covenants in EME's project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and could cause certain of EME's project agreements and other contracts to be voidable.

Public Utility Regulatory Policies Act of 1978

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

       If one of the projects in which EME has an interest were to lose its status as a qualifying cogeneration facility, the project would no longer be entitled to the qualifying facility-related exemptions

18

from regulation under PUHCA and the Federal Power Act. As a result, the project could become subject to rate regulation by the FERC under the Federal Power Act, and EME could inadvertently become a holding company under PUHCA. Under Section 26(b) of PUHCA, any project contracts that are entered into in violation of PUHCA, including contracts entered into during any period of non-compliance with the registration requirement, could be determined by the courts or the Securities and Exchange Commission to be void. If a project were to lose its qualifying facility status, EME could attempt to avoid holding company status on a prospective basis by qualifying the project owner as an exempt wholesale generator. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from the FERC would be required. In addition, the project would be required to cease selling electricity to any retail customers, in order to qualify for exempt wholesale generator status, and could become subject to additional state regulation. Loss of qualifying facility status by one project could also potentially cause other projects with the same partners to lose their qualifying facility status to the extent those partners became electric utilities, electric utility holding companies or affiliates of such companies for purposes of the ownership criteria applicable to qualifying facilities. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, EME cannot provide assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME's business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards for maintaining qualifying facility status or that eliminated or reduced the benefits, such as the mandatory purchase provisions of PURPA and exemptions currently enjoyed by qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties, or claims by a utility customer for the refund of payments previously made.

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

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

19

Natural Gas Act

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

Transmission of Wholesale Power

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

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

   &nbs