10-K

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

FORM 10-K

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

For the fiscal year ended December 31, 2005

Commission File Number 333-68630

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

Delaware (State or other jurisdiction of incorporation or organization)	95-4031807 (I.R.S. Employer Identification No.)
18101 Von Karman Avenue, Suite 1700 Irvine, California (Address of principal executive offices)	92612 (Zip Code)
Registrant's telephone number, including area code: (949) 752-5588
Securities registered pursuant to Section 12(b) of the Act:
None	Not Applicable
(Title of Class)	(Name of each exchange on which registered)

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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES o NO ý

       Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o NO ý

       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. o

       Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):    Large accelerated filer o    Accelerated filer o    Non-accelerated filer ý

       Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO ý

       Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 30, 2005: $0. Number of shares outstanding of the registrant's Common Stock as of February 28, 2006: 100 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.

(1)	Designated portions of Edison Mission Energy's Amendment to Form 10-K for the year ended December 31, 2005	Part III
(2)	Designated portions of the Proxy Statement relating to Edison International's 2006 Annual Meeting of Shareholders	Part III

       Edison Mission Energy is an indirect wholly owned subsidiary of Edison International. Although Edison International is a large accelerated filer as defined under Exchange Act Rule 12b-2, Edison Mission Energy is a non-accelerated filer. Edison Mission Energy is filing its annual report on Form 10-K concurrently with Edison International's filing of its annual report on Form 10-K. Edison Mission Energy has been advised by Edison International that, prior to March 31, 2006, Edison International will file with the Securities and Exchange Commission a definitive proxy statement containing information relating to executive compensation. Edison Mission Energy will file an amendment to its Form 10-K relating to the compensation of Edison Mission Energy's executive officers concurrently with Edison International's filing of its definitive proxy statement. The amendment will include some of the executive compensation information included in Edison International's definitive proxy statement as such information pertains to Edison Mission Energy's executive officers.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	26
Item 3.	Legal Proceedings	26
Item 4.	Submission of Matters to a Vote of Security Holders	26
	Executive Officers of the Registrant	27
PART II
Item 5.	Market for Registrant's Common Equity and Related Stockholder Matters	29
Item 6.	Selected Financial Data	30
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	87
Item 8.	Financial Statements and Supplementary Data	88
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	88
Item 9A.	Controls and Procedures	88
Item 9B.	Other Information	88
PART III
Item 10.	Directors and Executive Officers of the Registrant	141
Item 11.	Executive Compensation	142
Item 12.	Security Ownership of Certain Beneficial Owners and Management	142
Item 13.	Certain Relationships and Related Transactions	143
Item 14.	Principal Accounting Fees and Services	143
PART IV
Item 15.	Exhibits and Financial Statement Schedules	145
	Signatures	151

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, 2005, EME's continuing operations consisted of owned or leased interests in 20 operating power plants with an aggregate net physical capacity of 10,214 megawatts (MW), of which EME's capacity pro rata share was 9,098 MW.

       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 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.

       EME'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.

EME Restructuring Activities

       During 2004 and early 2005, EME sold assets totaling 6,452 megawatts (MW), which constituted most of its international assets. These international assets, except for the Doga project, which has not been sold, are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. The sale of the international operations included:

•

On September 30, 2004, EME sold its 51.2% interest in Contact Energy Limited to Origin Energy New Zealand Limited.

•

On December 16, 2004, EME sold 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 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 sold 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 sold its 25% equity interest in the Tri Energy project to IPM.

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       See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Discontinued Operations" for further details on EME's asset sales.

       EME implemented management and organizational changes in 2005 to streamline its reporting relationships and eliminate its regional management structure. In addition, EME and its affiliate, Edison Capital, have combined their management teams located in Irvine, California and combined their wind development efforts. In this regard, EME and Edison Capital have entered into a services agreement effective December 26, 2005. Under this services agreement, all existing employees of Edison Capital on the effective date of the agreement were transferred to EME, and thereafter EME provides accounting, legal, tax, management and administrative services to Edison Capital and its subsidiaries of the type previously provided by the transferred employees. Edison Capital and its subsidiaries continue to operate as independent legal entities separate and apart from EME, and EME has not assumed any obligation for the performance of any of Edison Capital's obligations to any party, whether with respect to its investment portfolio or with respect to any of the creditors of Edison Capital or its subsidiaries.

Forward-Looking Statements

       This annual report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements 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 and include any statement that does not directly relate to a historical or current fact. 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," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, 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 but are not limited to:

•

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;

•

the cost and availability of coal, natural gas, and fuel oil, and associated transportation;

•

market volatility and other market conditions that could increase EME's obligations to post collateral beyond the amounts currently expected, and the potential effect of such conditions on the ability of EME and its subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;

•

the cost and availability of emission credits or allowances;

•

transmission congestion in and to each market area and the resulting differences in prices between delivery points;

•

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

•

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

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technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;

•

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

•

effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events; and

•

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

       Certain of the risk factors listed above are discussed in more detail in "Item 1A. Risk Factors" below and in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures." Additional information about the risk factors listed above and other risks and uncertainties is contained throughout this annual report. Readers are urged to read this entire annual report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made, 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 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. In addition, in the Energy Policy Act of 2005, referred to as EPAct 2005 in this annual report, Congress made several changes to PURPA and other statutory provisions recognizing that a significant market for electric power produced by independent power producers, such as EME, has developed in the United States and indicating that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.

       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 system 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 such organized markets into which

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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."

Electric Power Markets

       EME's largest power plants are its fossil fuel power plants located in Illinois, which are collectively referred to as the Illinois Plants in this annual report, and the Homer City electric generating station located in Pennsylvania, which is referred to as the Homer City facilities in this annual report. The Illinois Plants and the Homer City facilities sell power into PJM Interconnection, LLC, commonly referred to as PJM. PJM operates a 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), with respect to the Illinois Plants, and EME Homer City Generation L.P. (EME Homer City), with respect to the Homer City facilities, may participate in PJM's capacity markets or transact capacity sales on a bilateral basis.

       The Homer City facilities 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 referred to as the NYISO. As in PJM, the market-clearing price for NYISO's day-ahead and real-time energy markets is set by supplier generation bids and customer demand bids.

       The Illinois Plants also sell power into PJM. On April 1, 2005, the Midwest Independent Transmission System Operator (MISO) commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region, in the MISO, where there is a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM. While EME does not own generating facilities within MISO, its opening has further facilitated transparency of prices and provided additional market liquidity to support risk management and trading strategies.

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

Competition

       EME is subject to intense competition from energy marketers, utilities, energy marketers, industrial companies and other independent power producers. For a number of years until the recent upturn in its price, natural gas has been the fuel of choice for new power generation facilities for economic, operational and environmental reasons. While natural gas-fired facilities will continue to be an important part of the nation's generation portfolio, some regulated utilities are now constructing clean coal units and units powered by renewable resources, often with subsidies or under legislative mandate. These

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utilities generally have a lower cost of capital than most independent power producers and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments.

       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. Some of EME's competitors, such as electric utilities and distribution companies have their own generation capacity, including nuclear generation. These companies, generally larger than EME, have a lower cost of capital and may have competitive advantages as a result of their scale and location of their generation facilities.

Operating Segments

       EME operates in one line of business, independent power production, 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 the Homer City facilities. EME is headquartered in Irvine, California with additional offices located in Chicago, Illinois and Boston, Massachusetts.

Overview of Facilities

       As of December 31, 2005, EME's operations consisted of ownership or leasehold interests in the following operating power plants:

Power Plants			Location	Primary Electric Purchaser(3)	Fuel Type	Ownership Interest		Net Physical Capacity (in MW)	EME's Capacity Pro Rata Share (in MW)
Merchant Power Plants
	Illinois Plants (6 plants)(1)		Illinois	PJM	Coal/Oil/Gas	100	%	5,876	5,876
	Homer City(1)		Pennsylvania	PJM	Coal	100	%	1,884	1,884
Contracted Power Plants
Domestic
	Big 4 Projects
		Kern River(1)	California	SCE	Natural Gas	50	%	300	150
		Midway-Sunset(1)	California	SCE	Natural Gas	50	%	225	113
		Sycamore(1)	California	SCE	Natural Gas	50	%	300	150
		Watson	California	SCE	Natural Gas	49	%	385	189
	Westside Projects
		Coalinga(1)	California	PG&E	Natural Gas	50	%	38	19
		Mid-Set(1)	California	PG&E	Natural Gas	50	%	38	19
		Salinas River(1)	California	PG&E	Natural Gas	50	%	38	19
		Sargent Canyon(1)	California	PG&E	Natural Gas	50	%	38	19
	American Bituminous(1)		West Virginia	MPC	Waste Coal	50	%	80	40
	March Point		Washington	PSE	Natural Gas	50	%	140	70
	Sunrise(1)		California	CDWR	Natural Gas	50	%	572	286
	San Juan Mesa(1)		New Mexico	SPS	Wind	100	%(2)	120	120
International
	Doga(1)		Turkey	TEDAS	Natural Gas	80	%	180	144
		Total						10,214	9,098

(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)

EME expects to sell 25% of its ownership interest in the San Juan Mesa project to a third party in March 2006.

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(3)

Electric purchaser abbreviations are as follows:

PJM	PJM Interconnection, LLC
SCE	Southern California Edison Company
PG&E	Pacific Gas & Electric Company
MPC	Monongahela Power Company
PSE	Puget Sound Energy, Inc.
CDWR	California Department of Water Resources
SPS	Southwestern Public Service
TEDAS	Türkiye Elektrik Dagitim Anonim Sirketi

       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 the Illinois Plants. The Illinois 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:

Operating Plant or Site		Location	Leased/ Owned	Fuel	Megawatts
Electric Generating Facilities
	Crawford Station	Chicago, Illinois	owned	coal	542
	Fisk Station	Chicago, Illinois	owned	coal	326
	Joliet Unit 6	Joliet, Illinois	owned	coal	290
	Joliet Units 7 and 8	Joliet, Illinois	leased	coal	1,044
	Powerton Station	Pekin, Illinois	leased	coal	1,538
	Waukegan Station	Waukegan, Illinois	owned	coal	789
	Will County Station	Romeoville, Illinois	owned	coal	1,092	(1)
Peaking Units
	Fisk	Chicago, Illinois	owned	oil/gas	163
	Waukegan	Waukegan, Illinois	owned	oil/gas	92
	Total				5,876
Other Plant or Site
	Collins Station(2)	Grundy County, Illinois
	Crawford peaker(3)	Chicago, Illinois
	Joliet peaker(4)	Joliet, Illinois
	Calumet peaker(4)	Chicago, Illinois
	Electric Junction peaker(4)	Aurora, Illinois
	Lombard peaker(4)	Lombard, Illinois
	Sabrooke peaker(4)	Rockford, Illinois

(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)

All Collins Station units ceased operations and were decommissioned by December 31, 2004.

(3)

Peaking units ceased operations as of April 21, 2005.

(4)

Peaking units ceased operations as of December 31, 2004.

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       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. Following the lease termination, Midwest Generation permanently ceased operations at the Collins Station, effective September 30, 2004, and decommissioned the plant by December 31, 2004, and all units were permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered.

       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 to obtain capital to repay corporate debt and entered into long-term leases of the facilities from these third parties to maintain control of the use of the power plants during the terms of the leases. 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 Sales

       Energy generated at the Illinois Plants was historically sold under three power purchase agreements between Midwest Generation and Exelon Generation Company LLC (Exelon Generation), under which Exelon Generation was obligated to make capacity payments for the plants under contract and energy payments for the energy produced by the Illinois Plants and taken by Exelon Generation. The power purchase agreements began on December 15, 1999, and all were terminated by December 31, 2004.

       All the energy and capacity from the Illinois Plants is now sold under terms, including price and quantity, negotiated by Edison Mission Marketing & Trading, Inc. (EMMT), 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. Thus, EME is subject to market risks related to the price of energy and capacity from the Illinois Plants. Power generated at the Illinois Plants is generally sold into the PJM market. Capacity prices for merchant energy sales within PJM are, and are expected in the near term to remain at a level unlikely to generate significant revenue for Midwest Generation.

       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

       Prior to May 1, 2004, sales of power produced by Midwest Generation required using transmission that had to be obtained from Commonwealth Edison. As discussed previously, the Illinois Plants are now dispatched into the broader PJM market. In addition, a number of other utilities in the region participate in the MISO, where there is a single rate for transmission within the MISO.

       On November 18, 2004, the FERC issued an order eliminating regional through and out transmission rates in the region encompassed by PJM and the MISO. The effect of this order was to eliminate so-called rate pancaking between PJM and the MISO on a prospective basis. 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 its impact on transactions in the region. The mechanism required the filing of tariffs by PJM and the MISO imposing

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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 the elimination. On November 30, 2004, the FERC clarified that SECAs can be recovered for lost revenues associated with elimination of intra-RTO pancaked rates.

       The response to the November 18 and November 30 orders from the parties potentially liable for the SECAs was strongly negative. Rehearings were 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 the orders 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. Pending further orders of the FERC and/or the outcome of future hearings, 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 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, 2005, Midwest Generation leased approximately 4,400 railcars to transport the coal from the mines to the generating stations and the leases have remaining terms that range from as short as 2 months up to 15 years, with options to extend the leases or purchase some railcars at the end of the lease terms. The coal is transported nearly 1,200 miles from the mines to the Illinois Plants.

       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.

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

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

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 Homer City facilities. 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.

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

Fuel Supply

       Units 1 and 2 typically consume approximately 3.3 million to 3.5 million tons of mid-range sulfur coal per year. Approximately 90% or more of this coal is obtained under contracts with the remainder purchased in the spot market as needed. Two types of coal are purchased, ready to burn coal and raw coal. Ready to burn coal is of a quality that can be burned directly in Units 1 and 2, whereas the raw coal purchased for consumption by Units 1 and 2 must be 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 under contracts with the balance purchased in the spot market. A wet scrubber flue gas desulfurization system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control.

       In general, the coal purchased for all three units originates from mines that are within approximately 100 miles of the Homer City facilities. It is delivered to the station by truck and by rail.

       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 and coal transportation contracts.

Emission Allowances for the Homer City Facilities and Illinois Plants

       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 and the Illinois Plants. Additional allowances are purchased by EME Homer City and Midwest Generation when operations make this necessary and are sold when they have 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 sell power to Southern California Edison Company, an affiliate of EME. Because 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, EME views these

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projects collectively and refers to them as the Big 4 projects. See "Item 8. Financial Statements and Supplementary Data—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.

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's prior long-term power purchase agreement with Southern California Edison Company and its steam supply agreement with Texaco Exploration and Production Inc. (TEPI), a wholly owned subsidiary of Chevron Corporation, both expired on August 9, 2005. On August 10, 2005, Kern River Cogeneration entered into a Reformed Standard Offer No. 1 As-Available Energy and Capacity Power Purchase Agreement (RSO#1) with Southern California Edison, which will remain in effect until August 10, 2010, unless terminated earlier by Kern River Cogeneration. On August 10, 2005, Kern River Cogeneration also entered into a new five-year Steam Purchase and Sale Agreement with Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc. In addition, as of December 31, 2005, Kern River Cogeneration entered into a five-year bilateral agreement with Southern California Edison, subject to approval by the California Public Utilities Commission (CPUC). If approved by the CPUC, this contract will replace the RSO#1 with Southern California Edison, which is currently in effect.

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 Cogeneration sells both electricity to Southern California Edison, Aera Energy LLC (Aera) and Pacific Gas & Electric Company under power purchase agreements that expire in 2009 and 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 both electricity to Southern California Edison under a power purchase agreement that expires in 2007 and 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 both electricity to Southern California Edison and to BP West Coast Products LLC under power purchase agreements that expire in 2008 and 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. Sunrise Power

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entered into a long-term power purchase agreement with the California Department of Water Resources in June 2001, which expires in 2012.

March Point Cogeneration Plant

       EME owns a 50% partnership interest in March Point Cogeneration Company, which owns a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, which EME refers to as the March Point project. The March Point project consists of two phases. Phase 1 is an 80 MW gas turbine cogeneration facility and Phase 2 is a 60 MW gas turbine combined cycle facility. March Point Cogeneration sells both electricity to Puget Sound Energy, Inc. under a power purchase agreement that expires in 2011 and steam to Equilon Enterprises, LLC under a steam supply agreement that also expires in 2011. During the third quarter of 2005, EME recorded a $55 million charge to impair fully its equity investment in the March Point project due to the adverse impact on cash flows from increases in long-term natural gas prices. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Continuing Operations—Earnings from Unconsolidated Affiliates."

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 continues to sell electricity to Pacific Gas & Electric under the "as available" rates. In March 2005, the parties agreed to a five-year extension for the sale of electricity under the "as available rates." The original steam agreement remains effective on a month-to-month basis pending the execution of a long-term steam agreement that is expected to be entered into during the first quarter of 2006.

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.

San Juan Mesa Wind Power Plant

       EME owns a 100% interest in Mission Wind New Mexico, which owns a 120 MW wind ranch located near Elida, New Mexico, which EME refers to as the San Juan Mesa wind project. The project uses wind to generate electricity from turbines, which is sold to Southwestern Public Service, a subsidiary of Xcel Energy, under a 20-year power purchase agreement. The San Juan Mesa wind project achieved commercial operation in December 2005.

Doga Cogeneration Plant

       EME owns an 80% interest in Doga Enerji, which owns a 180 MW natural gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. Doga Enerji sells electricity to

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Türkiye Elektrik Dagitim Anonim Sirketi, commonly known as TEDAS, under a power purchase agreement that expires in 2019.

Business Development

Wind Business Development

       EME expects to make significant investments in wind projects during the next several years. Historically, wind projects have received federal subsidies in the form of production tax credits. In August 2005, production tax credits were made available for new wind projects placed in service by December 31, 2007 under the Energy Policy Act of 2005, referred to as EPAct 2005. EME has undertaken a number of key activities with respect to wind projects, including the following:

•

During 2005, EME entered into agreements to purchase 105 turbines for an aggregate amount of $236 million and options to acquire an additional 100 turbines.

•

In December 2005, EME completed the acquisition of the San Juan Mesa wind project. EME expects to sell 25% of its ownership interest in the San Juan Mesa wind project to a third party in March 2006.

•

In January 2006, EME completed the purchase of development rights for a 161 MW wind project in Texas, which EME refers to as the Wildorado project. This project has substantially completed site selection, permitting, and negotiations of power purchase and turbine supply agreements, and has started construction contracting. Project completion is scheduled for April 2007, with total construction costs estimated to be $270 million.

•

EME expects to receive, as a capital contribution from its parent, a 196 MW portfolio of wind projects located in Iowa and Minnesota during the first half of 2006. These projects are owned by EME's affiliate, Edison Capital.

Thermal Business Development

       EME also expects to make investments in thermal projects during the next several years. As part of this development effort, EME has begun the process of obtaining permits for two sites in Southern California for peaker plants and has responded to several requests for proposals to build or acquire generation. It is expected that the thermal projects in which EME invests will sell electricity under long-term power purchase contracts. EME is also working in partnership with a subsidiary of BP to assess the feasibility of constructing and operating an integrated gasification combined cycle facility which would burn hydrogen gas derived from petroleum coke at BP's refinery in Carson, California.

Discontinued Operations

       For a description of discontinued operations, see "Item 8. Financial Statements and Supplementary Data—Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 8. Divestitures."

Price Risk Management and Trading Activities

       EME's power marketing and trading subsidiary, EMMT, markets the energy and capacity of EME's merchant generating fleet and, in addition, trades electric power and energy and related commodity and

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financial products, including forwards, futures, options and swaps. EMMT segregates its marketing and trading activities into two categories:

•

Marketing and Fuel Management—EMMT engages in the sale of electricity and purchase of fuels (other than coal) 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. EMMT 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 EMMT's trading activities and are recorded in what EMMT calls its hedge book.

•

Trading—As part of its trading activities, EMMT 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. EMMT records these transactions in what it calls its proprietary book.

       In conducting EME's price risk management and trading activities, EMMT contracts with a number of utilities, energy companies and financial institutions. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

       To manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever possible to mitigate its exposure to counterparty risk. EME requires counterparties to pledge collateral when deemed necessary. EME uses published credit ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In addition to 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 by EME's risk management committee 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 the risk management committee. EME uses "value at risk" 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 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 reliance 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.

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       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, letters of credit or guarantees 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 1A. Risk Factors."

Significant Customer

       EME derived a significant source of its operating revenues from electric power sold into the PJM market from the Homer City facilities in the past three fiscal years and from the Illinois Plants in 2005 and 2004. Sales into the PJM pool accounted for approximately 70%, 23% and 18% of EME's consolidated operating revenues for the years ended December 31, 2005, 2004 and 2003, respectively. In 2004 and 2003, EME also 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. These power purchase agreements had all expired by the end of 2004. Exelon Generation accounted for approximately 36% and 40% of EME's consolidated operating revenues for the years ended December 31, 2004 and 2003, 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.

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.

       The Homer City property insurance program currently covers losses up to $1 billion. Under the terms of the participation agreements entered into on December 7, 2001 as part of the sale-leaseback transaction of the Homer City facilities, EME Homer City is required to maintain specified minimum insurance coverages if and to the extent that such insurance is available on a commercially reasonable basis. Although the insurance covering the Homer City facilities is comparable to insurance coverages normally carried by companies engaged in similar businesses, and owning similar properties, the insurance coverages that are in place do not meet the minimum insurance coverages required under the participation agreements. Due to the current market environment, the minimum insurance coverage is not commercially available at reasonable prices. EME Homer City has obtained a waiver under the participation agreements which permits it to maintain its current insurance coverage through June 1, 2006.

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Seasonality

       Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Illinois Plants and the Homer City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power, driven in part by higher natural gas and oil prices, this historical trend may not be applicable to quarterly revenue in the future.

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

Regulatory Matters

General

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

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

U.S. Federal Energy Regulation

       The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy (other than transmission that is "bundled" with retail sales) 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. Prior to February 8, 2006, the Securities and Exchange Commission had regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935, or PUHCA 1935, which was repealed as of that date by EPAct 2005. The enactment of PURPA and the adoption of regulations under PURPA 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 1935 for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992

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further encouraged independent power production by providing additional exemptions from PUHCA 1935 for exempt wholesale generators and foreign utility companies.

The Energy Policy Act of 2005

       A comprehensive energy bill was passed by the U.S. House and Senate in July 2005 and was signed by President Bush on August 8, 2005. Known as "EPAct 2005," this comprehensive legislation includes provisions for the repeal of PUHCA 1935 and amendments to PURPA, for merger review reform, for the introduction of new regulations regarding "Transmission Operation Improvements," for transmission rate reform, for incentives for various generation technologies and for the extension through December 31, 2007 of production tax credits for wind and other specified types of generation.

       The FERC has finalized rules to implement the Congressionally mandated repeal of PUHCA 1935, effective February 8, 2006, and enactment of the Public Utility Holding Company Act of 2005 (PUHCA 2005). The repeal of PUHCA 1935 and its replacement by PUHCA 2005 effectively eliminates many of the restrictions on outside investment in the electricity industry, investment by and transactions between utilities, and geographic constraints on utility systems. PUHCA 1935 repeal is expected to enable investment in utility systems by private equity funds, financial institutions, foreign utility companies, and other non-utility companies without the burden of registration as a "public utility holding company." It also eliminates limits on investment in non-utility operations companies that were registered holding companies under PUHCA 1935, subject to other applicable regulatory limitations, as well as geographic limits on potential utility combinations. PUHCA 2005 is primarily a "books and records access" statute and does not give the FERC any new substantive authority under the Federal Power Act or Natural Gas Act. The FERC has also issued final rules to implement the electric company merger and acquisition provisions of EPAct 2005.

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 (other than transmission that is "bundled" with retail sales), 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. Most qualifying facilities, as that term is defined in PURPA, are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators certified in accordance with the FERC's rules under PUHCA 2005 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, after EPAct 2005, generation facilities, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.

       As of December 31, 2005, 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.

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Public Utility Regulatory Policies Act of 1978

       PURPA provides two primary benefits to qualifying facilities. First, all cogeneration facilities that are qualifying facilities are exempt from certain 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 (unless, pursuant to EPAct 2005, the FERC determines that the relevant market meets certain conditions for competitive, nondiscriminatory access), and that the utilities sell back up power to the qualifying facility on a nondiscriminatory basis. The FERC's regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs. While it had been common for utilities to enter into long-term contracts with qualifying facilities in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions, increasing competition and the development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner.

       If one of the projects in which EME has an interest were to lose its status as a qualifying cogeneration facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation. As a result, the project could become subject to rate regulation by the FERC under the Federal Power Act and additional state regulation. 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 applicable to EME's facilities for maintaining qualifying facility status or that eliminated or reduced the benefits and exemptions currently enjoyed by EME's 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.

       EPAct 2005 made several important amendments to PURPA, including the elimination of qualifying facility ownership restrictions, elimination of the requirement that electric utilities enter into new contracts to purchase electricity from qualifying facilities that have access to wholesale power markets that meet specified criteria or sell energy to existing qualifying facilities in states where there is retail electricity competition and no obligation under state law to make power sales, the granting of new authority to the FERC to ensure recovery by electric utilities of all prudently incurred costs associated with purchases of energy and capacity from qualifying facilities, and certain obligations upon electric utilities for interconnection and metering for qualifying facilities. The FERC has initiated several proceedings to promulgate rules and regulations to implement the mandates of EPAct 2005 with respect to PURPA, and EME is continuing to evaluate the effect of the legislation and proposed regulations on its business activities.

       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

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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.

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 by, among other things, expanding 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 1935 to more effectively compete in the wholesale market.

       In 1996, the FERC issued Order No. 888, also known as the Open Access Rules, which require utilities to offer eligible wholesale transmission customers open access on utility transmission lines on a comparable basis to the utilities' own use of the lines and directed jurisdictional public utilities that control a substantial portion of the nation's electric transmission networks to file uniform, non-discriminatory open access tariffs containing the terms and conditions under which they would provide such open access transmission service. The FERC subsequently issued Order Nos. 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs and 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.

       On September 16, 2005, the FERC issued a Notice of Inquiry, inviting comments on (1) whether reforms are needed to the Order No. 888 pro forma open access transmission tariff and the open access transmission tariffs of public utilities to ensure that services thereunder are just, reasonable and not unduly discriminatory or preferential; (2) the implementation of the newly established section 211A of the Federal Power Act concerning the provision of open access transmission service by unregulated transmitting utilities; and (3) section 1233 of EPAct 2005, which defines the native load service obligation.

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

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Environmental Matters and Regulations

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

Employees

       At December 31, 2005, EME and its subsidiaries employed 1,745 people, including:

•

approximately 752 employees at the Illinois Plants covered by a collective bargaining agreement governing wages, certain benefits and working conditions. This collective bargaining agreement expired on December 31, 2005. A new agreement was reached with the union representing the Illinois employees, with an expiration date of December 31, 2009. Midwest Generation also has a separate collective bargaining agreement governing retirement, health care, disability and insurance benefits that expires on June 15, 2006; and

•

approximately 190 employees at the Homer City facilities covered by a collective bargaining agreement governing wages, benefits and working conditions. This collective bargaining agreement expires on December 31, 2006.

EME's Relationship with Certain Affiliated Companies

       EME is an indirect subsidiary of Edison International. Edison International is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that serves customers in California.

MEHC

       On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. During 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. The senior secured notes are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes could result in a change in control of EME. A change in control of EME could trigger an obligation of Midwest Generation to repurchase its outstanding senior secured notes at 101% of the aggregate principal amount of notes repurchased, plus accrued and unpaid interest and liquidated damages, if any, and could result in an event of default under Midwest Generation's secured term loan facility. This relationship is discussed further in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 1. General—Mission Energy Holding Company."

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ITEM 1A.    RISK FACTORS

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

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

•

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

•

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities or technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;

•

transmission congestion in and to each market area and the resulting differences in prices between delivery points;

•

the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;

•

the cost and availability of emission credits or allowances;

•

the availability, reliability and operation of competing power generation facilities, including nuclear generating plants where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;

•

weather conditions prevailing in surrounding areas from time to time; and

•

changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

       In addition, unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of time.

       There is no assurance that EME's merchant energy power plants will be successful in selling power into their markets or that the prices received for their power will generate positive cash flows. If EME's merchant energy power plants do not meet these objectives, they may not be able to generate enough cash to service their own debt and lease obligations, which could have a material adverse effect on EME. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk."

EME's financial results can be affected by changes in fuel prices, fuel transportation cost increases, and interruptions in fuel supply.

       EME's business is subject to changes in fuel costs, which may negatively affect its financial results and financial position by increasing the cost of producing power. The fuel markets can be volatile, and actual fuel prices can differ from EME's expectations.

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       Although EME attempts to purchase fuel based on its known fuel requirements, it is still subject to the risks of supply interruptions, transportation cost increases, and fuel price volatility. In addition, fuel deliveries may not exactly match energy sales, due in part to the need to purchase fuel inventories in advance for reliability and dispatch requirements. The price at which EME can sell its energy may not rise or fall at the same rate as a corresponding rise or fall in fuel costs. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk."

EME may not be able to hedge market risks effectively.

       EME is exposed to market risks through its ownership and operation of merchant energy power plants and through its power marketing business. These market risks include, among others, volatility arising from the timing differences associated with buying fuel, converting fuel into energy and delivering energy to a buyer. EME uses forward contracts and derivative financial instruments, such as futures contracts and options, to manage market risks and exposure to fluctuating electricity and fuel prices. These activities, although intended to mitigate EME's exposure, expose EME to other risks.

       The effectiveness of EME's hedging activities may depend on the amount of working capital available to post as collateral in support of these transactions, either in support of performance guarantees or as a cash margin. The amount of credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in a requirement to provide cash collateral and letters of credit in very large amounts. Without adequate liquidity to meet margin and collateral requirements, EME could be exposed to the following:

•

a reduction in the number of counterparties willing to enter into bilateral contracts, which would result in increased reliance on short-term and spot markets instead of bilateral contracts, increasing EME's exposure to market volatility; and

•

a failure to meet a margining requirement, which could permit the counterparty to terminate the related bilateral contract early and demand immediate payment for the replacement value of the contract.

       As a result of these and other factors, EME cannot predict with precision the effect that risk management decisions may have on its businesses, operating results or financial position. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."

EME is exposed to credit and performance risk from third parties under supply and transportation contracts.

       EME relies on contracts for the supply and transportation of fuel and other services required for the operation of its generation facilities. EME's operations are exposed to the risk that counterparties will not perform their obligations. If a counterparty failed to perform under a contract, EME would need to obtain alternate suppliers for its requirements of fuel or other services, which could result in higher costs or disruptions in its operations. Furthermore, EME is exposed to credit risk because damages related to a breach of contract may not be recoverable. Accordingly, the failure of a supplier to fulfill its contractual obligations could have a material adverse effect on EME's financial results.

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EME is subject to extensive energy industry regulation.

       EME's operations are subject to extensive regulation by governmental agencies. EME's projects are subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, and access to transmission. 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. Generation facilities are also subject to federal, state and local laws and regulations that govern, among other things, the geographical location, zoning, land use and operation of a project. For more information, see "Item 1. Business—Regulatory Matters."

       There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on EME's business, results of operations or financial condition, nor is there any assurance that EME or its subsidiaries will be able to obtain and comply with all necessary licenses, permits and approvals for its projects. If projects cannot comply with all applicable regulations, EME's business, results of operations and financial condition could be adversely affected.

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

       EME's operations are subject to extensive environmental regulation. EME is required to obtain and comply with conditions established by licenses, permits and other approvals in order to construct, operate or modify its facilities. Failure to comply with these requirements could subject EME to civil or criminal liability, the imposition of liens or fines, or actions by regulatory agencies seeking to curtail EME's operations. EME may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to off-site waste disposal sites that have been used in its operations.

       EME devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. Future environmental laws and regulations, and future enforcement proceedings that may be taken by environmental authorities, could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that its business, financial position and results of operations would not be materially adversely affected.

       Environmental advocacy groups and regulatory agencies in the United States have been focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their potential role in climate change. The adoption of laws and regulations to implement carbon dioxide controls could adversely affect EME's coal-fired plants. Also, coal plant emissions of nitrogen oxides and sulfur oxides, mercury and particulates are subject to increased controls and mitigation expenses. Additionally, certain of the states in which EME operates are contemplating air pollution control regulations that are more stringent than existing and proposed federal regulations. Changing environmental regulations could require EME to purchase additional emission allowances or install additional pollution control technology, and could make some units uneconomical to maintain or operate. If EME cannot comply

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with all applicable regulations, it could be required to retire or suspend operations at its facilities, or restrict or modify the operations of its facilities, and its business, results of operations and financial condition could be adversely affected. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations."

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

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

       Midwest Generation, which owns or leases the Illinois Plants, has entered into financing documents that contain restrictions on its ability to pay dividends. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

       EME is the guarantor of the Powerton and Joliet leases and is obligated under intercompany notes to make debt service payments to Midwest Generation. Each intercompany note is a general corporate obligation of EME and payments on it are made from distributions from subsidiaries and other sources of cash received by EME. Accordingly, EME must continue to make payments under the intercompany notes regardless of whether or not Midwest Generation makes distributions to EME. If EME were not able to satisfy its obligations under the intercompany notes, it would result in a default under the financing documents of EME and Midwest Generation. This could have a material adverse effect on the results of operations and cash flow of EME.

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

       As of December 31, 2005, consolidated debt of EME was $3.4 billion. In addition, EME's subsidiaries have $4.6 billion of long-term power plant lease obligations that are due over a period ranging up to 29 years. The substantial amount of consolidated debt and financial obligations presents the risk that EME and its subsidiaries might not have sufficient cash to service their indebtedness or long-term lease obligations and that the existing corporate debt, project debt and lease obligations could limit the ability of EME and its subsidiaries to grow their business, to compete effectively or operate successfully under adverse economic conditions. If EME's or a subsidiary's cash flows and capital resources were insufficient to allow it to make scheduled payments on its debt, EME or its subsidiaries might have to reduce or delay capital expenditures, sell assets, seek additional capital, or restructure or refinance the debt. The terms of EME's or its subsidiaries' debt may not allow these alternative measures, the debt or equity may not be available on acceptable terms, and these alternative measures may not satisfy all scheduled debt service obligations.

Competition could adversely affect EME's business.

       The independent power industry is characterized by numerous capable competitors, some of whom may have more extensive operating experience in the acquisition and development of power projects, larger staffs, and greater financial resources than EME does. Further, in recent years some power markets have been characterized by strong and increasing competition as a result of regulatory changes and other

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factors which can contribute to a reduction in market prices for power from time to time. These regulatory and other changes may increase competitive pressures in the markets in which EME operates.

       Newer plants owned by EME's competitors are often more efficient than EME's facilities. This may put some of EME's facilities at a competitive disadvantage to the extent that its competitors are able to produce more power from each increment of fuel than EME's facilities are capable of producing.

       Several participants in the wholesale markets, including many regulated utilities, have a lower cost of capital than most merchant generators and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. This could affect EME's ability to compete effectively in the markets in which those entities operate.

EME's parent, MEHC, depends upon cash flows from EME to service its debt.

       MEHC's principal asset is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. The senior secured notes are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes would result in a change in control of EME which could have a material adverse effect on MEHC. Dividends from EME are limited based on its earnings and cash flow, the terms of restrictions contained in EME's corporate credit facility, business and tax considerations and restrictions imposed by applicable law. For a discussion of contractual restrictions that could constrain the ability of EME's subsidiaries to pay dividends or distributions to EME, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividend Restrictions in Major Financings."

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

       The financing documents entered into by MEHC contain financial and investment covenants restricting EME and its subsidiaries. EME's certificate of incorporation binds it to the provisions in MEHC's financing documents by restricting EME's ability to enter into specified transactions and engage in specified business activities without shareholder approval. The instruments governing EME's indebtedness also contain financial and investment covenants. Restrictions contained in these documents could affect, and in some cases significantly limit or prohibit, EME and its subsidiaries' ability to, among other things, incur, refinance, and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and engage in mergers and consolidations. These restrictions may significantly impede the ability of EME and its subsidiaries to take advantage of business opportunities as they arise, to grow their business and compete effectively, or to develop and implement any refinancing plans in respect of their indebtedness. See "—EME and its subsidiaries have a substantial amount of indebtedness, including long-term lease obligations," for further discussion.

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

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EME's projects may be affected by general operating risks and hazards customary in the power generation industry. EME may not have adequate insurance to cover all these hazards.

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

•

performance below expected levels of output or efficiency;

•

interruptions in fuel supply;

•

disruptions in the transmission of electricity;

•

curtailment of operations due to transmission constraints;

•

breakdown or failure of equipment or processes;

•

imposition of new regulatory, permitting, or environmental requirements, or violations of existing requirements;

•

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

•

operator error; and

•

catastrophic events such as terrorist activities, fires, tornadoes, earthquakes, explosions, floods or other similar occurrences affecting power generation facilities or the transmission and distribution infrastructure over which power is transported.

       These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of or damage to the environment, and suspension of operations. The occurrence of one or more of the events listed above could decrease or eliminate revenues generated by EME's projects or significantly increase the costs of operating them, and could also result in EME's being named as a defendant in lawsuits asserting claims for substantial damages, potentially including environmental cleanup costs, personal injury, property damage, fines and penalties. Equipment and plant warranties and insurance may not be sufficient or effective under all circumstances to cover lost revenues or increased expenses. A decrease or elimination in revenues generated by the facilities or an increase in the costs of operating them could decrease or eliminate funds available to meet EME's obligations as they become due and could have a material adverse effect on EME. A default under a financing obligation of a project entity could result in a loss of EME's interest in the project.

EME's future acquisitions and development projects may not be successful.

       EME's long-term strategy includes the development and acquisition of electric power generation facilities. The development of a power project may require EME to expend significant amounts for preliminary engineering, permitting, legal and other expenses before EME can determine whether it will win a competitive bid, or whether a project is feasible, economically attractive or financeable. EME may not be successful in obtaining financing for its projects and may not be able to obtain sufficient equity capital, project cash flow, or additional borrowings to enable it to fund equity commitments for future projects.

       In addition to the competition already existing in the markets in which EME presently operates or may consider operating in the future, EME is likely to encounter significant competition for acquisition opportunities that may become available as a result of the consolidation of the power industry, in general, as well as the passage of EPAct 2005. EME may be unable to identify attractive acquisition or development opportunities and/or to complete and integrate them on a successful and timely basis.

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ITEM 1B.    UNRESOLVED STAFF COMMENTS

       Inapplicable.

ITEM 2.    PROPERTIES

       EME leases its principal office in Irvine, California. The office lease is for approximately 60,000 square feet and expires on December 31, 2010. EME also leases office space in Chicago, Illinois; Chantilly, Virginia; Boston, Massachusetts; and Washington D.C. The Chicago lease is for approximately 41,000 square feet and expires on December 31, 2014. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010 and has been subleased since May 2001. The Boston lease is for approximately 37,000 square feet and expires on July 31, 2007. The Washington D.C. lease is immaterial.

       The following table shows, as of December 31, 2005, the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of EME's income before tax or is one in which EME has an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project.

Description of Properties

Plant	Location	Interest In Land	Plant Description
Homer City	Pittsburgh, Pennsylvania	Owned	Coal-fired generation facility
Illinois Plants	Northeast Illinois	Owned	Coal, oil/gas-fired generation facilities
Kern River	Oildale, California	Leased	Natural gas-fired cogeneration facility
Midway-Sunset	Fellows, California	Leased	Natural gas-fired cogeneration facility
Sunrise	Fellows, California	Leased	Combined cycle generation facility
Sycamore	Oildale, California	Leased	Natural gas-fired cogeneration facility
Watson	Carson, California	Leased	Natural gas-fired cogeneration facility

ITEM 3.    LEGAL PROCEEDINGS

       No material legal proceedings are presently pending against EME.

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

       Inapplicable.

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Pursuant to Form 10-K's General Instruction G(3), the following information is included as an additional item in Part I of this annual report:

EXECUTIVE OFFICERS OF THE REGISTRANT

       Listed below are EME's current executive officers and their ages and positions as of December 31, 2005.

Name, Position and Age	Position Held Continuously Since	Term Expires
Theodore F. Craver, Jr., 54 President and Chief Executive Officer	2005	2006
W. James Scilacci, 50 Senior Vice President and Chief Financial Officer	2005	2006
Raymond W. Vickers, 63 Senior Vice President and General Counsel	1999	2006
Guy F. Gorney, 51 Vice President	2005	2006
Paul Jacob, 44 Vice President	2000	2006
John P. Finneran, Jr., 46 Vice President	1999	2006
Gerald P. Loughman, 50 Vice President	2005	2006
Jenene Wilson, 62 Vice President	2001	2006

Business Experience

       Below is a description of the principal business experience during the past five years of each of the executive officers named above.

Mr. Craver has been a director of Edison Mission Energy since January 2001 and chairman of the board, president and chief executive officer since January 2005. Mr. Craver has been chief executive officer of Edison Capital since January 2005. From January 2002 until January 2005, Mr. Craver was executive vice president of Edison International. Mr. Craver was senior vice president from January 2000 to December 2001, and was chief financial officer and treasurer of Edison International from January 2000 until January 2005. Mr. Craver was chairman of the board and chief executive officer of Edison Enterprises from September 1999 to August 2001. Mr. Craver also serves as a director of Health Net and a Trustee of the Autry National Center.

Mr. Scilacci has been senior vice president and chief financial officer of Mission Energy Holding Company and Edison Mission Energy since March 2005. Mr. Scilacci was senior vice president and chief financial officer of Southern California Edison Company from January 2003 to March 2005 and vice president and chief financial officer of Southern California Edison Company from January 2000 to December 2002.

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Mr. Vickers has been senior vice president and general counsel of Edison Mission Energy since March 1999.

Mr. Gorney has been vice president of Edison Mission Energy since August 2000, and president of Midwest Generation EME, LLC since June 2005. Mr. Gorney was vice president of Operations, Maintenance & Fuels for the Americas Region from January 2002 to January 2005, vice president of Operations Planning from August 2000 to January 2002 and regional vice president of Operations Planning from December 1999 to August 2000.

Mr. Jacob has been vice president of Edison Mission Energy since September 2000 and president of Edison Mission Marketing & Trading since February 2001. Mr. Jacob was vice president of Edison Mission Marketing & Trading from September 2000 to February 2001. Mr. Jacob was the executive vice president of Citizens Power, LLC from 1994 to September 2000. Citizens Power, LLC was merged with and into Edison Mission Marketing & Trading on September 1, 2000.

Mr. Finneran has been vice president of Business Management for Edison Mission Energy since April 2005. Mr. Finneran was vice president of Edison Mission Energy and vice president Finance, Americas from July 2002 to April 2005. Mr. Finneran was vice president of Edison Mission Energy and regional vice president of Finance, Americas Region from September 1999 to July 2002.

Mr. Loughman has been vice president of Development for Edison Mission Energy since March 2005. Mr. Loughman was director of Business Planning & Development for Southern California Edison Company since January 2003 and was vice president for Business Development, Americas Region for Edison Mission Energy since January 2000.

Ms. Wilson has been vice president of Human Resources for Edison Mission Energy since December 2001. Prior to joining Edison Mission Energy, Ms. Wilson served as vice president of Human Resources at MySmart Solutions since October 2000.

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PART II

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

       All the outstanding common stock of EME is, as of the date hereof, owned by MEHC, which is a wholly owned subsidiary of Edison Mission Group Inc., a wholly owned subsidiary of Edison International. There is no market for the common stock. Dividends on the common stock will be paid when declared by EME's board of directors. EME made cash dividend payments totaling $360 million in 2005, which included the $305 million declared in 2004, and $74 million in 2004. A total of $11.5 million in dividends was paid in January 2006. Dividends from EME may be limited based on its earning and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax considerations, and restrictions imposed by applicable law. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividend Restrictions in Major Financings" for more information about dividend restrictions contained in EME's corporate credit facility.

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ITEM 6.    SELECTED FINANCIAL DATA

       The selected financial data was derived from EME's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report. EME's international operations are accounted for as discontinued operations, except the Doga project in Turkey, which is accounted for as an equity investment. Continuing operations include EME's Illinois Plants and Homer City facilities, energy trading, equity investments in power projects primarily located in California, the Doga project, corporate interest expense and general and administrative expenses. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Continuing Operations" and "—Results of Discontinued Operations" for more information about the sale of EME's international operations and loss on lease termination, asset impairment and other charges in 2005, 2004 and 2003, and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Continuing Operations—Cumulative Effect of Change in Accounting Principle" for further explanation of accounting changes.

		Years Ended December 31,
		2005			2004			2003			2002			2001(1)
		(in millions)
INCOME STATEMENT DATA
Operating revenues		$	2,248		$	1,639		$	1,778		$	1,713		$	1,771
Operating expenses
	Fuel, plant operations and plant operating lease		1,279			1,299			1,334			1,292			1,256
	Loss on lease termination, asset impairment and other charges and credits		7			989			304			60			59
	Depreciation and amortization		124			144			154			146			174
	Administrative and general		154			149			138			118			132
			1,564			2,581			1,930			1,616			1,621
Operating income (loss)			684			(942	)		(152	)		97			150
Equity in income from unconsolidated affiliates			227			215			245			197			334
Impairment loss on equity method investment			(55	)		—			—			—			—
Interest and other income			65			52			2			14			83
Interest expense			(296	)		(293	)		(302	)		(312	)		(428	)
Income (loss) from continuing operations before income taxes and minority interest			625			(968	)		(207	)		(4	)		139
Provision (benefit) for income taxes			221			(401	)		(114	)		(23	)		75
Minority interest			—			(1	)		(2	)		(2	)		(2	)
Income (loss) from continuing operations			404			(568	)		(95	)		17			62
Income (loss) from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004 and loss on disposal of $1.1 billion in 2001), net of tax			29			690			124			22			(1,198	)
Income (loss) before accounting change			433			122			29			39			(1,136	)
Cumulative effect of change in accounting, net of tax			(1	)		—			(9	)		(14	)		15
Net income (loss)		$	432		$	122		$	20		$	25		$	(1,121	)

(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.

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	As of December 31,
	2005		2004(2)(3)		2003(2)		2002		2001
	(in millions)
BALANCE SHEET DATA
Assets	$	6,788	$	6,828	$	12,078	$	11,092	$	10,743
Current liabilities		819		944		1,136		1,356		656
Long-term obligations		3,303		3,507		2,919		3,022		3,978
Preferred securities		—		—		—		281		254
Shareholder's equity		1,844		1,682		1,903		1,693		1,577

(2)

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

(3)

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

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

This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements 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 and include any statement that does not directly relate to a historical or current fact. Other information distributed by EME that is incorporated in this MD&A, or that refers to or incorporates this MD&A, may also contain forward-looking statements. In this MD&A and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, 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. See "Item 1. Business—Forward-Looking Statements" and "Item 1A. Risk Factors" for a discussion of some of the risks, uncertainties and other important factors that could cause results to differ, or otherwise could impact EME or its subsidiaries. Additional information about risks and uncertainties is contained throughout this MD&A. Readers are urged to read this entire annual report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made 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.

       This MD&A is presented in five sections:

	Page
Management's Overview; Critical Accounting Estimates	32
Results of Operations	38
Liquidity and Capital Resources	52
Market Risk Exposures	75
Recent Development	87

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING ESTIMATES

Management's Overview

Introduction

       EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own all or an interest in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. As of December 31, 2005, EME's subsidiaries and affiliates owned or leased interests in 19 domestic operating power plants.

       EME's subsidiaries and affiliates have financed the development and construction or acquisition of its projects by capital contributions from EME and the incurrence of so-called project financed debt obligations by its subsidiaries and affiliates owning the operating facilities. These project level debt obligations are generally structured as non-recourse to EME, with several exceptions, including EME's

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guarantee of the Powerton and Joliet leases as part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Illinois Plants. As a result, these project level debt obligations have structural priority with respect to revenues, cash flows and assets of the project companies over debt obligations incurred by EME itself. In this regard, EME has, itself, borrowed funds to make the equity contributions required of it for its projects and for general corporate purposes. Since EME does not, itself, directly own any revenue producing generation facilities, it depends for the most part on cash distributions from its projects to meet its debt service obligations, to pay for general and administrative expenses and to pay dividends to its parent, MEHC. Distributions to EME from projects are generally only available after all current debt service obligations at the project level have been paid and are further restricted by contractual restrictions on distributions included in the documentation evidencing the project level debt obligations.

EME Restructuring Activities

       During 2004 and early 2005, EME sold most of its international assets. These international assets, except for the Doga project, which has not been sold, are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations.

       EME implemented management and organizational changes in 2005 to streamline its reporting relationships and eliminate its regional management structure. In addition, EME and its affiliate, Edison Capital, have combined their management teams located in Irvine, California and combined their wind development efforts. In this regard, EME and Edison Capital have entered into a services agreement effective December 26, 2005. Under this services agreement, all existing employees of Edison Capital on the effective date of the agreement were transferred to EME, and thereafter EME provides accounting, legal, tax, management and administrative services to Edison Capital and its subsidiaries of the type previously provided by the transferred employees. Edison Capital and its subsidiaries continue to operate as independent legal entities separate and apart from EME, and EME has not assumed any obligation for the performance of any of Edison Capital's obligations to any party, whether with respect to its investment portfolio or with respect to any of the creditors of Edison Capital or its subsidiaries.

Merchant Operations

       The majority of EME's power plants is located in the PJM control area and sells power under short-term contracts. These power plants are known as merchant power plants since the generation is not sold under long-term contracts. EME's revenues and the results of operations of its merchant power plants depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, fuel oil, coal, natural gas and associated transportation costs in the market areas where EME's merchant plants are located. EME's income from continuing operations increased substantially during 2005 from its merchant operations due to higher wholesale energy prices driven largely by increases in the market price of natural gas and oil. The average market price during 2005 at the Northern Illinois Hub (related to the Illinois Plants) increased to $46.39 per megawatt hour (MWh), compared to the average market prices at "Into ComEd" and at the Northern Illinois Hub of $29.52 per MWh during 2004.

Energy Trading Activities

       EME seeks to generate profit by utilizing the commercial platform of its subsidiary, EMMT, to engage in trading activities in those markets where merchant power plants are located. EMMT trades power, fuel and transmission primarily in the eastern power grid using financial products available over

33

the counter, through exchanges and from independent system operators. EME's earnings from energy trading activities were $195 million during 2005. Volatile market conditions during 2005, driven by increased prices for natural gas and oil and warmer summer temperatures, have created favorable conditions for EMMT's trading strategies in 2005 compared to 2004. This trading activity is limited by the risk management policies of EME, including a limit on value at risk. During 2005, EME's maximum value at risk associated with trading of over-the-counter products and exchange-traded products was $1.9 million, using a 95% confidence interval and assuming a one-day holding period. As of December 31, 2005, margin and collateral posted to support trading activities of EMMT was approximately $75 million. This amount includes collateral posted independent system operators as well as initial and mark-to-market margin posted for outstanding volumes of futures and over-the-counter contracts. Income from trading activities will vary substantially from period to period depending on market conditions.

Business Development Plans

Wind Business Development

       EME expects to make significant investments in wind projects during the next several years. Historically, wind projects have received federal subsidies in the form of production tax credits. In August 2005, production tax credits were made available for new wind projects placed in service by December 31, 2007 under EPAct 2005. EME has undertaken a number of key activities with respect to wind projects, including the following:

•

During 2005, EME entered into agreements to purchase 105 turbines for an aggregate amount of $236 million and options to acquire an additional 100 turbines.

•

In December 2005, EME completed the acquisition of the San Juan Mesa wind project. EME expects to sell 25% of its ownership interest in the San Juan Mesa wind project to a third party in March 2006.

•

In January 2006, EME completed the purchase of development rights for the Wildorado project. This project has substantially completed site selection, permitting, and negotiations of power purchase and turbine supply agreements, and has started construction contracting. Project completion is scheduled for April 2007, with total construction costs estimated to be $270 million.

•

EME expects to receive, as a capital contribution from its parent, a 196 MW portfolio of wind projects located in Iowa and Minnesota during the first half of 2006. These projects are owned by EME's affiliate, Edison Capital.

Thermal Business Development

       EME also expects to make investments in thermal projects during the next several years. As part of this development effort, EME has begun the process of obtaining permits for two sites in Southern California for peaker plants and has responded to several requests for proposals to build or acquire generation. It is expected that the thermal projects in which EME invests will sell electricity under long-term power purchase contracts. EME is also working in partnership with a subsidiary of BP to assess the feasibility of constructing and operating an integrated gasification combined cycle facility which would burn hydrogen gas derived from petroleum coke at BP's refinery in Carson, California.

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Critical Accounting Estimates

Introduction

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

Derivative Financial Instruments and Hedging Activities

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

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

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

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

       EME enters into master agreements and other arrangements in conducting price risk management and trading activities with a right of setoff in the event of bankruptcy or default by the counterparty.

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These types of transactions are reported net in the balance sheet in accordance with Financial Accounting Standards Board Interpretation No. 39, "Offsetting Amounts Related to Certain Contracts."

Impairment of Long-Lived Assets

       EME follows Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). EME evaluates long-lived assets whenever indicators of impairment exist. This accounting standard requires that if the undiscounted expected future cash flow from a company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be recognized in the financial statements. The amount of impairment is determined by the difference between the carrying amount and fair value of the asset.

       The assessment of impairment is a critical accounting estimate because significant management judgment is required to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. Factors that EME considers important, which could trigger an impairment, include operating losses from a project, projected future operating losses, the financial condition of counterparties, or significant negative industry or economic trends. During 2005, 2004 and 2003, EME recorded impairment charges of $55 million, $35 million and $304 million, respectively, related to specific assets included in continuing operations. See "Results of Continuing Operations—Earnings from Consolidated Operations—Illinois Plants" and "Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Impairment Loss on Equity Method Investment" and "—Asset Impairment Charges."

Off-Balance Sheet Financing

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

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

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Contract Indemnities

       During 2004, EME sold a majority of its international operations. The asset sale agreements contain indemnities from EME to the purchasers, including indemnification for pre-closing environmental liabilities and for pre-closing foreign taxes imposed with respect to operations of the assets prior to the sale. EME also provided an indemnity to IPM (a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%)) for matters arising out of the exercise by one of EME's project partners of a purported right of first refusal. The right of first refusal matter has been submitted to arbitration, with hearings having been conducted during February 2006. It is expected that a decision of the arbitration panel will be rendered in the coming months. At December 31, 2005, EME recorded an estimated liability related to these matters of $122 million.

       In addition, Midwest Generation has agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in a supplemental agreement. See "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Commercial Commitments." Midwest Generation engaged an independent actuary during 2004 with extensive experience in performing asbestos studies to estimate future losses based on its claims experience and other available information. In calculating future losses, the actuary made various assumptions, including, but not limited to, the settlement of future claims under the supplemental agreement with Commonwealth Edison as described above, the distribution of exposure sites, and that the filing date of asbestos claims will not be after 2045. At December 31, 2005, Midwest Generation recorded a liability related to this contract indemnity of $67 million.

Income Taxes

       Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109), requires the asset and liability approach for financial accounting and reporting for deferred income taxes. EME uses the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. See Note 13 to the "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements" for additional details.

       As part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes in each jurisdiction in which it operates. This process involves estimating actual current tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within EME's consolidated balance sheet. In addition, estimated taxes for uncertain tax positions are accrued and included in other long-term liabilities in the consolidated balance sheet.

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

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RESULTS OF OPERATIONS

Introduction

       This section discusses operating results in 2005, 2004 and 2003. Continuing operations include EME's Illinois Plants and Homer City facilities, energy trading, equity investments in power projects primarily located in California, corporate interest expense and general and administrative expenses. Discontinued operations include all of EME's international operations, except the Doga project. This section also discusses the effect of new accounting pronouncements on EME's consolidated financial statements. It is organized under the following headings:

	Page
Net Income Summary	38
Results of Continuing Operations	39
Results of Discontinued Operations	49
Related Party Transactions	50
New Accounting Pronouncements	50
Proposed Accounting Pronouncements	51

Net Income Summary

       Net income is comprised of the following components:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Income (loss) from continuing operations	$	404		$	(568	)	$	(95	)
Income from discontinued operations		29			690			124
Cumulative changes in accounting principle		(1	)		—			(9	)
Net Income	$	432		$	122		$	20

       EME's 2005 loss from a change in accounting principle resulted from the adoption of a new accounting standard for conditional asset retirement obligations. EME's 2003 loss from a change in accounting principle resulted from the adoption of a new accounting standard for asset retirement obligations. See "Results of Continuing Operations—Cumulative Effect of Change in Accounting Principle" for further discussion of these changes in accounting.

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       EME's income (loss) from continuing operations during the three year period ended December 31, 2005 included the following items:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Loss on lease termination, asset impairment and other charges (see "—Results of Continuing Operations—Earnings from Consolidated Operations—Illinois Plants," and "—Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Asset Impairment Charges")	$	—		$	(608	)	$	(186	)
Impairment loss on equity method investment (see "—Results of Continuing Operations—Earning from Unconsolidated Affiliates—Impairment Loss on Equity Method Investment")	$	(34	)	$	—		$	—
Gain on sale of assets (see "—Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Four Star Oil & Gas")	$	—		$	29		$	—

       The 2005 increase in income from continuing operations after considering the above items, was primarily attributable to higher energy trading income and higher wholesale energy prices at the Illinois Plants. The 2004 decrease in income from continuing operations after considering the above items, was primarily due to the absence of 2004 earnings from Four Star Oil & Gas (sold on January 7, 2004) compared to 2003, lower earnings from the Homer City facilities due to lower generation and higher fuel costs related to emission allowances, and lower earnings from the Illinois Plants primarily due to a $56 million charge related to a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999. Further details regarding income from continuing operations is set forth below.

Results of Continuing Operations

Overview

       EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of power generated from the Illinois Plants and the Homer City facilities. 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 accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

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

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       The following section provides a summary of the operating results for the three years ended December 31, 2005 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Income (Loss) before Taxes and Minority Interest
(Earnings/Losses)(1)
	Consolidated operations
	Illinois Plants	$	547		$	(881	)	$	(112	)
	Homer City		74			77			137
	Energy Trading(2)		195			23			34
	Doga		—			6			13
	Other		(3	)		2			3
	Unconsolidated affiliates
	Big 4 projects		158			142			135
	Four Star Oil & Gas		—			—			43
	Sunrise		29			28			35
	March Point		9			17			10
	Impairment loss on equity method investment		(55	)		—			—
	Doga		7			1			—
	Asset impairment charges		—			—			(59	)
	Other		12			11			—
			973			(574	)		239
	Corporate interest expense		(270	)		(283	)		(292	)
	Corporate administrative and general		(126	)		(149	)		(138	)
	Gain on sale of assets		—			43			—
	Loss on early extinguishment of debt		(4	)		—			—
	Corporate interest income and other expense, net		52			(5	)		(16	)
	Income (Loss) from Continuing Operations Before Income Taxes and Minority Interest	$	625		$	(968	)	$	(207	)

(1)

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

(2)

Income from energy trading represents the gains recognized from price volatility associated with the purchase and sale of contracts for electricity, fuels and transmission. The indirect cost of energy trading is included in administrative and general expenses.

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Earnings from Consolidated Operations

Illinois Plants

			Years Ended December 31,
			2005			2004			2003
			(in millions)
Operating Revenues
	Energy revenues		$	1,445		$	758		$	667
	Capacity revenues			27			289			380
	Other revenues			10			15			8
	Net losses from price risk management			(53	)		(4	)		(3	)
	Total operating revenues			1,429			1,058			1,052
Operating Expenses
	Fuel(1)			383			408			401
	Sale of emission allowances(2)			(56	)		(26	)		(10	)
	Plant operations			351			379			333
	Plant operating leases			75			84			104
	Depreciation and amortization			99			116			116
	Loss on lease termination, asset impairment and other charges			7			989			245
	Administrative and general			19			1			7
	Total operating expenses			878			1,951			1,196
Operating Income (Loss)				551			(893	)		(144	)
Other Income (Expense)
	Interest income from note receivable from EME			113			113			113
	Interest expense and other			(117	)		(101	)		(81	)
	Total other income (expense)			(4	)		12			32
Income (Loss) Before Taxes			$	547		$	(881	)	$	(112	)
Statistics—Coal-Fired Generation(3)
	Generation (in GWh):
		Merchant		30,953			17,133			13,561
		Power purchase agreement		—			13,435			13,949
		Total coal-fired generation		30,953			30,568			27,510
	Equivalent availability(4)			79.6%			84.4%			82.7%
	Forced outage rate(5)			7.8%			5.4%			7.7%
	Average energy price/MWh:
		Merchant	$	46.68		$	31.11		$	26.57
		Power purchase agreement	$	—		$	17.46		$	18.08
		Total coal-fired generation(6)	$	46.68		$	24.84		$	22.27
	Average fuel costs/MWh		$	12.40		$	11.60		$	11.28

(1)

The Illinois Plants purchased NOx emission allowances from the Homer City facilities at fair market value. Purchases were $5 million in 2005 and none in 2004 and 2003. These purchases are included in fuel costs.

(2)

The Illinois Plants sold excess SO2 emission allowances to the Homer City facilities at fair market value. Sales to the Homer City facilities were $61 million in 2005, $26 million in 2004 and $10 million in 2003. These sales reduced

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operating expenses. In addition, EME eliminated $6 million of intercompany profit in 2005 on emission allowances sold but not yet used by the Homer City facilities at December 31, 2005.

(3)

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

(4)

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

(5)

Midwest Generation refers to unplanned maintenance as a forced outage.

(6)

The average energy price in prior year periods represents an average, weighted by generation, of energy prices earned by the merchant coal plants and energy prices earned under the power purchase agreements with Exelon Generation. Due to the structure of the power purchase agreements with Exelon Generation (with higher capacity prices and lower energy prices), the composite data in 2004 and 2003 is not directly comparable to 2005 merchant energy prices.

       Earnings from the Illinois Plants increased $1.4 billion in 2005 compared to 2004, and losses increased $769 million in 2004 compared to 2003. Discrete items affecting the income (loss) of the Illinois Plants include:

•

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

•

$29 million loss recorded in 2004 and $245 million loss in 2003 related to the impairment of small peaking units in Illinois.

       Earnings from the Illinois Plants, excluding the above discrete items, increased $438 million in 2005 compared to 2004, and decreased $24 million in 2004 compared to 2003. The 2005 increase in earnings is due to the following factors:

•

substantially higher energy revenues resulting from increased average energy prices;

•

higher fuel costs in 2004 during the period the Collins Station operated (operations ceased effective September 30, 2004);

•

an increase in sales of excess SO2 emission allowances in 2005, as compared to 2004, primarily due to higher market prices;

•

the absence in 2005 as compared to 2004 of a $56 million charge recorded during the fourth quarter of 2004 related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999. See "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Indemnities Provided as Part of the Acquisition of the Illinois Plants"; and

•

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

       Partially offset by:

•

lower capacity revenues resulting from the expiration of the power purchase agreements with Exelon Generation;

•

higher plant operation costs due to higher planned maintenance;

•

higher coal costs attributable to higher coal prices primarily due to price escalation under coal and transportation agreements; and

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•

higher interest expense primarily attributable to a full year of interest expense in 2005 versus approximately eight months of interest expense in 2004 related to debt issued in April 2004 by Midwest Generation, which owns or leases the Illinois Plants.

       The 2004 decrease in earnings is due to the following factors:

•

a $56 million charge related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999; and

•

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

       Partially offset by:

•

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

•

higher sales of excess SO2 emission allowances due to higher market prices; and

•

higher energy revenues in 2004 from increased merchant generation at higher prices which offset the lower capacity payments received under the power purchase agreements with Exelon Generation. Accordingly, energy revenues increased $90 million and capacity revenues decreased $91 million during 2004 compared to 2003.

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

       Losses from price risk management were $53 million, $4 million and $3 million in 2005, 2004 and 2003, respectively. The 2005 increase was primarily due to significant price increases in 2005 on power contracts that did not qualify for hedge accounting under SFAS No. 133 resulting in losses. These energy contracts were entered into to hedge the price risk related to projected sales of power through 2007 (sometimes referred to as economic hedges). The 2005 losses included $30 million related to the 2005 hedge contracts which related to activities reported as energy revenues and $23 million unrealized losses related to 2006 and 2007 hedge contracts. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

       The earnings (losses) of the Illinois Plants included interest income of $113 million for each of the three years ended December 31, 2005, 2004 and 2003 related to loans to EME. In August 2000, Midwest Generation entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes. See "Management's Overview; Critical Accounting Estimates—Critical Accounting Estimates—Off-Balance Sheet Financing" for further discussion of these leases.

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Homer City

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Operating Revenues
	Energy revenues	$	632		$	486		$	491
	Capacity revenues		18			28			30
	Net gains (losses) from price risk management		(58	)		(17	)		10
	Total operating revenues		592			497			531
Operating Expenses
	Fuel(1)		288			215			199
	Sale of emission allowances(2)		(4	)		—			(6	)
	Plant operations		112			88			82
	Plant operating leases		102			102			102
	Depreciation and amortization		16			15			15
	Administrative and general		6			3			1
	Total operating expenses		520			423			393
Operating Income			72			74			138
Other Income (Expense)
	Interest expense		(1	)		(1	)		(2	)
	Interest and other income (expense)		3			4			1
	Total other income (expense)		2			3			(1	)
Income Before Taxes		$	74		$	77		$	137
Statistics
	Generation (in GWh)		13,637			13,292			14,403
	Equivalent availability(3)		85.2%			85.1%			88.7%
	Forced outage rate(4)		4.8%			5.3%			5.1%
	Average energy price/MWh	$	46.29		$	36.20		$	34.02
	Average fuel costs/MWh	$	21.08		$	16.15		$	13.79

(1)

The Homer City facilities purchased SO2 emission allowances from the Illinois Plants at fair market value. Purchases were $61 million in 2005, $26 million in 2004 and $10 million in 2003. These purchases are included in fuel costs.

(2)

The Homer City facilities sold excess NOx emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $5 million in 2005 and none in 2004 and 2003. These sales reduced operating expenses. In addition, EME eliminated $1 million of intercompany profit in 2005 on emission allowances sold but not yet used by the Illinois Plants at December 31, 2005.

(3)

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

(4)

Homer City refers to unplanned maintenance as a forced outage.

       Earnings from Homer City decreased $3 million in 2005 compared to 2004 and $60 million in 2004 compared to 2003. The 2005 decrease was primarily attributable to increased losses related to price risk management activities (explained below), mostly offset by higher energy margin including the effect of higher wholesale energy prices, higher coal prices, higher priced SO2 emission allowances and higher

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plant operations costs. Homer City had higher planned equipment maintenance costs in 2005 compared to 2004 and incurred costs in 2005 related to the replacement of the catalyst for the pollution control equipment. Included in fuel costs were $81 million, $42 million and $18 million in 2005, 2004 and 2003, respectively, related to the net cost of SO2 emission allowances. See "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for more information regarding the price of SO2 allowances.

       The 2004 decrease in earnings is primarily due to increased losses related to price risk management activities and an increase in fuel costs from higher priced SO2 emission allowances. Homer City also had lower energy revenues in 2004 due to lower generation and availability, which was mostly offset by increased average energy prices. Lower generation in 2004 was caused by a temporary interruption of coal deliveries under contracts with four fuel suppliers to the Homer City facilities. As a result of these interruptions, Homer City reduced generation during off-peak periods when power prices were lower and purchased coal from alternative suppliers at spot prices which were substantially higher than the contract prices from these four fuel suppliers. In addition, the Homer City facilities had an unplanned outage at Unit 1 in February 2004.

       The average energy price earned by Homer City in 2005 and 2004 was $46.29/MWh and $36.20/MWh, respectively, compared to the average real-time market price at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system) for the same periods of $54.80/MWh and $40.79/MWh, respectively. Homer City's average energy price was lower than the average real-time market price due to: (1) hedge contracts having been entered into in prior periods when market prices were lower, and (2) an increase in the differential in market prices at the PJM West Hub (the settlement point under forward contracts) versus the Homer City busbar. The increase in the differential is referred to as a widening of the basis between these PJM locations. Homer City hedges its energy price risk at PJM West Hub and retains the risk that the basis between PJM West Hub and Homer City widens. See "Market Risk Exposures—Commodity Price Risk—Basis Risk."

       Losses from price risk management activities increased $41 million in 2005 compared to 2004 and $27 million in 2004 compared to 2003. The 2005 and 2004 increases were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. Homer City recorded net gains (losses) of approximately $(63) million, $(14) million and $11 million in 2005, 2004 and 2003, respectively, representing the amount of cash flow hedges' ineffectiveness. The ineffective losses from Homer City were primarily attributable to an increase in the difference between energy prices at PJM West Hub and the energy prices at the Homer City busbar. Included in the 2005 ineffective losses was $44 million related to the 2006 and 2007 hedge contracts. Partially offsetting the ineffective losses were gains in 2005 primarily related to futures contracts that did not qualify for hedge accounting under SFAS No. 133. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

Seasonal Disclosure

       Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Illinois Plants and the Homer City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power, driven in part by higher natural gas and oil prices, this historical trend may not be applicable to quarterly revenue in the future.

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Energy Trading

       EME seeks to generate profit by utilizing the commercial platform of its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission primarily in the eastern power grid using products available over-the-counter, through exchanges and from independent system operators. Earnings from energy trading activities were $195 million, $23 million and $34 million in 2005, 2004 and 2003, respectively. Volatile market conditions in 2005, driven by increased prices for natural gas and oil and warmer summer temperatures, have created favorable conditions for EMMT's trading strategies in 2005 compared to 2004 and 2003.

Earnings from Unconsolidated Affiliates

Big 4 Projects

       EME owns partnership investments (50% ownership or less) in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company. These projects have similar economic characteristics and have been used, collectively, to secure bond financing by Edison Mission Energy Funding Corp., a special purpose entity. Due to similar economic characteristics and the bond financing related to EME's equity investments in these projects, EME evaluates them collectively and refers to them as the Big 4 projects.

       Earnings from the Big 4 projects increased $16 million in 2005 compared to 2004, and $7 million in 2004 compared to 2003. The 2005 and 2004 changes in earnings were largely due to higher energy prices in 2005 and 2004. The impact of the higher energy prices in 2005 was partially offset by lower earnings from the Kern River project during 2005, compared to 2004, resulting from the expiration of the project's long-term power purchase and steam supply agreements in August 2005 and an unplanned outage in December 2005. The impact of the higher energy prices in 2004 was partially offset by planned outages at the Sycamore Cogeneration plant and the Watson Cogeneration plant in March 2004.

       Earnings from the Big 4 projects are net of interest expense of $9 million, $12 million and $16 million in 2005, 2004 and 2003, respectively, with respect to Edison Mission Energy Funding.

Four Star Oil & Gas

       EME's share of earnings from its ownership interest in Four Star Oil & Gas Company was $43 million in 2003, with no earnings from its ownership interest recorded in 2004 and 2005 due to the sale of its interest in the company. The 2004 earnings include the gain on sale of 100% of EME's stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, on January 7, 2004. Proceeds from the sale were approximately $100 million. EME recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

Sunrise

       Earnings from the Sunrise project increased $1 million in 2005 from 2004 and decreased $7 million in 2004 from 2003. The 2005 increase was primarily the result of higher energy revenues attributable to increased dispatch. The 2004 decrease primarily resulted from higher interest expense due to the completion of the Sunrise project financing in September 2003.

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March Point

       Earnings from March Point decreased $8 million in 2005 from 2004 and increased $7 million in 2004 from 2003. The 2005 decrease is primarily attributable to earnings recorded for a full year in 2004, compared to nine months in 2005 due to the impairment charge recorded during the third quarter of 2005 discussed below. The increase in 2004 was attributable to higher operating revenues in 2004 because there was no planned outage in 2004, as there was in 2003.

Impairment Loss on Equity Method Investment

       During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash flows. The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest. The March Point project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil) under a steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements purchased at current market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the first nine months of 2005, long-term natural gas prices increased substantially, thereby adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a $55 million charge during the third quarter of 2005.

Doga

       In accordance with Statement of Financial Accounting Standards Interpretation No. 46(R), "Consolidation of Variable Interest Entities," EME determined that it was not the primary beneficiary of the Doga project and, accordingly, deconsolidated this project at March 31, 2004. Beginning April 1, 2004, EME recorded its interest in the Doga project on the equity method basis of accounting. Earnings from the Doga project were $7 million in 2005 and $1 million in 2004, representing earnings from the final three quarters of 2004. Revenues included in EME's consolidated statements of income from the Doga project were $29 million in 2004, representing revenues from the first quarter of 2004, and $124 million in 2003. Earnings from the Doga project were $6 million in 2004, representing earnings from the first quarter of 2004, and $13 million in 2003. Earnings decreased in 2004 from 2003 primarily due to lower generation and higher major maintenance costs due also to plant outages and the write-off of uncollectible receivables.

       On August 17, 2005, EME entered into a purchase agreement to sell its 80% interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim Isletme ve Ticaret Limited Sirketi, which would have acquired an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which would have acquired a 50% interest in the Doga project. The transaction did not close and has been terminated.

Asset Impairment Charges

       Asset impairment charges were none in 2005 and 2004 and $59 million in 2003. In 2003, EME recorded a $59 million loss related to the write-down of EME's investments in the Brooklyn Navy Yard and Gordonsville projects due to their planned dispositions. These projects have since been sold.

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Other

       Earnings from other projects (unconsolidated affiliates) increased $11 million in 2004 from 2003. The 2004 increase was primarily due to higher earnings from the TM Star project due to mark-to-market losses recorded in 2003.

Seasonal Disclosure

       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.

Corporate Interest Expense

	Years Ended December 31,
	2005		2004		2003
	(in millions)
Interest expense to third parties	$	157	$	170	$	179
Interest expense to Midwest Generation		113		113		113
Total corporate interest expense	$	270	$	283	$	292

Corporate Administrative and General Expenses

       Administrative and general expenses decreased $23 million in 2005 from 2004, and increased $11 million in 2004 from 2003. The 2005 decrease was primarily due to decreased use of third-party consultants, partially offset by charges for severance and related costs of $13 million recorded in 2005. The 2004 increase was primarily due to increased use of third-party consultants and higher performance-based compensation, partially offset by lower debt restructuring costs.

Loss on Early Extinguishment of Debt

       Loss on early extinguishment of debt was $4 million in 2005. Extinguishment of debt consisted of a $4 million loss related to the early repayment of EME's junior subordinated debentures recorded during the first quarter of 2005.

Corporate Interest Income and Other, Net

       Corporate interest income and other (net) increased $57 million in 2005 from 2004 and $11 million in 2004 from 2003. The 2005 increase was primarily attributable to higher interest income resulting from higher average cash balances in 2005 compared to 2004 due largely to cash proceeds received from the sale of international operations.

Income Taxes

       EME's income tax provision (benefit) from continuing operations was $221 million in 2005, $(401) million in 2004 and $(114) million in 2003. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "—Liquidity and Capital Resources—EME's

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Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes which was recorded as a reduction of income taxes during the second quarter of 2005. During the second quarter of 2004, EME recorded a tax benefit of $368 million primarily relating to the loss on the termination of the Collins Station lease, and during the first quarter of 2004, EME recorded a tax provision of $18 million relating to the sale of 100% of its stock in Edison Mission Energy Oil & Gas, which in turn held interests in Four Star Oil & Gas.

Cumulative Effect of Change in Accounting Principle

Statement of Financial Accounting Standard Interpretation No. 47

       Effective December 31, 2005, EME adopted Financial Accounting Standard Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). For further discussion of FIN 47 refer to "New Accounting Pronouncements." EME recorded a $1 million, after tax, decrease to net income as the cumulative effect of the adoption of FIN 47.

Statement of Financial Accounting Standards No. 143

       Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

Results of Discontinued Operations

       Income from discontinued operations, net of tax, was $29 million in 2005, $690 million in 2004 and $124 million in 2003. During 2005, EME completed the following sales:

•

On January 10, 2005, EME sold its 50% equity interest in the CBK hydroelectric power project to CBK Projects B.V. Proceeds from the sale were approximately $104 million.

•

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM. Proceeds from the sale were approximately $20 million.

       The aggregate after-tax gain on sale of the projects mentioned above was $5 million. During the third quarter of 2005, EME recorded tax benefit adjustments of $28 million, which resulted from completion of the 2004 federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004. During the fourth quarter of 2005, EME recorded an after-tax charge of $25 million related to a tax indemnity for a project sold to IPM in December 2004. This charge related to an adverse tax court ruling in Spain, which the local company plans to appeal.

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       During 2004, EME completed the following sales:

•

On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser.

•

On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) to IPM. The sale of MECIBV included the sale of EME's interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV was $2.0 billion in cash. EME retained its ownership of the subsidiaries associated with the Lakeland project and some inactive subsidiaries.

       The aggregate after-tax gain on the sale of the above-referenced international projects was $533 million.

Previously Reported Discontinued Operations

Lakeland Project

       EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. Payments received to date include £13 million (approximately $24 million) in March 2005 and £18 million (approximately $31 million) in February 2006. EME estimates remaining distributions (expected by the end of 2006) will be approximately $100 million and the 2006 net income impact of distributions to be approximately $75 million. Because taxes in the United Kingdom have not been finalized, the actual amount of distributions and the impact on net income may vary materially from the above estimates. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

Related Party Transactions

       Specified EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to Southern California Edison Company and others under the terms of long-term power purchase agreements. Sales by these partnerships to Southern California Edison Company under these agreements amounted to $932 million, $824 million and $754 million in 2005, 2004 and 2003, respectively.

New Accounting Pronouncements

       In November 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 151, "Inventory Costs." SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current- period charges. Further, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. Unallocated overheads must be recognized as an expense in the period in which they are incurred. SFAS No. 151 is effective for inventory costs incurred beginning in the first quarter of 2006. EME does not expect the adoption of this standard to have a material impact on EME's consolidated financial statements.

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       In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations (AROs), an interpretation of SFAS 143. This interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. This interpretation became effective as of December 31, 2005 for EME. EME identified conditional AROs related to asbestos removal and disposal costs at its owned Illinois Plants (buildings and power plant facilities) and retired structures leased at the Powerton Station. EME recorded a $1 million, after tax, charge as a cumulative effect adjustment for asbestos removal and disposal activities associated with retired Powerton structures that are currently scheduled for demolition in 2007. EME has not recorded a liability related to the owned structures because it cannot reasonably estimate fair value of the obligation at this time. The range of time over which EME may settle this obligation in the future (demolition or other method) is sufficiently large to not allow for the use of expected present value techniques.

       A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. EME is required to implement the new standard in the first quarter of 2006, and will apply the modified prospective transition method. Under the modified prospective method, the new accounting standard will be applied; effective January 1, 2006, to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements will not be restated under this method. The new accounting standard will result in the recognition of expense for all stock-based compensation awards where EME previously used the intrinsic value method of accounting, at times resulting in no recognition of expense for stock-based compensation.

Proposed Accounting Pronouncements

       In July 2005, the FASB published an exposure draft of a proposed interpretation that seeks to clarify the accounting for uncertain tax positions. An enterprise would be required to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. The proposed effective date is January 1, 2007. The FASB is expected to issue a final interpretation in the first quarter of 2006. EME is currently assessing the potential impact of the proposed interpretation on its results of operations and financial condition.

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LIQUIDITY AND CAPITAL RESOURCES

       The following discussion of liquidity and capital resources is organized in the following sections:

	Page
EME's Liquidity	52
Midwest Generation Financing	52
Capital Expenditures	53
EME's Historical Consolidated Cash Flow	53
Credit Ratings	55
Margin, Collateral Deposits and Other Credit Support for Energy Contracts	56
EME's Liquidity as a Holding Company	56
Dividend Restrictions in Major Financings	58
Contractual Obligations, Commitments and Contingencies	60
Off-Balance Sheet Transactions	64
Environmental Matters and Regulations	67

EME's Liquidity

       At December 31, 2005, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.3 billion, and EME had available the full amount of borrowing capacity under its $98 million corporate credit facility. EME's consolidated debt at December 31, 2005 was $3.4 billion. In addition, EME's subsidiaries had $4.6 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 29 years.

Midwest Generation Financing

       On December 15, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of Midwest Generation's existing credit facility, previously amended and restated on April 18, 2005. The credit facility, as previously amended and restated, provided for approximately $343 million of first priority secured institutional term loans due in 2011 and $500 million of first priority secured revolving credit, working capital facilities, $200 million due in 2009 and $300 million due in 2011, with a lender option to require prepayment in 2010.

       The refinancing consisted of, among other things, a reduction in the interest rate applicable to the term loan and the working capital facilities, and a modification of financial covenants. After giving effect to the refinancing, all the facilities carry a lower interest rate of LIBOR + 1.75%. The maturity date of the repriced term loan remains 2011. The previously existing working capital facilities were combined into one $500 million facility, maturing in 2011, with a lender option to require prepayment in 2010. Also, as part of the refinancing, Midwest Generation's financial covenants were modified, with its consolidated interest coverage ratio for the immediately preceding four consecutive fiscal quarters required to be at least 1.40 to 1 (increased from 1.25 to 1), and its secured leverage ratio for the 12-month period ended on the last day of the immediately preceding fiscal quarter required to be no greater than 7.25 to 1 (reduced from 8.75 to 1).

       As of December 31, 2005, Midwest Generation had $333 million outstanding under its term loan and a $500 million working capital facility available for working capital requirements, including credit support for hedging activities. As of December 31, 2005, approximately $175 million was utilized under the working capital facility.

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Capital Expenditures

       The estimated capital and construction expenditures of EME's subsidiaries are $390 million, $175 million and $28 million for 2006, 2007 and 2008, respectively. The non-environmental portion of these expenditures relates to the construction of the Wildorado project, purchase of turbines, upgrades to dust collection/mitigation systems and the coal handling system, ash removal improvements and various other projects. EME plans to finance these expenditures with existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the estimated expenditures are environmental expenditures of $8 million for 2006, $6 million for 2007 and $6 million for 2008. The environmental expenditures relate to environmental projects such as selective catalytic reduction system improvements at the Homer City facilities and projects at the Illinois Plants. EME's subsidiaries may also make substantial additional capital expenditures as described under "—Environmental Matters and Regulations—Federal—United States of America—Clean Air Act—Mercury Regulation."

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

       Net cash provided by (used in) operating activities:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Continuing operations	$	(266	)	$	(384	)	$	422
Discontinued operations		20			(434	)		243
	$	(246	)	$	(818	)	$	665

       Cash used in operating activities from continuing operations decreased $118 million in 2005 from 2004, and increased $806 million in 2004 from 2003. The 2005 decrease was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and improved operating income in 2005. Partially offsetting these decreases was $656 million in required margin and collateral deposits in 2005 for EME's price risk management and trading activities, compared to $30 million in 2004. This increase in margin and collateral deposits resulted from an increase in forward market prices.

       The 2004 increase was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and tax-allocation payments of $7 million paid to Edison International during 2004, compared to $112 million in tax-allocation payments received by EME from Edison International during 2003. EME made tax payments in 2004 primarily attributable to taxable income resulting from the sale of the Four Star Oil & Gas and Brooklyn Navy Yard projects. In addition, distributions from unconsolidated affiliates were lower during 2004 compared to 2003, primarily because the 2003 distributions included $151 million from completion of the Sunrise project financing in September 2003.

       Cash used in operating activities from discontinued operations in 2004 primarily reflects settlement of working capital items from the sale of EME's international operations. Cash provided by operating activities from discontinued operations in 2003 primarily reflects operating income and distributions from international projects.

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Consolidated Cash Flows from Financing Activities

       Net cash used in financing activities:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Continuing operations	$	(753	)	$	4		$	(475	)
Discontinued operations		—			(144	)		153
	$	(753	)	$	(140	)	$	(322	)

       Cash used in financing activities from continuing operations increased $757 million in 2005 from 2004, and decreased $479 million in 2004 from 2003. The 2005 increase was primarily attributable to dividend payments made to MEHC of $360 million during 2005, compared to $74 million during 2004. The increase was also due to the repayment of EME's junior subordinated debentures of $150 million in January 2005 and a $302 million repayment in April 2005 related to Midwest Generation's existing term loan.

       The 2004 decrease was due to a higher level of borrowings in 2004 compared to 2003, primarily due to the $1 billion secured notes and $700 million term loan facility received by Midwest Generation in April 2004 partially offset by the repayment of the $800 million secured loan at EME's subsidiary, Mission Energy Holdings International, Inc., $693 million related to Edison Mission Midwest Holdings' credit facility and $28 million related to the Coal and Capex facility in April 2004.

       Cash used in financing activities from discontinued operations in 2004 primarily reflects repayment of debt and dividends to minority shareholders. Cash provided by financing activities from discontinued operations in 2003 primarily reflects borrowings by Contact Energy to finance the acquisition of a power station, partially offset by repayment of debt.

Consolidated Cash Flows from Investing Activities

       Net cash provided by (used in) investing activities:

	Years Ended December 31,
	2005			2004		2003
	(in millions)
Continuing operations	$	(130	)	$	2,712	$	(98	)
Discontinued operations		5			18		(413	)
	$	(125	)	$	2,730	$	(511	)

       Cash used in investing activities from continuing operations increased $2.8 billion in 2005 from 2004, and decreased $2.8 billion in 2004 from 2003. The 2005 increase was primarily attributable to proceeds of $2.7 billion received in 2004 from the sale of most of EME's international operations and $154 million paid towards the purchase price for the San Juan Mesa project in December 2005. Proceeds of $124 million received in 2005 from the sale of EME's 25% investment in the Tri Energy project and EME's 50% investment in the CBK project were comparable to proceeds of $118 million received in 2004, described below. Partially offsetting the 2005 increase were net purchases of marketable securities of $43 million in 2005, compared to $120 million in 2004.

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       The 2004 decrease was due to a combination of the following:

•

$2.7 billion in proceeds received in 2004 from the sale of most of EME's international operations.

•

$118 million in proceeds received in 2004 from the sale of EME's stock in Edison Mission Energy Oil & Gas and the sale of EME's 50% partnership interest in the Brooklyn Navy Yard project.

•

a reduction in investment in new plant and equipment. EME invested $55 million and $81 million in property and equipment during 2004 and 2003, respectively.

•

$23 million in equity contributions to the Sunrise project in 2003.

       Cash used in investing activities from discontinued operations in 2003 primarily reflects $275 million paid in 2003 by Contact Energy for an acquisition of a power station and investments in new plant and equipment.

Credit Ratings

Overview

       The credit ratings for EME and its subsidiaries, Midwest Generation and EMMT, are as follows:

		Moody's Rating	S&P Rating
EME		B1	B+
Midwest Generation:
	First priority senior secured rating	Ba3	BB-
	Second priority senior secured rating	B1	B
EMMT		Not Rated	B+

       EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

       EME does not have any "rating triggers" contained in subsidiary financings that would result in it or EME being required to make equity contributions or provide additional financial support to its subsidiaries.

Credit Rating of EMMT

       The Homer City sale-leaseback documents restrict EME Homer City's ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from Standard & Poor's or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through EMMT; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback

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owner participant has not indicated that it intends to revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between EMMT and EME Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

       In connection with entering into contracts in support of EME's price risk management and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME's subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. Because the credit ratings of EMMT and EME are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these price risk management and trading activities. At December 31, 2005, EMMT had deposited $543 million in cash with brokers in margin accounts in support of futures contracts and had deposited $155 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $12 million in support of commodity contracts at December 31, 2005.

       Margin and collateral deposits increased substantially in 2005 due to higher wholesale energy prices and increased megawatt hours hedged under contracts requiring margin and collateral. Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2005, if wholesale energy prices increase further or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of December 31, 2005 could increase during 2006 by approximately $180 million using a 95% confidence level.

       Midwest Generation has a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois Plants. At December 31, 2005, Midwest Generation had borrowed $170 million under this credit facility to finance margin advances to EMMT of $328 million. The balance of the margining advances by Midwest Generation was provided through cash on hand. In addition, EME has cash on hand and a $98 million working capital facility to provide credit support to subsidiaries. See "EME's Liquidity as a Holding Company" for further discussion.

EME's Liquidity as a Holding Company

Overview

       At December 31, 2005, EME had corporate cash and cash equivalents and short-term investments of $1.1 billion to meet liquidity needs. See "—EME's Liquidity." Cash distributions from EME's subsidiaries and partnership investments, and unused capacity under its corporate credit facility, represent EME's major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "—Dividend Restrictions in Major Financings."

       As security for its obligations under its corporate credit facility, EME has pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects are deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

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       At December 31, 2005, EME also had available $74 million under Midwest Generation EME, LLC's $100 million letter of credit facility with Citibank, N.A., as Issuing Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation EME is required to deposit cash in a bank account in order to cash collateralize any letters of credit that may be outstanding under the facility. The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings, which in turn owns 100% of Midwest Generation, LLC.

Historical Distributions Received By EME

       The following table is presented as an aid in understanding the cash flow of EME's continuing operations and its various subsidiary holding companies which depend on distributions from subsidiaries and affiliates to fund general and administrative costs and debt service costs of recourse debt.

		Years Ended December 31,
		2005			2004		2003
		(in millions)
Distributions from Consolidated Operating Projects:
	Edison Mission Midwest Holdings (Illinois Plants)	$	330	(1)	$	88	$	—
	EME Homer City Generation L.P. (Homer City facilities)		86			61		128	(2)
	Holding companies of other consolidated generating projects		1			1		1
Distributions from Unconsolidated Operating Projects:
	Edison Mission Energy Funding Corp. (Big 4 Projects)(3)		122			108		98
	Four Star Oil & Gas Company		—			—		21
	Sunrise Power Company		20			19		69	(4)
	Holding company for Doga project		17			15		—
	Holding companies for Westside projects		17			18		25
	Holding companies of other unconsolidated operating projects		5			3		7
Total Distributions		$	598		$	313	$	349

(1)

In April 2005, EME made a capital contribution of $300 million which was used to repay debt. Subsequent to December 31, 2005, Edison Mission Midwest Holdings made an additional distribution of $185 million.

(2)

Excludes $34 million distributed by EME Homer City from additional cash on hand due to accelerated payments received from EMMT.

(3)

The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy Funding Corp.

(4)

Includes $59 million of the $151 million proceeds from the Sunrise project financing. EME has classified the remaining $92 million as a return of capital.

Intercompany Tax-Allocation Agreement

       EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient

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taxable income in order to be able to utilize EME's tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME paid tax-allocation payments to Edison International of $129 million and $7 million during 2005 and 2004, respectively.

Dividend Restrictions in Major Financings

General

       Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

       Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements for the twelve months ended December 31, 2005:

Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation, LLC (Illinois Plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	6.40 to 1
Midwest Generation, LLC (Illinois Plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	1.99 to 1
EME Homer City Generation L.P. (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.59 to 1

Midwest Generation Financing Restrictions on Distributions

       Midwest Generation is bound by the covenants in its credit agreement and indenture as well as certain covenants under the Powerton-Joliet lease documents with respect to Midwest Generation making payments under the leases. These covenants include restrictions on the ability to, among other things, incur debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines of business or engage in transactions for any speculative purpose. In addition, the credit agreement contains financial covenants binding on Midwest Generation.

Covenants in Credit Agreement

       In order for Midwest Generation to make a distribution, it must be in compliance with covenants specified under its credit agreement. Compliance with the covenants in its credit agreement includes maintaining the following two financial performance requirements:

•

At the end of each fiscal quarter, Midwest Generation's consolidated interest coverage ratio for the immediately preceding four consecutive fiscal quarters must be at least 1.40 to 1. The consolidated interest coverage ratio is defined as the ratio of consolidated net income (plus or minus specified amounts as set forth in the credit agreement), to consolidated interest expense (as more specifically defined in the credit agreement).

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•

Midwest Generation's secured leverage ratio for the 12-month period ended on the last day of the immediately preceding fiscal quarter may be no greater than 7.25 to 1. The secured leverage ratio is defined as the ratio of the aggregate principal amount of Midwest Generation secured debt plus all indebtedness of a subsidiary of Midwest Generation, to the aggregate amount of consolidated net income (plus or minus specified amounts as set forth in the credit agreement).

       In addition, Midwest Generation's distributions are limited in amount. Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of its excess cash flow (as defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributed to the equity contribution equals the amount of the equity contribution. Because EME made a $300 million equity contribution to Midwest Generation on April 19, 2005, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to that equity contribution equals $300 million. After taking into account Midwest Generation's most recent distribution in January 2006, $177 million of the equity contribution is still available for this purpose. To the extent Midwest Generation makes a distribution which is not fully attributed to an equity contribution, Midwest Generation is required to make concurrently with such distribution an offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the amount attributed to the equity contribution.

       In January 2005, Midwest Generation made a distribution of $61 million and, as required under its credit agreement, Midwest Generation offered to prepay $20 million of the term loan, of which $5 million was accepted by certain lenders and repaid on January 24, 2005. Midwest Generation subsequently made a voluntary prepayment, as provided under the credit agreement, of $15 million on January 28, 2005. In April 2005 and October 2005, Midwest Generation made additional distributions of $109 million and $160 million, respectively.

Covenants in Indenture

       Midwest Generation's indenture contains restrictions on its ability to make a distribution substantially similar to those in the credit agreement. Failure to achieve the conditions required for distributions will not result in a default under the indenture, nor does the indenture contain any other financial performance requirements.

EME Homer City (Homer City facilities)

       EME Homer City completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, EME Homer City must be in compliance with the covenants specified in the lease agreements, including the following financial performance requirements measured on the date of distribution:

•

At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period (taken as a whole) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of EME Homer City less amounts paid for operating expenses, required capital expenditures, taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service reserve letter of credit.

       At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid. The senior rent service coverage ratio (discussed above) projected for each of the prospective two twelve-month periods must be greater than 1.7 to 1. No more than two rent default events may have occurred, whether or not cured. A rent default event is defined as the failure to pay the equity portion of the rent within five business days of when it is due.

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EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries

       EME's corporate credit facility contains covenants that restrict its ability, and the ability of several of its subsidiaries, to make distributions. This restriction binds the subsidiaries through which EME owns the Westside projects, the Sunrise project, the Illinois Plants, the Homer City facilities and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME if an event of default were to occur and be continuing under EME's corporate credit facility after giving effect to the distribution.

       In addition, EME granted a security interest in an account into which all distributions received by it from the Big 4 projects are deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

       As of December 31, 2005, EME had no borrowings outstanding under this credit facility.

Contractual Obligations, Commitments and Contingencies

Contractual Obligations

       The following table summarizes EME's significant consolidated contractual obligations as of December 31, 2005.

				Payments Due by Period (in millions)
Contractual Obligations		Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years
Long-term debt(1)		$	4,921	$	328	$	1,088	$	1,006	$	2,499
Operating lease obligations			4,755		362		717		693		2,983
Purchase obligations:
	Capital improvements		8		8		—		—		—
	Turbine commitments(2)		192		114		78		—		—
	Fuel supply contracts		1,031		367		487		158		19
	Gas transportation agreements		100		8		16		16		60
	Coal transportation		680		226		301		153		—
	Other contractual obligations		55		12		22		21		—
Employee benefit plan contribution(3)			15		15		—		—		—
Total Contractual Obligations		$	11,757	$	1,440	$	2,709	$	2,047	$	5,561

(1)

See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 11. Financial Instruments" for additional details. Table assumes long-term debt is held to maturity, except the Midwest Generation senior secured notes which are assumed to be held until 2014. Amount also includes interest payments over applicable period of the debt.

(2)

See "Management's Overview—Business Development Plans—Wind Business Development" for additional details.

(3)

Amount includes estimated contribution for pension plans and postretirement benefits other than pensions. The estimated contributions beyond 2006 are not available. For more information, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 14. Employee Benefit Plans."

Operating Lease Obligations

       At December 31, 2005, minimum operating lease payments were primarily related to long-term leases for the Powerton and Joliet Stations and the Homer City facilities. During 2000, EME entered into sale-leaseback transactions for two power facilities, the Powerton and Joliet coal-fired stations located in

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Illinois, with third-party lessors. During the fourth quarter of 2001, EME entered into a sale-leaseback transaction for the Homer City coal-fired facilities located in Pennsylvania, with third-party lessors. Total minimum lease payments during the next five years are $337 million in 2006, $336 million in 2007, $337 million in 2008, $336 million in 2009, $325 million in 2010, and the minimum lease payments due after 2010 are $2.9 billion. For further discussion, see "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions."

Fuel Supply Contracts

       At December 31, 2005, EME's subsidiaries had contractual commitments to purchase coal. The remaining contracts' lengths range from one year to seven years. The minimum commitments are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses.

Gas Transportation Agreements

       At December 31, 2005, EME had a contractual commitment to transport natural gas. EME is committed to pay its share of fixed monthly capacity charges under its gas transportation agreement, which has a remaining contract length of 12 years.

Coal Transportation Agreements

       At December 31, 2005, EME's subsidiaries had contractual commitments for the transport of coal to their respective facilities, with remaining contract lengths that range from one year to six years. Midwest Generation's primary contract is with Union Pacific Railroad (and various delivering carriers) which extends through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, Midwest Generation's contractual obligations for transportation are based on coal volumes set forth in their fuel supply contracts. EME Homer City commitments under its agreements are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses. Only a portion of total coal shipments to the Homer City facilities are shipped by rail. Trucking remains the predominant mode of transportation for coal shipments to the Homer City facilities.

Commercial Commitments

Introduction

       EME and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, standby letters of credit, guarantees of debt and indemnifications.

Standby Letters of Credit

       As of December 31, 2005, standby letters of credit aggregated to $33 million and were scheduled to expire as follows: 2006—$28 million and 2007—$5 million.

Guarantees and Indemnities

Tax Indemnity Agreements—

       In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in

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Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins Station lease in April 2004, Midwest Generation will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

Indemnities Provided as Part of the Acquisition of the Illinois Plants—

       In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison take all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

       Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were between 185 and 195 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2005. Midwest Generation had recorded a $67 million liability at December 31, 2005 related to this matter.

       The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities—

       In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. Payments would be triggered under this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.

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Indemnities Provided under Asset Sale Agreements—

       The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. The right of first refusal matter has been submitted to arbitration, with hearings having been conducted during February 2006. It is expected that a decision of the arbitration panel will be rendered in the coming months. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At December 31, 2005, EME had recorded a liability of $122 million related to these matters.

       In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

       On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which held a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through January 2007. At December 31, 2005, EME had recorded a liability of $8 million related to this indemnity.

Capacity Indemnification Agreements—

       EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project's power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of December 31, 2005, if payment were required, would be $124 million. EME has not recorded a liability related to these indemnities.

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Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

       A subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement. This agreement runs through 2007. EME believes there is sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Contingencies

Litigation

       EME experiences routine litigation in the normal course of its business. Pending routine litigation is not expected to have a material adverse effect on EME's consolidated financial position or results of operations.

Tax Matters

       EME is, and may in the future be, under examination by tax authorities with respect to positions it takes in connection with the filing of its tax returns. Matters raised upon tax audit may involve substantial amounts, which, if resolved unfavorably, could possibly be material, though EME does not believe such an unfavorable resolution is likely to occur. In EME's opinion, it is unlikely that the resolution of any such tax audit matters will have a material adverse effect upon EME's financial condition or results of operations.

Off-Balance Sheet Transactions

Introduction

       EME has off-balance sheet transactions in two principal areas: investments in projects accounted for under the equity method and operating leases resulting from sale-leaseback transactions.

Investments Accounted for under the Equity Method

       EME has a number of investments in power projects that are accounted for under the equity method. Under the equity method, the project assets and related liabilities are not consolidated in EME's consolidated balance sheet. Rather, EME's financial statements reflect its investment in each entity and it records only its proportionate ownership share of net income or loss. These investments are of three principal categories.

       Historically, EME has invested in qualifying facilities, those which produce electrical energy and steam, or other forms of energy, and which meet the requirements set forth in the Public Utility Regulatory Policies Act. See "Item 1. Business—Regulatory Matters—U.S. Federal Energy Regulation." Prior to the passage of the Energy Policy Act of 2005, these regulations limited EME's ownership interest in qualifying facilities to no more than 50% due to EME's affiliation with Southern California Edison, a public utility. For this reason, EME owns a number of domestic energy projects through partnerships in which it has a 50% or less ownership interest.

       Entities formed to own these projects are generally structured with a management committee or board of directors in which EME exercises significant influence but cannot exercise unilateral control

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over the operating, funding or construction activities of the project entity. EME's energy projects have generally secured long-term debt to finance the assets constructed and/or acquired by them. These financings generally are secured by a pledge of the assets of the project entity, but do not provide for any recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's project investment, but would generally not require EME to contribute additional capital. At December 31, 2005, entities which EME has accounted for under the equity method had indebtedness of $601 million, of which $287 million is proportionate to EME's ownership interest in these projects.

Sale-Leaseback Transactions

       EME has entered into sale-leaseback transactions related to the Powerton and Joliet Stations in Illinois and the Homer City facilities in Pennsylvania. See "—Contractual Obligations, Commitments and Contingencies—Contractual Obligations—Operating Lease Obligations." Each of these transactions was completed and accounted for in accordance with Statement of Financial Accounting Standards No. 98, which requires, among other things, that all the risk and rewards of ownership of assets be transferred to a new owner without continuing involvement in the assets by the former owner other than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original acquisition of the assets or to repay indebtedness previously incurred for the acquisition. In each of these transactions, the assets were sold to and then leased from owner/lessors owned by independent equity investors. In addition to the equity invested in them, these owner/lessors incurred or assumed long-term debt, referred to as lessor debt, to finance the purchase of the assets. The lessor debt takes the form generally referred to as secured lease obligation bonds.

       EME's subsidiaries account for these leases as financings in their separate financial statements due to specific guarantees provided by EME or another one of its subsidiaries as part of the sale-leaseback transactions. These guarantees do not preclude EME from recording these transactions as operating leases in its consolidated financial statements, but constitute continuing involvement under SFAS No. 98 that precludes EME's subsidiaries from utilizing this accounting treatment in their separate subsidiary financial statements. Instead, each subsidiary continues to record the power plants as assets in a similar manner to a capital lease and records the obligations under the leases as lease financings. EME's subsidiaries, therefore, record depreciation expense from the power plants and interest expense from the lease financing in lieu of an operating lease expense which EME uses in preparing its consolidated financial statements. The treatment of these leases as an operating lease in its consolidated financial statements in lieu of a lease financing, which is recorded by EME's subsidiaries, resulted in an increase in consolidated net income by $72 million, $73 million and $81 million in 2005, 2004 and 2003, respectively.

       The lessor equity and lessor debt associated with the sale-leaseback transactions for the Powerton, Joliet and Homer City assets are summarized in the following table:

Power Station(s)	Acquisition Price		Equity Investor	Original Equity Investment in Owner/Lessor		Amount of Lessor Debt at December 31, 2005		Maturity Date of Lessor Debt
	(in millions)
Powerton/Joliet	$	1,367	PSEG/ Citigroup, Inc.	$	238	$	333.5 Series A 769.7 Series B	2009 2016
Homer City		1,591	GECC/ Metropolitan Life Insurance Company(1)		798	$	282.0 Series A 524.3 Series B	2019 2026

PSEG—PSEG Resources, Inc.
GECC—General Electric Capital Corporation

(1)

On September 29, 2005, GECC sold 10% of its investment to Metropolitan Life Insurance Company.

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       The operating lease payments to be made by each of EME's subsidiary lessees are structured to service the lessor debt and provide a return to the owner/lessor's equity investors. Neither the value of the leased assets nor the lessor debt is reflected in EME's consolidated balance sheet. In accordance with generally accepted accounting principles, EME records rent expense on a levelized basis over the terms of the respective leases. To the extent that EME's cash rent payments exceed the amount levelized over the term of each lease, EME records prepaid rent. At December 31, 2005 and 2004, prepaid rent on these leases was $395 million and $277 million, respectively. To the extent that EME's cash rent payments are less than the amount levelized, EME reduces the amount of prepaid rent.

       In the event of a default under the leases, each lessor can exercise all its rights under the applicable lease, including repossessing the power plant and seeking monetary damages. Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which generally declines over time and in the case of default may be reduced by the proceeds arising from the sale of the repossessed power plant. A default under the terms of the Powerton and Joliet or Homer City leases could result in a loss of EME's ability to use such power plant and would trigger obligations under EME's guarantee of the Powerton and Joliet leases. These events could have a material adverse effect on EME's results of operations and financial position.

       EME's minimum lease obligations under its power related leases are set forth under "—Contractual Obligations, Commitments and Contingencies—Contractual Obligations—Operating Lease Obligations."

EME's Obligations to Midwest Generation

       The proceeds, in the aggregate amount of approximately $1.4 billion, received by Midwest Generation from the sale of the Powerton and Joliet plants, described above under "Sale-Leaseback Transactions," were loaned to EME. EME used the proceeds from this loan to repay corporate indebtedness. Although interest and principal payments made by EME to Midwest Generation under this intercompany loan assist in the payment of the lease rental payments owing by Midwest Generation, the intercompany obligation does not appear on EME's consolidated balance sheet. This obligation was disclosed to the credit rating agencies at the time of the transaction and has been included by them in assessing EME's credit ratings. The following table summarizes principal payments due under this intercompany loan:

Years Ending December 31,	Principal Amount		Interest Amount		Total
	(in millions)
2006	$	3	$	113	$	116
2007		3		113		116
2008		4		112		116
2009		4		112		116
2010		5		112		117
Thereafter		1,343		512		1,855
Total	$	1,362	$	1,074	$	2,436

       EME funds the interest and principal payments due under this intercompany loan from distributions from EME's subsidiaries, including Midwest Generation, cash on hand, and amounts available under corporate lines of credit. A default by EME in the payment of this intercompany loan could result in a shortfall of cash available for Midwest Generation to meet its lease and debt obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME.

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Environmental Matters and Regulations

Introduction

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

       Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects, which may involve significant capital expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by regulatory authorities.

Federal—United States of America

Clean Air Act

Clean Air Interstate Rule—

       On May 12, 2005, the Clean Air Interstate Rule (CAIR) was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address ozone attainment issues by reducing regional nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions. The CAIR reduces the current Clean Air Act Title IV Phase II SO2 emissions allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR also reduces regional NOx emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The CAIR has been challenged in court by state, environmental and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation.

       EME expects that compliance with the CAIR and the regulations and revised state implementation plans developed as a consequence of the CAIR will result in increased capital expenditures and operating expenses. Given the uncertainty of the requirements that will need to be implemented and the options available to meet the NOx and SO2 reductions fleetwide, EME at this time cannot accurately estimate the cost to meet these obligations. EME's approach to meeting these obligations will consist of a blending of capital expenditure and emission allowance purchases that will be based on an ongoing assessment of the dynamics of its market conditions.

Mercury Regulation—

       The Clean Air Mercury Rule (CAMR), published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual nationwide cap will be 38 tons. Emissions of mercury are to be reduced primarily by taking advantage of mercury

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reductions achieved by reducing SO2 and NOx emissions under the CAIR. In the second phase, which is to take effect in 2018, coal-fired power plants will be subject to a lower annual cap, which will reduce emissions nationwide to 15 tons. States may join the trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's suggested cap-and-trade program. Any program adopted by a state must be approved by the United States Environmental Protection Agency (US EPA).

       Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated as a hazardous air pollutant pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards. Litigation has been filed challenging the US EPA's rescission action and claiming that the agency should have imposed technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR. As a result of these challenges, the CAMR rules and timetables may change.

       If Illinois and Pennsylvania implement the CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, EME may have the option to purchase mercury emission allowances, to install pollution control equipment, to otherwise alter its operations to reduce mercury emissions, or to implement some combination thereof. If EME were to implement environmental control technology at its Homer City facilities instead of purchasing allowances to comply with the CAMR and other Clean Air Act developments described herein, it currently estimates capital expenditures for such improvements to be approximately $350 million to $400 million in the 2006-2010 timeframe. However, because the mercury state implementation plans are not due until the fourth quarter of 2006 and such plans may not adopt the CAMR's cap-and-trade program, and because EME cannot predict the outcome of the legal challenge to the CAMR and the US EPA's decision not to regulate mercury emissions pursuant to Section 112 of the federal Clean Air Act, the full impact of this regulation currently cannot be assessed. Additional capital costs, particularly for the Illinois coal units, related to these regulations could be required in the future and they could be material. EME's approach to meeting these obligations will continue to be based upon an ongoing assessment of applicable legal requirements and market conditions.

National Ambient Air Quality Standards—

       Ambient air quality standards for ozone and fine particulate matter were adopted by the US EPA in July 1997. These standards were challenged in the courts, and on March 26, 2002, the United States Court of Appeals for the District of Columbia Circuit upheld the US EPA's revised ozone and fine particulate matter ambient air quality standards.

       The US EPA designated non-attainment areas for the 8-hour ozone standard on April 30, 2004, and for the fine particulate standard on January 5, 2005. Almost all of EME's facilities are located in counties that have been identified as being in non-attainment with both standards. States are required to revise their implementation plans for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised state implementation plans are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates. Any additional obligations on EME's facilities to further reduce their emissions of SO2, NOx and fine particulates to address local non-attainment with the 8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans.

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Depending upon the final standards that are adopted, EME may incur substantial costs or experience other financial impacts resulting from required capital improvements or operational changes.

       On January 17, 2006, the US EPA proposed revisions to its fine particulate standard. Under the proposal, the annual standard would remain the same but the 24-hour fine particulate standard would be significantly lowered. The US EPA is under court order to issue a final rule in December 2006. If the US EPA retains its proposed new 24-hour standard or lowers the annual standard, states may be required to impose further emission reductions beyond what would be necessary to meet the existing standards. Although EME may incur substantial costs or experience financial impacts as a result of any new standards, the uncertainties associated with this ongoing rulemaking at this time render EME unable to accurately estimate the costs to meet any such obligation. EME anticipates, however, that any such further emission reduction obligations would not be imposed until 2010 at the earliest.

Regional Haze—

       The goal of the 1999 regional haze regulations is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions in 60 years. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install Best Available Retrofit Technology (BART) or implement other control strategies to meet regional haze control requirements. States are required to revise their state implementation plans to demonstrate reasonable further progress towards meeting regional haze goals. Emission reductions that are achieved through other ongoing control programs may be sufficient to demonstrate reasonable progress toward the long-term goal, particularly for the first 10 to 15 year phase of the program. States must develop implementation plans by December 2007. It is possible that sources that are subject to the CAIR will be able to satisfy their obligations under the regional haze regulations through compliance with the more stringent CAIR. However, until the state implementation plans are revised, EME cannot predict whether it will be required to install BART or implement other control strategies, and cannot identify the financial impacts of any additional control requirements.

New Source Review Requirements—

       Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address Clean Air Act New Source Review (NSR) compliance issues at the nation's coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, in the event that modifications are made to air emissions sources at a facility. The US EPA's strategy included both the filing of a number of suits against power plant owners, and the issuance of a number of administrative notices of violation to power plant owners alleging NSR violations. Neither EME nor any of its subsidiaries has been named as a defendant in these lawsuits and have not received any administrative Notices of Violation alleging NSR violations at any of their facilities.

       In response to conflicting court decisions concerning the applicable emissions test used to determine whether an operational or physical change at an electric generating station would require the plant to install additional pollution controls, the US EPA, on October 13, 2005, proposed a change to the NSR program. The proposal put forth several options for a new emissions test based on the impact of a facility modification on a facility's maximum hourly emissions or its emissions per unit of energy produced. The existing NSR emissions test is based on the impact of a modification on a generating station's net annual emissions.

       In October 2005, the US EPA announced a revised NSR strategy to take account of recent US EPA rulemakings, such as the CAIR and regional haze rules, affecting coal-fired power plants. Under the

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revised strategy, while the US EPA will continue to pursue filed cases and cases in active negotiation, it intends to shift its future enforcement focus from coal-fired power plants to other sectors where compliance assurance activities have the potential to produce significant environmental benefits.

       Prior to EME's purchase of the Homer City facilities, the US EPA requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning physical changes at the plant. This request was part of the US EPA's industry-wide investigation of compliance by coal-fired plants with the Clean Air Act NSR requirements. On February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois coal plants from the US EPA. On July 28, 2003, Commonwealth Edison received a substantially similar request for information from the US EPA related to these same plants. Under date of February 1, 2005, the US EPA submitted a request for additional information to Midwest Generation. Midwest Generation has provided responses to these requests. Other than these requests for information, no NSR enforcement-related proceedings have been initiated by the US EPA with respect to any of EME's facilities. See also "State—Illinois—Air Quality."

       Developments with respect to changes to the NSR program and NSR enforcement will continue to be monitored by EME to assess what implications, if any, they will have on the operation of power plants owned or operated by EME or its subsidiaries, or on EME's results of operations or financial position.

Clean Water Act—Cooling Water Intake Structures

       On July 9, 2004, the US EPA published the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for cooling purposes. The purpose of the regulation is to reduce substantially the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems. Pursuant to the regulation, a demonstration study must be conducted when applying for a new or renewed National Pollutant Discharge Elimination System (NPDES) wastewater discharge permit. If one can demonstrate that the costs of meeting the presumptive standards set forth in the regulation are significantly greater than the costs that the US EPA assumed in its rule making or are significantly disproportionate to the expected environmental benefits, a site-specific analysis may be performed to establish alternative standards. Depending on the findings of the demonstration studies, cooling towers and/or other mechanical means of reducing impingement/ entrainment may be required. EME has begun to collect impingement and entrainment data at its potentially affected Midwest Generation facilities in Illinois to begin the process of determining what corrective actions may need to be taken.

       After the final promulgation of the Phase II cooling water intake structure regulation, legal challenges were filed by environmental groups, the attorneys general for six states, a utility trade association and several individual electric power generating companies. These cases have been consolidated and transferred to the United States Court of Appeals for the Second Circuit. A briefing schedule has been established for the case and a decision is not expected until sometime in 2006. The final requirements of the Phase II rule will not be fully known until these appeals are resolved and, if necessary, the regulation is revised by the US EPA. Although the Phase II rule could have a material impact on EME's operations, EME cannot reasonably determine the financial impact on it at this time because it is in the beginning stages of collecting the data required by the regulation and due to the legal challenges mentioned above which may affect the obligations imposed by the rule.

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Federal Legislative Initiatives

       There have been a number of bills introduced in Congress that would amend the Clean Air Act to specifically target emissions of specific pollutants from electric utility generating stations. These bills would mandate reductions in emissions of NOx, SO2 and mercury. Some bills would also impose limitations on carbon dioxide emissions. The various proposals differ in many details, including the timing of any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these bills with existing legal requirements. There is significant uncertainty as to whether any of the proposed legislative initiatives will pass in its current form or whether any compromise can be reached that would facilitate passage of legislation. Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

Environmental Remediation

       Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs to remediate releases of hazardous substances from such facilities even where the disposal of such wastes was undertaken in compliance with applicable laws. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several.

       With respect to EME's potential liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $2 million at December 31, 2005 for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for environmental activity where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

       Federal, state and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor condition or in the event of construction, remodeling, renovation or demolition of a building. Those laws and regulations may impose liability for release of asbestos-containing materials and may provide for the ability of third parties to seek recovery from owners or operators of these properties for personal injury associated with asbestos-containing materials. In connection with the ownership and operation of its facilities, EME may be liable for these costs. EME has agreed to indemnify the sellers of the Illinois Plants and the Homer City

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facilities with respect to specified environmental liabilities. See "—Contractual Obligations, Commitments and Contingencies—Commercial Commitments—Guarantees and Indemnities" for a discussion of these indemnities.

State—Illinois

Air Quality

       Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NOx emission rate of 0.25 lb NOx/mmBtu of heat input. This limitation is commonly referred to as the East St. Louis State Implementation Plan. This regulation is a State of Illinois requirement. Each of the Illinois Plants complied with this standard in 2004. Beginning with the 2004 ozone season, the Illinois Plants became subject to the federally mandated "NOx SIP Call" regulation that provided ozone-season NOx emission allowances to a 19-state region east of the Mississippi. This program provides for NOx allowance trading similar to the SO2 (acid rain) trading program already in effect. EME has qualified for early reduction allowances by reducing NOx emissions at various plants ahead of the imposed deadline. Additionally, the installation of emission control technology at certain plants has demonstrated over-compliance at those individual plants with the pending NOx emission limitations. Finally, NOx emission trading will be utilized, as needed, to comply with any shortfall at plants where installation of emission control technology has demonstrated reductions at levels short of the NOx limitations.

       During 2004, the Illinois Plants stayed within their NOx allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois Plants used banked allowances, along with some purchased allowances, to stay within their NOx allocations. After 2005, EME plans to continue to purchase allowances while evaluating the costs and benefits of various technologies to determine whether any additional pollution controls should be installed at the Illinois facilities.

       On January 5, 2006, Illinois Governor Rod Blagojevich announced that he was directing the Illinois Environmental Protection Agency to draft rules that would impose state limits on mercury emissions from coal-fired power plants which would be more stringent than the US EPA's CAMR issued in May 2005. Illinois is required to submit a state implementation plan (SIP) for CAMR to the US EPA by November 17, 2006. The Governor or his spokespersons have said that rules to be submitted to the Illinois Pollution Control Board will require a 90% reduction in mercury emissions averaged across company-owned Illinois generators and a minimum reduction of 75% for individual generating units by June 30, 2009. A 90% reduction at each generating unit would be required by 2013. Buying or selling of emission allowances under the CAMR federal cap and trade program would be prohibited. The Pollution Control Board must act on proposed rules submitted by the Illinois EPA after evidentiary hearings, including the presentation and cross-examination of expert testimony. After the Pollution Control Board adopts rules, they must be submitted to the General Assembly's Joint Committee on Administrative Rules for notice, hearing, and adoption, rejection or modification. Rules adopted through such state proceedings are also subject to court appeal. EME is not able at this time to predict the final form of these rules or provide an estimate of their financial impact.

       During 2006, the Illinois EPA is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. This SIP is to be submitted to the US EPA by September 11, 2006. The Illinois EPA has also begun to develop SIPs to meet National Ambient Air Quality Standards for 8-hour ozone and fine particulates. These SIPs will be developed with the intent of bringing non-attainment areas, such as Chicago, into attainment. They are expected to deal with all

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emission sources, not just power generators, and to address emissions of NOx, SO2, and Volatile Organic Carbon. These SIPs are to be submitted to the US EPA by June 15, 2007 for 8-hour ozone, and by April 5, 2008 for fine particulates. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

       The Illinois EPA is reviewing the water quality standards for the Des Plaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. An upgraded use classification could result in more stringent limits being applied to wastewater discharges to the river from these plants. If the existing use classification is changed, the limits on the temperature of the discharges from the Joliet and Will County plants may be made more stringent. The Illinois EPA has also begun a review of the water quality standards for the Chicago River and Chicago Sanitary and Ship Canal which are adjacent to the Fisk and Crawford Stations. Proposed changes to the existing standards are still being developed. Accordingly, EME is not able to estimate financial impact of potential changes to the water quality standards. However, the cost of additional cooling water treatment, if required, could be substantial.

State—Pennsylvania

Air Quality

       During 2006, the Pennsylvania Department of Environmental Protection (PADEP) is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. This SIP is to be submitted to the US EPA by September 11, 2006. The Ozone Transport Commission, of which Pennsylvania is a member, is developing a model rule that would continue to allow SO2 and NOx emissions trading, but would impose more stringent limits on SO2 and NOx emissions and would phase in these reductions more quickly than is required by CAIR. EME does not know whether the northeast states will ultimately agree to this model rule or whether Pennsylvania will implement such a rule. Pennsylvania is also required to develop a SIP to implement the federal CAMR, which SIP is to be submitted to the US EPA by November 17, 2006. With respect to mercury, the PADEP has recently announced that it plans to issue a proposed rule that would require coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015. The proposed rule would not allow the use of emissions trading to achieve compliance. However, the proposal would apparently allow facilities to comply with the mercury regulation by installing specific pollution control technology for sulfur dioxide and nitrogen oxides and by burning 100% bituminous coal. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

       The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas desulfurization system at the Homer City facilities has exceeded the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME was notified in April 2002 by PADEP that it was included in the Quarterly Noncompliance Report submitted to the US EPA. EME investigated a number of technical alternatives for maximizing the level of selenium removal in the discharge and performed various pilot studies. While some of the pilot studies improved the performance of the treatment system, the discharge still was not able to consistently meet the selenium effluent limits. EME identified additional options for achieving the selenium limits, and, with PADEP's approval, has undertaken a pilot program utilizing biological treatment. EME prepared a draft of a consent order and agreement addressing the selenium issue and presented it to PADEP for consideration in connection with

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the renewal of the station's NPDES permit. PADEP has included civil penalties in consent agreements related to other facilities with selenium treatment issues, but the amount of civil penalties that may be assessed against EME cannot be estimated at this time.

Climate Change

       The Kyoto Protocol on climate change officially came into effect on February 16, 2005. Under the Kyoto Protocol, the United States would have been required, by 2008-2012, to reduce its greenhouse gas emissions, such as carbon dioxide, by 7% from 1990 levels. Under the Bush administration, however, the United States has chosen not to pursue ratification of the Kyoto Protocol. Instead, the Bush administration has proposed several alternatives to mandatory reductions of greenhouse gases.

       There have been petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. Also, in 2004, several states and environmental organizations brought a complaint in federal court in New York, alleging that several electric utility corporations are jointly and severally liable under a theory of public nuisance for damages caused by the alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. Neither EME nor its subsidiaries were named as defendants in the complaint. The case was dismissed and is currently on appeal with the United States Court of Appeals for the Second Circuit.

       On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap and trade greenhouse gas program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule is scheduled to be announced within the next few months. The current proposal is to commence the program in 2009 by setting a cap (for the 2009 to 2015 period) on allowances based on carbon dioxide emissions from 2000 to 2004 and reducing emissions by 10% between 2015 and 2020. The Memorandum of Understanding provides that at least 25% of the state allowance allocations be set aside for public purposes, suggesting that from the commencement of the program, generators subject to the RGGI may receive allowances that are materially less than their carbon dioxide emissions. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania has participated as an observer of the process. If Pennsylvania were to join the RGGI, this could have a material impact on EME's Homer City facility.

       In California, Governor Schwarzenegger issued an executive order on June 1, 2005, setting forth targets for greenhouse gas reductions. The targets call for a reduction of greenhouse gas emissions to 2000 levels by 2010; a reduction of greenhouse gas emissions to 1990 levels by 2020; and a reduction of greenhouse gas emissions to 80% below 1990 levels by 2050. The CPUC is addressing climate change related issues in various regulatory proceedings.

       The ultimate outcome of the climate change debate could have a significant economic effect on EME. Any legal obligation that would require EME to reduce substantially its emissions of carbon dioxide would likely require extensive mitigation efforts and would raise considerable uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generating facilities.

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MARKET RISK EXPOSURES

Introduction

       EME's primary market risk exposures are associated with the sale of electricity and capacity from and the procurement of fuel for its merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures.

       This section discusses these market risk exposures under the following headings:

	Page
Commodity Price Risk	75
Credit Risk	84
Interest Rate Risk	85
Fair Value of Financial Instruments	85

Commodity Price Risk

General Overview

       EME's revenues and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market areas where EME's merchant plants are located. Among the factors that influence the price of energy, capacity and ancillary services in these markets are:

•

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

•

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and/or technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;

•

transmission congestion in and to each market area and the resulting differences in prices between delivery points;

•

the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;

•

the cost and availability of emission credits or allowances;

•

the availability, reliability and operation of competing power generation facilities, including nuclear generating plants, where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;

•

weather conditions prevailing in surrounding areas from time to time; and

•

changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

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       A discussion of commodity price risk for the Illinois Plants and the Homer City facilities is set forth below.

Introduction

       EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

       In addition to prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary from unit to unit.

       EME uses "value at risk" to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities, and its trading 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.

Hedging Strategy

       To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through the use of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange. Hedge transactions are also entered into as forward sales to utilities and power marketing companies.

       The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME's ability to enter into hedging transactions depends upon its, Midwest Generation's and EMMT's credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

       In the case of hedging transactions related to the generation and capacity of the Illinois Plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity support for implementation of EME's contracting strategy for the Illinois Plants. In the case of hedging transactions related to the generation and capacity of the

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Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See "—Credit Risk," below.

Energy Price Risk Affecting Sales from the Illinois Plants

       All the energy and capacity from the Illinois Plants is sold under terms, including price and quantity, negotiated by EMMT with customers through a combination of bilateral agreements, forward energy sales and spot market sales. As discussed further below, power generated at the Illinois Plants has generally been sold into the PJM market. 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." Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, linking eastern PJM and the Northern Illinois control areas of the PJM system and allowing the Illinois Plants to be dispatched into the broader PJM market. Further, on April 1, 2005, the MISO commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region, in the MISO, where there is a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM.

       Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing and is no longer required to arrange and pay separately for transmission when making sales to wholesale buyers within the PJM system. Hedging transactions related to the generation of the Illinois units are entered into at the Northern Illinois Hub in PJM, the AEP/Dayton Hub in PJM and, with the advent of MISO, at the Cinergy Hub in MISO. Because of proximity, the Illinois Plants are primarily hedged with transactions at the Northern Illinois Hub, but from time to time may be hedged in limited amounts at the AEP/Dayton Hub and the Cinergy Hub. These trading hubs have been the most liquid locations for these hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. See "—Basis Risk" below for further discussion.

       The PJM pool has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in the western PJM control area and are physically connected to high-voltage transmission lines serving this market.

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       The following table depicts the average historical market prices for energy per megawatt-hour during 2005 and 2004.

	2005(1)		2004
January	$	38.36	$	27.88	(2)
February		34.92		29.98	(2)
March		45.75		30.66	(2)
April		38.98		27.88	(2)
May		33.60		34.05	(1)
June		42.45		28.58	(1)
July		50.87		30.92	(1)
August		60.09		26.31	(1)
September		53.30		27.98	(1)
October		49.39		30.93	(1)
November		44.03		29.15	(1)
December		64.99		29.90	(1)
Yearly Average	$	46.39	$	29.52

(1)

Represents average historical market prices for energy as quoted for sales into the Northern Illinois Hub. Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.

(2)

Represents average historical market prices for energy "Into ComEd." Energy prices were determined by obtaining broker quotes and other public price sources for "Into ComEd" delivery points.

       Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

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       The following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar year 2006 and calendar year 2007 "strips," which are defined as energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub during 2005:

	24-Hour Northern Illinois Hub Forward Energy Prices*
	2006		2007
January 31, 2005	$	34.67	$	33.85
February 28, 2005		36.52		35.61
March 31, 2005		41.49		40.49
April 29, 2005		41.52		39.73
May 31, 2005		40.15		39.45
June 30, 2005		42.73		42.17
July 29, 2005		44.66		43.17
August 31, 2005		51.29		46.79
September 30, 2005		52.74		47.61
October 31, 2005		49.52		43.38
November 30, 2005		53.75		47.73
December 30, 2005		53.08		46.66

*

Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.

       The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at December 31, 2005:

	2006		2007
Megawatt hours		15,047,414		11,004,000
Average price/MWh(1)	$	44.29	$	48.04

(1)

The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods during the day and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at December 31, 2005 is not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

Energy Price Risk Affecting Sales from the Homer City Facilities

       Electric power generated at the Homer City facilities is generally sold into the PJM market. The PJM pool has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

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       The following table depicts the average historical market prices for energy per megawatt-hour in PJM during the past three years:

	Historical Energy Prices* 24-Hour PJM
	Homer City						West Hub
	2005		2004		2003		2005		2004		2003
January	$	45.82	$	51.12	$	36.56	$	49.53	$	55.01	$	43.62
February		39.40		47.19		46.13		42.05		44.22		48.31
March		47.42		39.54		46.85		49.97		39.21		54.85
April		44.27		43.01		35.35		44.55		42.82		35.93
May		43.67		44.68		32.29		43.64		48.04		32.10
June		46.63		36.72		27.26		53.72		38.05		29.10
July		54.63		40.09		36.55		66.34		43.64		40.88
August		66.39		34.76		39.27		82.83		38.59		39.74
September		66.67		40.62		28.71		76.82		41.96		29.51
October		67.93		37.37		26.96		77.56		37.78		27.47
November		59.78		35.79		29.17		62.01		36.91		29.30
December		75.03		38.59		35.89		81.97		41.83		35.92
Yearly Average	$	54.80	$	40.79	$	35.08	$	60.92	$	42.34	$	37.23

*

Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub using historical hourly real-time prices provided on the PJM-ISO web-site.

       Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below.

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       The following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar 2006 and 2007 "strips," which are defined as energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub during 2005:

	24-Hour PJM West Hub Forward Energy Prices*
	2006		2007
January 31, 2005	$	46.11	$	44.48
February 28, 2005		48.17		46.84
March 31, 2005		53.07		50.80
April 29, 2005		50.26		49.16
May 31, 2005		50.05		49.56
June 30, 2005		53.66		52.71
July 29, 2005		55.88		54.35
August 31, 2005		65.31		59.81
September 30, 2005		72.01		62.18
October 31, 2005		69.26		60.86
November 30, 2005		75.58		66.16
December 30, 2005		73.74		68.62

*

Energy prices were determined by obtaining broker quotes and information from other public sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.

       The following table summarizes Homer City's hedge position at December 31, 2005:

	2006		2007
Megawatt hours		8,526,000		5,280,000
Average price/MWh(1)	$	53.42	$	67.30

(1)

The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods during the day and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at December 31, 2005 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

       The average price/MWh for Homer City's hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. See "—Basis Risk" below for a discussion of the difference.

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Basis Risk

       Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point known as the PJM West Hub in the case of the Homer City facilities and for a settlement point known as the Northern Illinois Hub in the case of the Illinois Plants. EME's price risk management activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME's revenues with respect to such forward contracts include:

•

sales of actual generation in the amounts covered by the forward contracts with reference to PJM spot prices at the busbar of the plant involved, plus,

•

sales to third parties at the price under such hedging contracts at designated settlement points (generally the PJM West Hub for the Homer City facilities and the Northern Illinois Hub for the Illinois Plants) less the cost of power at spot prices at the same designated settlement points.

       Under the PJM market design, locational marginal pricing, which establishes hourly prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to by EME as "basis risk." During 2005, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (EME Homer City's primary trading hub) by an average of 10%, compared to 4% during 2004. The monthly average difference during 2005 ranged from zero to 20%, which occurred in August 2005. In contrast to the Homer City facilities, during 2005, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois Plants.

       By entering into cash settled future contracts and forward contracts using the PJM West Hub and the Northern Illinois Hub (or other similar trading hubs) as the settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME has participated in purchasing financial transmission rights in PJM, and may continue to do so in the future. A financial transmission right is a financial instrument that entitles the holder to receive actual spot prices at one point of delivery and pay prices at another point of delivery that are pegged to prices at the first point of delivery, plus or minus a fixed amount. Accordingly, EME's price risk management activities include using financial transmission rights alone or in combination with forward contracts to manage basis risk.

Coal Price and Transportation Risk

       The Illinois Plants use approximately 18 million to 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of Wyoming. In addition, the Homer City facilities use approximately 5 million to 6 million tons of coal annually, obtained from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements with terms

82

ranging from one year to eight years. The following table summarizes the percent of expected coal requirements for the next five years that were under contract at December 31, 2005.

	Percent of Coal Requirements Under Contract
	2006	2007	2008	2009	2010
Illinois Plants	100%	91%	32%	32%	33%
Homer City facilities	101%	94%	39%	15%	0%

       EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which is purchased for the Homer City facilities, have increased considerably during 2004 and 2005. In January 2004, prices of NAPP coal (with 13,000 British Thermal units (Btu) per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) were below $40 per ton and increased to more than $60 per ton during 2004. The price of NAPP coal fluctuated between $44 per ton and $57 per ton during 2005, with a price of $45 per ton at December 30, 2005, as reported by the Energy Information Administration. The overall increase in the NAPP coal price has been largely attributed to greater demand from domestic power producers and increased international shipments of coal to Asia. Prices of Powder River Basin (PRB) coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content), which is purchased for the Illinois Plants, significantly increased in 2005 due to the curtailment of coal shipments during 2005 due to increased PRB coal demand from other regions (east), rail constraints (discussed below), higher oil and natural gas prices and higher prices for SO2 allowances. On December 30, 2005, the Energy Information Administration reported the price of coal to be $18.48 per ton, which compares to 2004 prices of generally below $7 per ton.

       During 2005, the rail lines that bring coal from the PRB to EME's Illinois Plants were damaged from derailments caused by heavy rains. The railroads are in the process of making repairs to these rail lines. During 2005, Midwest Generation received sufficient quantities to meet generation requirements. Rail line maintenance is expected to continue in 2006. Based on communication with the transportation provider, EME expects to continue receiving a sufficient amount of coal to generate power at historical levels while these repairs are being completed.

Emission Allowances Price Risk

       The federal Acid Rain Program requires electric generating stations to hold SO2 allowances, and Illinois and Pennsylvania regulations implemented the federal NOx SIP Call requirement. Under these programs, EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these plants.

       The price of emission allowances, particularly SO2 allowances issued through the federal Acid Rain Program, increased substantially during 2005 and 2004. The average price of purchased SO2 allowances increased from $204 per ton during 2003 to $435 per ton during 2004 to $1,219 per ton during 2005. The increase in the price of SO2 allowances has been attributed to reduced numbers of both allowance sellers and prior year allowances.

       Based on EME's anticipated SO2 emission allowances requirements in 2006, EME expects that a 10% change in the price of SO2 emission allowances at December 31, 2005 would increase or decrease pre-tax income in 2006 by approximately $7 million. See "Liquidity and Capital Resources—

83

Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions.

Credit Risk

       In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted 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 a counterparty defaulted.

       To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the 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. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

       EME measures credit risk exposure from counterparties of its merchant energy activities as either: (i) the sum of 60 days of accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME's subsidiaries enter into master agreements and other arrangements in conducting price risk management and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these agreements. At December 31, 2005, the amount of exposure, broken down by the credit ratings of EME's counterparties, was as follows:

S&P Credit Rating	December 31, 2005
	(in millions)
A or higher	$	6
A-		230
BBB+		45
BBB		28
BBB-		3
Below investment grade		—
Total	$	312

       EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a

84

default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power plant.

       In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

       EME's merchant plants sell electric power generally into the PJM market by participating in PJM's capacity markets or transact capacity on a bilateral basis. Sales into the PJM pool accounted for approximately 70% of EME's consolidated operating revenues for the year ended December 31, 2005. Moody's Investor Service rates PJM's senior unsecured debt Aa3. PJM, an independent system operator with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default is shared by all members based upon a predetermined formula. At December 31, 2005, EME's account receivable due from PJM was $223 million.

Interest Rate Risk

       Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. Based on the amount of variable rate long-term debt for which EME has not entered into interest rate hedge agreements at December 31, 2005, a 100-basis-point change in interest rates at December 31, 2005 would increase or decrease 2006 income before taxes by approximately $5 million. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's total long-term obligations (including current portion) was $3.7 billion at December 31, 2005, compared to the carrying value of $3.4 billion. A 10% increase in market interest rates at December 31, 2005 would result in a decrease in the fair value of total long-term obligations by approximately $125 million. A 10% decrease in market interest rates at December 31, 2005 would result in an increase in the fair value of total long-term obligations by approximately $141 million.

Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

       The following table summarizes the fair values for outstanding derivative financial instruments used in EME's continuing operations for purposes other than trading, by risk category (in millions):

		December 31, 2005			December 31, 2004
Commodity price:
	Electricity	$	(434	)	$	10

85

       In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. A 10% change in the market price at December 31, 2005 would increase or decrease the fair value of outstanding derivative commodity price contracts by approximately $250 million. The following table summarizes the maturities and the related fair value, based on actively traded prices, of EME's commodity price risk management assets and liabilities as of December 31, 2005 (in millions):

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(434	)	$	(354	)	$	(80	)	$	—	$	—

Energy Trading Derivative Financial Instruments

       The fair value of the commodity financial instruments related to energy trading activities as of December 31, 2005 and 2004, are set forth below (in millions):

	December 31, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities
Electricity	$	127	$	27	$	125	$	36
Other		1		—		—		—
Total	$	128	$	27	$	125	$	36

       The change in the fair value of trading contracts for the year ended December 31, 2005, was as follows (in millions):

Fair value of trading contracts at January 1, 2005	$	89
Net gains from energy trading activities		202
Amount realized from energy trading activities		(203	)
Other changes in fair value		13
Fair value of trading contracts at December 31, 2005	$	101

       A 10% change in the market price at December 31, 2005 would increase or decrease the fair value of trading contracts by approximately $6 million.

86

       Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for a power sales agreement with an unaffiliated electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of December 31, 2005) (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	12	$	12	$	—	$	—	$	—
Prices based on models and other valuation methods		89		2		9		15		63
Total	$	101	$	14	$	9	$	15	$	63

RECENT DEVELOPMENT

       On January 29, 2006, the main power transformer on Unit 3 of the Homer City facilities failed resulting in a suspension of operations at this unit. No fire occurred and there were no injuries as a result of the equipment failure. EME Homer City has secured a replacement transformer and currently expects remedial and replacement activities to be completed in a manner which will permit Unit 3 to return to service in April 2006. EME Homer City plans to adjust its previously planned outage schedules for Unit 3 and the other Homer City units in order to minimize overall outage activities over the next fifteen months. Although the unplanned outage will reduce generation and hence revenues and net income during the first quarter of 2006, because of the change in outage schedules generation for the year as a whole should not be significantly affected. In order to mitigate the effects of the outage on EME Homer City's cash flow for the first quarter of 2006, EME and EMMT have arranged with EME Homer City to advance to EME Homer City such funds, if any, as may be necessary to enable EME Homer City to meet its ongoing operating obligations during the period affected by the outage. It is anticipated that these funds, if any, will be recovered by EME and EMMT during the balance of the year.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

       Information responding to Item 7A is filed with this report under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements:
	Report of Independent Registered Public Accounting Firm	89
	Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	90
	Consolidated Balance Sheets at December 31, 2005 and 2004	91
	Consolidated Statements of Shareholder's Equity for the years ended December 31, 2005, 2004 and 2003	93
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003	94
	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	95
	Notes to Consolidated Financial Statements	96

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

       None.

ITEM 9A.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

       EME's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of EME's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, EME's disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

       There were no changes in EME's internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the fourth fiscal quarter of 2005 that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

       None.

88

EDISON MISSION ENERGY AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Edison Mission Energy

       In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Edison Mission Energy and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

       As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005. As discussed in Note 7 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of March 31, 2004.

PricewaterhouseCoopers LLP
Los Angeles, California
March 6, 2006

89

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)

			Years Ended December 31,
			2005			2004			2003
Operating Revenues
	Electric revenues		$	2,133		$	1,604		$	1,700
	Net gains from price risk management and energy trading			90			9			48
	Operation and maintenance services			25			26			30
		Total operating revenues		2,248			1,639			1,778
Operating Expenses
	Fuel			617			619			669
	Plant operations			462			471			438
	Plant operating leases			177			186			206
	Operation and maintenance services			23			23			21
	Depreciation and amortization			124			144			154
	Loss on lease termination, asset impairment and other charges			7			989			304
	Administrative and general			154			149			138
		Total operating expenses		1,564			2,581			1,930
	Operating income (loss)			684			(942	)		(152	)
Other Income (Expense)
	Equity in income from unconsolidated affiliates			227			215			245
	Impairment loss on equity method investment			(55	)		—			—
	Interest and other income			69			9			2
	Gain on sale of assets			—			43			—
	Loss on early extinguishment of debt			(4	)		—			—
	Interest expense			(296	)		(293	)		(295	)
	Dividends on preferred securities			—			—			(7	)
		Total other income (expense)		(59	)		(26	)		(55	)
	Income (loss) from continuing operations before income taxes and minority interest			625			(968	)		(207	)
	Provision (benefit) for income taxes			221			(401	)		(114	)
	Minority interest			—			(1	)		(2	)
Income (Loss) From Continuing Operations				404			(568	)		(95	)
Income from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004), net of tax (Note 8)				29			690			124
Income Before Accounting Change				433			122			29
Cumulative effect of change in accounting, net of tax (Note 3)				(1	)		—			(9	)
Net Income			$	432		$	122		$	20

The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)

			December 31,
			2005		2004
Assets
Current Assets
	Cash and cash equivalents		$	1,147	$	2,270
	Short-term investments			183		140
	Accounts receivable—trade			335		152
	Accounts receivable—affiliates			8		52
	Inventory			120		107
	Assets under price risk management and energy trading			78		41
	Margin and collateral deposits			561		42
	Deferred taxes			155		—
	Prepaid expenses and other			68		88
		Total current assets		2,655		2,892
Investments in Unconsolidated Affiliates				391		454
Property, Plant and Equipment				3,653		3,493
	Less accumulated depreciation and amortization			798		709
		Net property, plant and equipment		2,855		2,784
Other Assets
	Deferred financing costs			42		47
	Long-term assets under price risk management and energy trading			90		90
	Restricted cash			105		155
	Rent payments in excess of levelized rent expense under plant operating leases			395		277
	Long-term margin and collateral deposits			137		—
	Other long-term assets			117		18
		Total other assets		886		587
Assets of Discontinued Operations				1		111
Total Assets			$	6,788	$	6,828

The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)

			December 31,
			2005			2004
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	32		$	26
	Accounts payable and accrued liabilities			268			316
	Dividends payable			—			305
	Liabilities under price risk management and energy trading			418			31
	Interest payable			51			55
	Current maturities of long-term obligations			50			211
		Total current liabilities		819			944
Long-term obligations net of current maturities				3,303			3,507
Deferred taxes and tax credits				171			198
Long-term liabilities under price risk management and energy trading				83			—
Other long-term liabilities				540			492
Liabilities of discontinued operations				4			5
Total Liabilities				4,920			5,146
Minority Interest				24			—
Commitments and Contingencies (Notes 11, 12, 16 and 17)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of December 31, 2005 and 2004			64			64
	Additional paid-in capital			2,209			2,251
	Retained deficit			(218	)		(650	)
	Accumulated other comprehensive income (loss)			(211	)		17
Total Shareholder's Equity				1,844			1,682
Total Liabilities and Shareholder's Equity			$	6,788		$	6,828

The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(In millions)

		Common Stock		Additional Paid-in Capital			Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholder's Equity
Balance at December 31, 2002		$	64	$	2,633		$	(792	)	$	(212	)	$	1,693
	Net income							20						20
	Other comprehensive income										190			190
Balance at December 31, 2003			64		2,633			(772	)		(22	)		1,903
	Net income							122						122
	Other comprehensive income										39			39
	Dividend payable to parent				(305	)								(305	)
	Cash dividends to parent				(74	)								(74	)
	Payments to Edison International for stock option price appreciation on options exercised				(8	)								(8	)
	Other stock transactions, net				5									5
Balance at December 31, 2004			64		2,251			(650	)		17			1,682
	Net income							432						432
	Other comprehensive loss										(228	)		(228	)
	Non-cash equity contribution				20									20
	Cash dividends to parent				(55	)								(55	)
	Payments to Edison International for stock option price appreciation on options exercised				(4	)								(4	)
	Other stock transactions, net				(3	)								(3	)
Balance at December 31, 2005		$	64	$	2,209		$	(218	)	$	(211	)	$	1,844

The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)

			Years Ended December 31,
			2005			2004			2003
Net Income			$	432		$	122		$	20
Other comprehensive income, net of tax:
	Foreign currency translation adjustments:
		Foreign currency translation adjustments, net of income tax expense of $4 and $5 for 2004 and 2003, respectively		—			(18	)		154
		Reclassification adjustments for sale of investment in a foreign subsidiary		—			(127	)		—
	Minimum pension liability adjustment, net of income tax effect			—			10			(1	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(54), $(6) and $2 for 2005, 2004 and 2003, respectively		(69	)		86			47
		Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $107, $(64) and $(1) for 2005, 2004 and 2003, respectively		(159	)		88			(10	)
Other comprehensive income				(228	)		39			190
Comprehensive Income			$	204		$	161		$	210

The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

			Years Ended December 31,
			2005			2004 Revised(1)			2003 Revised(1)
Cash Flows From Operating Activities
	Net income		$	432		$	122		$	20
	Less: Income from discontinued operations			(29	)		(690	)		(124	)
	Income (loss) from continuing operations, net			403			(568	)		(104	)
	Adjustments to reconcile income to net cash provided by (used in) operating activities:
		Equity in income from unconsolidated affiliates		(227	)		(215	)		(245	)
		Distributions from unconsolidated affiliates		222			228			375
		Depreciation and amortization		132			144			154
		Minority interest		—			1			2
		Deferred taxes and tax credits		(60	)		(21	)		(21	)
		Gain on sale of assets		—			(43	)		—
		Loss on early extinguishment of debt		4			—			—
		Impairment charges		62			35			304
		Cumulative effect of change in accounting, net of tax		1			—			9
	Changes in operating assets and liabilities:
		Increase in margin and collateral deposits		(656	)		(30	)		—
		Increase in accounts receivable		(135	)		(49	)		(4	)
		Decrease (increase) in inventory		(13	)		11			28
		Decrease in prepaid expenses and other		10			3			41
		Increase in rent payments in excess of levelized rent expense		(117	)		(59	)		(96	)
		Increase (decrease) in accounts payable and accrued liabilities		22			86			(35	)
		Increase (decrease) in interest payable		(4	)		13			(9	)
		Decrease in net assets under risk management		41			13			1
		Other operating-assets		(3	)		13			(6	)
		Other operating-liabilities		52			54			28
				(266	)		(384	)		422
	Operating cash flow from discontinued operations			20			(434	)		243
		Net cash provided by (used in) operating activities		(246	)		(818	)		665
Cash Flows From Financing Activities
	Borrowing on long-term debt and lease swap agreements			325			1,795			796
	Payments on long-term debt agreements			(694	)		(1,678	)		(1,252	)
	Cash dividends to parent			(360	)		(74	)		—
	Payments for price appreciation on stock options exercised			(18	)		(5	)		—
	Financing costs			(6	)		(34	)		(19	)
				(753	)		4			(475	)
	Financing cash flow from discontinued operations			—			(144	)		153
		Net cash used in financing activities		(753	)		(140	)		(322	)
Cash Flows From Investing Activities
	Investments in and loans to energy projects			—			—			(22	)
	Purchase of common stock of acquired companies			(154	)		—			(3	)
	Capital expenditures			(57	)		(55	)		(81	)
	Proceeds from sale of interest in projects			—			118			36
	Proceeds from sales of discontinued operations			124			2,740			—
	Purchases of short-term investments			(183	)		(301	)		(318	)
	Sales of short-term investments			140			181			298
	Decrease (increase) in restricted cash			41			30			(12	)
	Turbine deposits			(57	)		—			—
	Proceeds from (investments in) other assets			16			(1	)		4
				(130	)		2,712			(98	)
	Investing cash flow from discontinued operations			5			18			(413	)
		Net cash provided by (used in) investing activities		(125	)		2,730			(511	)
Effect of exchange rate changes on cash				—			50			5
Effect on cash from deconsolidation of subsidiary				—			(34	)		—
Net increase (decrease) in cash and cash equivalents				(1,124	)		1,788			(163	)
Cash and cash equivalents at beginning of period				2,272			484			647
Cash and cash equivalents at end of period				1,148			2,272			484
Cash and cash equivalents classified as part of discontinued operations				(1	)		(2	)		(191	)
Cash and cash equivalents of continuing operations			$	1,147		$	2,270		$	293

(1)

See Note 2—Revisions for further explanation.

The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. General

Organization

       Edison Mission Energy (EME) is a wholly owned subsidiary of Mission Energy Holding Company (MEHC), which is a wholly owned subsidiary of Edison Mission Group Inc., which is a wholly owned, non-utility subsidiary of Edison International, which is also the parent holding company of Southern California Edison Company. Through its subsidiaries, EME is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also conducts price risk management and energy trading activities in power markets open to competition.

Note 2. Summary of Significant Accounting Policies

Basis of Consolidation

       The consolidated financial statements include the accounts of EME and all subsidiaries and partnerships in which EME has a controlling interest and variable interest entities in which EME is deemed the primary beneficiary. EME's investments in unconsolidated affiliates in which a significant, but less than controlling, interest is held and variable interest entities, in which EME is not deemed to be the primary beneficiary, are accounted for by the equity method. Refer to Note 7—Acquisitions and Consolidations—Consolidations, for a discussion of EME's adoption of an accounting standard on variable interest entities. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.

Reclassifications

       Certain prior year reclassifications have been made to conform to the current year financial statement presentation. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

Revisions

       EME revised its Consolidated Statements of Cash Flows for the years ended December 31, 2004 and 2003 to separately disclose the operating, financing and investing portions of the cash flows attributable to its discontinued operations. EME had previously reported these amounts on a combined basis.

Management's Use of Estimates

       The preparation of financial statements in conformity with generally accepted accounting principles requires EME to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates.

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Cash Equivalents

       Cash equivalents include time deposits and other investments totaling $1.1 billion and $2.2 billion at December 31, 2005 and 2004, respectively, with original maturities of three months or less. Time deposits and certificates of deposit totaled $411 million and $200 million at December 31, 2005 and 2004, respectively.

Short-term Investments

       At December 31, 2005, EME had classified all marketable securities as held-to-maturity under Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities" (SFAS No. 115). The securities were carried at amortized cost plus accrued interest which approximated their fair value. At December 31, 2005, all held-to-maturity securities mature within one year and consisted of $99 million of commercial paper, $50 million in time deposits and $34 million in certificates of deposit.

       At December 31, 2004, EME had classified all marketable securities as available-for-sale under SFAS No. 115. The fair market value of the securities was $140 million and consisted of auction rate securities rated AAA or Aaa by S&P or Moody's, respectively, with interest rate reset dates of less than thirty days. Sales of auction rate securities were $140 million in 2005. Purchases and sales of auction rate securities were $301 million and $181 million in 2004, respectively. Unrealized gains and losses from investments in theses securities were not material.

Margin and Collateral Deposits

       Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions.

Property, Plant and Equipment

       Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are principally comprised of EME's majority-owned subsidiaries' plants and related facilities. Depreciation and amortization are computed by using the straight-line method over the useful life of the property, plant and equipment and over the lease term for leasehold improvements.

       As part of the acquisition of the Illinois Plants and the Homer City facilities, EME acquired emission allowances under the United States Environmental Protection Agency's Acid Rain Program. Although the emission allowances granted under this program are freely transferable, EME intends to use substantially all the emission allowances in the normal course of its business to generate electricity. Accordingly, EME has classified emission allowances expected to be used by EME to generate power as part of property, plant and equipment. Acquired emission allowances will be amortized over the estimated lives of the plants on a straight-line basis.

       Useful lives for property, plant, and equipment are as follows:

Power plant facilities	3-34.5 years
Leasehold improvements	Life of lease
Emission allowances	25-34.5 years
Equipment, furniture and fixtures	3-7 years
Capitalized leased equipment	5 years

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Rent Expense

       Rent expense under all operating leases is levelized over the terms of the leases. Operating leases primarily consist of long-term leases for the Powerton, Joliet and Homer City power plants. See Note 17—Lease Commitments for additional information on these sale-leaseback transactions.

Impairment of Investments and Long-Lived Assets

       EME periodically evaluates the potential impairment of its investments in projects and other long-lived assets based on a review of estimated future cash flows expected to be generated. If the carrying amount of the investment or asset exceeds the amount of the expected future cash flows, undiscounted and without interest charges, then an impairment loss for EME's investments in projects and other long-lived assets is recognized in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock" and Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," respectively.

Capitalized Interest

       Interest incurred on funds borrowed by EME to finance project construction is capitalized. Capitalization of interest is discontinued when the projects are completed and deemed operational. Such capitalized interest is included in investment in energy projects and property, plant and equipment.

       Capitalized interest is amortized over the depreciation period of the major plant and facilities for the respective project.

	Years Ended December 31,
	2005		2004		2003
	(in millions)
Interest incurred	$	296	$	293	$	302
Interest capitalized		—		—		(7	)
	$	296	$	293	$	295

Income Taxes

       EME is included in the consolidated federal and state income tax returns of Edison International and participates in tax-allocation and payment agreements with other subsidiaries of Edison International. EME calculates its tax provision in accordance with these tax agreements. EME's current tax liability or benefit is determined on a "with and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding EME's taxable income or loss and state apportionment factors. This method is similar to a separate company return, except that EME recognizes, without regard to separate company limitations, additional tax liabilities or benefits based on the impact to the combined group of including EME's taxable income or losses and state apportionment factors.

       EME accounts for deferred income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted income tax rates. Investment and energy tax credits are deferred and amortized over the term of the power purchase agreement of the respective project. Income tax accounting policies are discussed further in Note 13—Income Taxes.

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Maintenance Accruals

       Certain of EME's plant facilities' major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Project Development Costs

       EME capitalizes direct costs incurred in developing new projects upon attainment of principal activities needed to commence procurement and construction. These costs consist of professional fees, salaries, permits, and other directly related development costs incurred by EME. The capitalized costs are amortized over the life of operational projects or charged to expense if management determines the costs to be unrecoverable.

Deferred Financing Costs

       Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis which approximates the effective interest rate method over the term of the related debt. Accumulated amortization of these costs amounted to $21 million in 2005 and $16 million in 2004.

Revenue Recognition

       EME is primarily an independent power producer, operating a portfolio of owned and leased plants and plants which are accounted for under the equity method. EME's subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts, all subject to market conditions. One of EME's subsidiaries executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EME's subsidiaries generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. Therefore, EME's subsidiaries record settlement of non-trading physical forward contracts on a gross basis. Consistent with Emerging Issues Task Force No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes," EME nets the cost of purchased power against related third party sales in markets that use locational marginal pricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EME's subsidiaries do not take title to the underlying commodity. Therefore, gains and losses from settlement of financial swaps and options are recorded net. Managed risks typically include commodity price risk associated with fuel purchases and power sales.

       EME records revenue and related costs as electricity is generated or services are provided unless EME is subject to Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" and does not qualify for the normal sales and purchases exception.

Derivative Instruments

       Statement of Financial Accounting Standards No. 133 (SFAS No. 133), as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal sale and purchase. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met,

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which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

       SFAS No. 133 sets forth the accounting requirements for cash flow hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.

       Financial instruments that are utilized for trading purposes are measured at fair value and included in the balance sheet as assets or liabilities from energy trading activities. In the absence of quoted market prices, financial instruments are valued at fair value, considering time value, volatility of the underlying commodity, and other factors as determined by EME. Resulting gains and losses are recognized in net gains from price risk management and energy trading in the accompanying Consolidated Income Statements in the period of change. Assets from price risk management and energy trading activities include the fair value of open financial positions related to trading activities and the present value of net amounts receivable from structured transactions. Liabilities from price risk management and energy trading activities include the fair value of open financial positions related to trading activities and the present value of net amounts payable from structured transactions.

       Where EME's derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (FIN) 39 "Offsetting of Amounts Related to Certain Contracts" are met, EME presents its derivative assets and liabilities on a net basis in its balance sheet.

Stock-Based Compensation

       At December 31, 2005, Edison International has stock-based compensation plans, which are described more fully in Note 15—Stock Compensation Plans. EME has accounted for those plans using the intrinsic value method. Upon grant, no stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income if EME had used the fair value accounting method.

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Net income, as reported	$	432		$	122		$	20
Add: Stock-based compensation expense included in reported net income, net of related tax effects		13			14			6
Deduct: Total stock-based employee compensation expense determined under fair value based method, net of related tax effects		(10	)		(12	)		(6	)
Pro forma net income	$	435		$	124		$	20

       As noted in "—New Accounting Pronouncements—Statement of Financial Accounting Standards No. 123(R)" below, EME is required to use the fair value accounting method for stock-based employee compensation beginning in the first quarter of 2006.

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New Accounting Pronouncements

Statement of Financial Accounting Standards No. 151

       In November 2004, the FASB issued SFAS No. 151, "Inventory Costs." SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current-period charges. Further, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. Unallocated overheads must be recognized as an expense in the period in which they are incurred. SFAS No. 151 is effective for inventory costs incurred beginning in the first quarter of 2006. EME does not expect the adoption of this standard to have a material impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 123(R)

       A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. EME is required to implement the new standard in the first quarter of 2006, and will apply the modified prospective transition method. Under the modified prospective method, the new accounting standard will be applied; effective January 1, 2006, to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements will not be restated under this method. The new accounting standard will result in the recognition of expense for all stock-based compensation awards where EME previously used the intrinsic value method of accounting, at times resulting in no recognition of expense for stock-based compensation.

Note 3. Asset Retirement Obligations

       Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

       In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations (AROs), an interpretation of SFAS 143. This interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. This interpretation became effective as of December 31, 2005 for EME. EME identified conditional AROs related to asbestos removal and disposal costs at its owned Illinois Plants (buildings and power plant facilities) and retired structures leased at the Powerton Station. EME recorded a $1 million, after tax, charge as a cumulative effect adjustment for asbestos removal and disposal activities associated with retired Powerton structures that are currently scheduled for demolition in 2007. EME has not recorded a liability related to the owned structures because it cannot reasonably estimate fair value of the obligation at this time. The range of time over which EME may settle this obligation in the future (demolition or other method) is sufficiently large to not allow for the use of expected present value techniques.

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       EME recorded a liability representing expected future costs associated with site reclamations, facilities dismantlement and removal of environmental hazards as follows:

	2005		2004		2003
	(in millions)
Beginning balance	$	5	$	5	$	4
Cumulative effect of accounting change		2		—		—
Accretion expense		—		—		1
Ending balance	$	7	$	5	$	5

       The pro forma net income effect of adopting FIN 47 is not shown due to its immaterial impact on EME's results of operations. The pro forma liability for conditional AROs is not shown due to the immaterial impact on EME's consolidated balance sheet.

Note 4. Inventory

       Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2005 and December 31, 2004 consisted of the following:

	2005		2004
	(in millions)
Coal and fuel oil	$	77	$	65
Spare parts, materials and supplies		43		42
Total	$	120	$	107

Note 5. Restructuring, Loss on Lease Termination, Asset Impairment and Other Charges

Restructuring Costs

       During the first quarter of 2005, EME initiated a review of its domestic organization to better align its resources with its domestic business requirements. Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional management structure. As a result of these changes, EME recorded charges of approximately $13 million (pre-tax) in 2005 for severance and related costs. These charges were included in administrative and general expense on EME's consolidated statement of income.

Loss on Lease Termination, Asset Impairment and Other Charges

       During 2004, EME recorded loss on lease termination, asset impairment and other charges of $989 million. On April 27, 2004, EME's subsidiary, Midwest Generation, LLC (Midwest Generation) terminated the Collins Station lease through a negotiated transaction with the lease equity investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax) due to termination of the lease and the planned decommissioning of the asset and disposition of excess inventory.

       Following the termination of the Collins Station lease, Midwest Generation announced plans on May 28, 2004 to permanently cease operations at the Collins Station by December 31, 2004 and

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decommission the plant. 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. In September 2004, EME recorded a pre-tax impairment charge of $5 million resulting from the termination of the power purchase agreement effective September 30, 2004 for the two units at the Collins Station that remained under contract. In addition, EME recognized a $4 million pre-tax charge for exit costs recorded as part of plant operations on EME's consolidated income statement related to reducing the workforce in Illinois during the fourth quarter of 2004.

       In September 2004, management completed an analysis of future competitiveness in the expanded PJM Interconnection, LLC (PJM) marketplace of its eight remaining small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight small peaking units. As a result of the decision to decommission the units, projected future cash flows associated with the Illinois peaking units were less than the book value of the units, resulting in an impairment under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or the Disposal of Long-Lived Assets." During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million (approximately $18 million after tax).

       During 2003, EME recorded asset impairment charges of $304 million, consisting of $245 million related to eight small peaking plants owned by Midwest Generation in Illinois and $53 million and $6 million to write down the estimated net proceeds from the planned sale of the Brooklyn Navy Yard and Gordonsville projects, respectively. The impairment charge related to the peaking plants in Illinois resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and current generation overcapacity. The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5% discount rate.

Note 6. Accumulated Other Comprehensive Income (Loss)

       Accumulated other comprehensive income (loss), including discontinued operations, consisted of the following:

		Currency Translation Adjustments			Unrealized Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
		(in millions)
Balance at December 31, 2003		$	145		$	(156	)	$	(11	)	$	(22	)
	Change for 2004		(145	)		174			10			39
Balance at December 31, 2004			—			18			(1	)		17
	Change for 2005		—			(228	)		—			(228	)
Balance at December 31, 2005		$	—		$	(210	)	$	(1	)	$	(211	)

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       Unrealized losses on cash flow hedges, net of tax, at December 31, 2005, include unrealized losses on commodity hedges primarily related to Midwest Generation and EME Homer City Generation L.P. (EME Homer City) futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. The increase in the unrealized losses during 2005 resulted from a combination of new hedges for 2006 and 2007 and an increase in market prices for power driven largely from higher natural gas and oil prices. In addition, EME reclassified a $9 million, after tax, unrealized gain from other comprehensive loss to earnings due to the impairment of its equity investment in the March Point project in 2005.

       As EME's hedged positions for continuing operations are realized, approximately $178 million, after tax, of the net unrealized losses on cash flow hedges at December 31, 2005 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will offset energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2007.

       Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $(65) million, $(13) million and $11 million in 2005, 2004 and 2003, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in net gains from price risk management and energy trading in EME's consolidated income statements.

Note 7. Acquisitions and Consolidations

Acquisitions

San Juan Mesa Project

       On December 27, 2005, EME completed a transaction with Padoma Project Holdings, LLC to acquire a 100% interest in the San Juan Mesa Wind Project, which owns a 120 MW wind power generation facility located in New Mexico, referred to as the San Juan Mesa wind project. The total purchase price was $156.5 million. The acquisition was funded with cash. The acquisition was accounted for utilizing the purchase method. The fair value of the San Juan Mesa wind project was equal to the purchase price and as a result, the entire purchase price was allocated to property, plant and equipment in EME's consolidated balance sheet. EME's consolidated statement of income will reflect the operations of the San Juan Mesa project beginning January 1, 2006. The pro forma effects of the San Juan Mesa wind project acquisition on EME's consolidated financial statements were not material.

Consolidations

Variable Interest Entities

       In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). This Interpretation defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. Under this Interpretation, the primary beneficiary is the variable interest holder that absorbs a majority of expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary

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beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met.

Consolidation of Special Purpose Entity—

       Wildorado Wind, L.P. is a special purpose entity formed to develop the Wildorado project, a planned 161 MW wind power generating facility to be located in Texas. A subsidiary of EME entered into a loan agreement with Wildorado Wind to fund turbine payments for the Wildorado project. In accordance with FIN 46R, EME is the primary beneficiary and accordingly, consolidated Wildorado Wind at December 31, 2005.

Deconsolidation of Variable Interest Entities—

       In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga project and, accordingly, deconsolidated the project at March 31, 2004.

Variable Interest Entities—

       EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it had significant variable interests in variable interest entities as defined in this Interpretation. As of December 31, 2005, these entities consisted of five equity investments (the Big 4 projects and the Sunrise project) that had interests in natural gas-fired facilities with a total generating capacity of 1,782 MW. An operations and maintenance subsidiary of EME operates the Big 4 projects, but EME does not supply the fuel consumed or purchase the power generated by these facilities. EME determined that it is not the primary beneficiary in these entities; accordingly, EME continues to account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities, which totaled $332 million as of December 31, 2005.

Note 8. Divestitures

Dispositions of Domestic Investments in Energy Plants

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

       On March 31, 2004, EME completed the sale of 100% of its stock of Mission Energy New York, Inc., which in turn owned a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., to a third party for a sales price of approximately $42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related to the planned disposition of this investment and a pre-tax loss of approximately $4 million during the first quarter of 2004 due to changes in the terms of the sale.

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

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Discontinued Operations

Tri Energy Project

       On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project pursuant to a Purchase Agreement, dated December 15, 2004, by and between EME and a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million. EME recorded an impairment charge of approximately $5 million during the fourth quarter of 2004 related to the planned disposition of this investment.

CBK Project

       On January 10, 2005, EME sold its 50% equity interest in the CBK project pursuant to a Purchase Agreement, dated November 5, 2004, by and between EME and Corporacion IMPSA S.A. Proceeds from the sale were approximately $104 million.

MEC International B.V.

       On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) pursuant to a Purchase Agreement, dated July 29, 2004, by and between EME and IPM. The purchase agreement was entered into following a competitive bidding process. The sale of MECIBV included the sale of EME's interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV and related assets was $2.0 billion.

Contact Energy

       On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited pursuant to a Purchase Agreement, dated July 20, 2004. The purchase agreement was entered into following a competitive bidding process. Consideration for the sale was NZ$1,101 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser.

Lakeland Project

       EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. Payments received to date include £13 million (approximately $24 million) in March 2005 and £18 million (approximately $31 million) in February 2006. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

Summarized Financial Information for Discontinued Operations

       In accordance with SFAS No. 144, all of the projects discussed above are classified as discontinued operations in the accompanying consolidated statements of income. Previously issued statements of

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operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. Summarized results of discontinued operations are as follows:

	Years Ended December 31,
	2005			2004		2003
	(in millions)
Total operating revenues	$	—		$	1,281	$	1,403
Income (loss) before income taxes and minority interest		(20	)		256		252
Provision (benefit) for income taxes		(44	)		48		90
Minority interest		—			51		38
Income from operations of discontinued foreign subsidiaries		24			157		124
Gain on sale before income taxes		9			532		—
Gain on sale after income taxes		5			533		—

       During the third quarter of 2005, EME recorded tax benefit adjustments of $28 million, which resulted from completion of the 2004 federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004 and are included in "Provision (benefit) for income taxes" in the above table. During the fourth quarter of 2005, EME recorded an after-tax charge of $25 million related to a tax indemnity for a project sold to IPM in December 2004. This charge related to an adverse tax court ruling in Spain, which the local company plans to appeal.

       The assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets at December 31, 2005 and 2004. The balance sheet at December 31, 2005 and 2004 was comprised of current assets of $1 million and $4 million, respectively, and investments in unconsolidated affiliates of $107 million at December 31, 2004, which was principally related to EME's investment in the Tri Energy and CBK projects. In addition, there were current liabilities of $1 million at December 31, 2004 and deferred revenue of $4 million at the end of each period.

       EME has operated as one segment since the third quarter of 2004 due to the sale of most of its international assets. Prior periods' segment information have not been presented due to lack of continuing significance.

Note 9. Investments in Unconsolidated Affiliates

       Investments in unconsolidated affiliates, generally 50% or less owned partnerships and corporations, are accounted for by the equity method. These investments are primarily in energy projects. For 2003, the summarized financial information included Four Star Oil & Gas Company. EME sold 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, on January 7, 2004. For 2003, the summarized financial information also included Gordonsville Energy and Brooklyn Navy Yard. EME sold its interests in Gordonsville Energy and Brooklyn Navy Yard on November 21, 2003 and March 31, 2004, respectively. Therefore, Gordonsville Energy, Brooklyn Navy Yard and Four Star Oil & Gas are not included in the balances for 2004 and 2005. The difference between the carrying value of these equity investments and the underlying equity in the net assets amounted to $2 million at December 31, 2005. The differences are being amortized over the life of the

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energy projects. The following table presents summarized financial information of the investments in unconsolidated affiliates:

			2005		2004
			(in millions)
Investments in Unconsolidated Affiliates
	Equity investment		$	365	$	428
	Loan receivable			26		26
		Total	$	391	$	454

       EME's subsidiaries have provided loans or advances related to certain projects. The loan receivable at December 31, 2005 and 2004 consists of a $26 million, 5% interest promissory note, interest payable semiannually, due April 2008. The undistributed earnings of equity method investments were $117 million in 2005 and $160 million in 2004.

       The following table presents summarized financial information of the investments in unconsolidated affiliates accounted for by the equity method:

		Years Ended December 31,
		2005		2004		2003
		(in millions)
Revenues		$	1,830	$	1,617	$	1,988
Expenses			1,452		1,192		1,529
Income before accounting change			378		425		459
Cumulative effect of change in accounting, net of tax			—		—		(7	)
	Net income	$	378	$	425	$	452

		December 31,
		2005		2004
		(in millions)
Current assets		$	665	$	624
Noncurrent assets			1,145		1,224
	Total assets	$	1,810	$	1,848
Current liabilities		$	439	$	347
Noncurrent liabilities			644		674
Equity			727		827
	Total liabilities and equity	$	1,810	$	1,848

       The majority of noncurrent liabilities are comprised of project financing arrangements that are non-recourse to EME.

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       The following table presents, as of December 31, 2005, the investments in unconsolidated affiliates accounted for by the equity method that represent at least five percent (5%) of EME's income before tax or in which EME has an investment balance greater than $50 million.

Unconsolidated Affiliates	Location	Investment at December 31, 2005		Ownership Interest at December 31, 2005		Operating Status
		(in millions)
Sunrise	Fellows, CA	$	107	50	%	Operating gas-fired facility
Watson	Carson, CA		85	49	%	Operating cogeneration facility
Midway-Sunset	Fellows, CA		53	50	%	Operating cogeneration facility
Sycamore	Bakersfield, CA		50	50	%	Operating cogeneration facility
Kern River	Bakersfield, CA		37	50	%	Operating cogeneration facility

Impairment Loss on Equity Method Investment

       During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash flows. The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest. The March Point project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil) under a steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements purchased at current market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the first nine months of 2005, long-term natural gas prices increased substantially, thereby adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a $55 million charge during the third quarter of 2005.

Note 10. Property, Plant and Equipment

       Property, plant and equipment consist of the following:

		December 31,
		2005		2004
		(in millions)
Power plant facilities		$	2,131	$	1,966
Leasehold improvements			90		80
Emission allowances			1,305		1,305
Construction in progress			34		33
Equipment, furniture and fixtures			92		108
Capitalized leased equipment			1		1
			3,653		3,493
Less accumulated depreciation and amortization			798		709
	Net property, plant and equipment	$	2,855	$	2,784

       In connection with Midwest Generation's financing activities, EME has given first and second priority security interests in substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants and receivables of EMMT directly related to Midwest

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Generation's hedging activities. The amount of assets pledged or mortgaged totaled approximately $2.9 billion at December 31, 2005. In addition to these assets, Midwest Generation's membership interests and the capital stock of Edison Mission Midwest Holdings were pledged. Emission allowances have not been pledged.

Note 11. Financial Instruments

Long-Term Obligations

       Long-term obligations include both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay such obligations. At December 31, 2005, recourse debt totaled $1.7 billion and non-recourse project debt totaled $1.7 billion. At December 31, 2005, EME had no borrowings outstanding on the $98 million secured line of credit that matures on April 27, 2007. Long-term obligations consist of the following:

			December 31,
			2005		2004
			(in millions)
Recourse
EME (parent only)
	Senior Notes, net
		due 2008 (10.0%)	$	400	$	400
		due 2009 (7.73%)		598		598
		due 2011 (9.875%)		600		600
Long-Term Obligations—Affiliate				78		78
Junior Subordinated Debentures				—		155
Non-recourse
Due to EME Funding Corp.—Long-Term Obligation due 2005-2008 (7.33%)				92		139
EME CP Holdings Co.
	Note Purchase Agreement due 2015 (7.31%)			79		81
Midwest Generation, LLC
	Second Priority Senior Secured Notes due 2034 (8.75%)			1,000		1,000
	Credit Agreement due 2011 (LIBOR+1.75%) (5.91% at 12/31/05)			333		667
	$500 million Credit Revolver due 2011 (LIBOR+1.75%) (6.12% at 12/31/05)			170		—
Other				3		—
Subtotal			$	3,353	$	3,718
Less current maturities of long-term obligations				50		211
Total			$	3,303	$	3,507

Midwest Generation, LLC Financing

       On December 15, 2005, Midwest Generation, LLC completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of Midwest Generation's existing credit facility, previously amended and restated on April 18, 2005. The credit facility, as previously amended and restated, provided for approximately $343 million of first priority secured institutional term loans due in 2011 and $500 million of first priority secured revolving credit, working capital facilities, $200 million due in 2009 and $300 million due in 2011, with a lender option to require prepayment in 2010.

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       The refinancing consisted of, among other things, a reduction in the interest rate applicable to the term loan and the working capital facilities, and a modification of financial covenants. After giving effect to the refinancing, all the facilities carry a lower interest rate of LIBOR + 1.75%. The maturity date of the repriced term loan remains 2011. The previously existing working capital facilities were combined into one $500 million facility, maturing in 2011, with a lender option to require prepayment in 2010. Also, as part of the refinancing, Midwest Generation's financial covenants were modified, with its consolidated interest coverage ratio for the immediately preceding four consecutive fiscal quarters required to be at least 1.40 to 1 (increased from 1.25 to 1), and its secured leverage ratio for the 12-month period ended on the last day of the immediately preceding fiscal quarter required to be no greater than 7.25 to 1 (reduced from 8.75 to 1).

       Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of its excess cash flow (as defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributed to the equity contribution equals the amount of the equity contribution. Because EME made a $300 million equity contribution to Midwest Generation on April 19, 2005, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to the equity contribution equals $300 million. After taking into account Midwest Generation's most recent distribution in January 2006, $177 million of the equity contribution is still available for this purpose. To the extent Midwest Generation makes a distribution which is not fully attributed to an equity contribution, Midwest Generation is required to make concurrently with such distribution an offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the amount attributed to the equity contribution.

Long-term Obligations—Affiliates

       During 1997, EME declared a dividend of $78 million to The Mission Group (now known as Edison Mission Group, Inc.) which was recorded as a note payable due in June 2007 with interest at LIBOR plus 0.275% (4.36% at December 31, 2005). The note was subsequently exchanged for two notes with the same terms and conditions and assigned to other subsidiaries of Edison International.

Junior Subordinated Debentures

       In November 1994, Mission Capital, L.P., a limited partnership of which EME is the sole general partner, issued 3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a price of $25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024 which were issued by EME in November 1994. On January 25, 2005, all of these securities were redeemed for a purchase price of 100% of the principal amount, plus accrued interest through January 25, 2005 for a total of $88 million. During August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly Income Preferred Securities, Series B at a price of $25 per security and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025 which were issued by EME in August 1995. On January 25, 2005 all of these securities were redeemed for a purchase price of 100% of the principal amount, plus accrued interest through January 25, 2005 for a total of $63 million. On January 25, 2005, EME repaid the junior subordinated debentures and consequently repaid the cumulative monthly income preferred securities (MIPS) of $150 million. In connection with the repayment of the junior subordinated debentures, EME recorded a $4 million loss on early extinguishment of debt during the first quarter of 2005.

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Annual Maturities on Long-Term Obligations

       Annual maturities on long-term debt at December 31, 2005, for the next five years are summarized as follows: 2006—$50 million; 2007—$129 million; 2008—$416 million; 2009—$610 million; and 2010—$11 million.

Standby Letters of Credit

       As of December 31, 2005, standby letters of credit aggregated to $33 million and were scheduled to expire as follows: $28 million in 2006 and $5 million in 2007.

Restricted Cash

       Several cash balances are restricted primarily to pay amounts required for debt payments and letter of credit expenses. The total restricted cash included in EME's consolidated balance sheet was $105 million at December 31, 2005 and $155 million at December 31, 2004. Included in restricted cash were debt service reserves of $40 million and $76 million at December 31, 2005 and 2004, respectively, and collateral reserves of $65 million and $79 million at December 31, 2005 and 2004, respectively.

       Each of EME's direct and indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Any asset of any of those subsidiaries may not be available to satisfy EME's obligations or any obligations of EME's other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of these subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or its affiliates.

Fair Values of Non-Derivative Financial Instruments

       The carrying amount of cash and cash equivalents, trade accounts receivables and payables contained in EME's consolidated balance sheet approximates fair value. The following table summarizes the carrying amounts and fair values for outstanding non-derivative financial instruments (in millions):

		December 31, 2005				December 31, 2004
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Instruments
Non-derivatives:
	Long-term obligations	$	3,353	$	3,692	$	3,718	$	4,153

       In assessing the fair value of EME's financial instruments, EME uses a variety of methods and assumptions that are based on market conditions and risks existing at each balance sheet date. Quoted market prices for the same or similar instruments are used for long-term obligations.

Note 12. Risk Management and Derivative Financial Instruments

       EME's risk management policy allows for the use of derivative financial instruments to limit financial exposure on EME's investments and to manage exposure from fluctuations in electricity, capacity and fuel prices, emission allowances, transmission rights, and interest rates for both trading and non-trading purposes.

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Commodity Price Risk Management

       EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated. EME uses "value at risk" to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities, and its trading 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.

       In order to provide more predictable earnings and cash flow, EME may hedge a portion of the electric output of its merchant plants. When appropriate, EME manages the spread between the electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is no assurance that contracts to hedge changes in market prices will be effective.

Interest Rate Risk Management

       Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of EME's project financings.

Credit Risk

       In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted 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 a counterparty defaulted.

       To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the 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. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no

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assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

       EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power plant.

       In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

       EME derived a significant source of its operating revenues from electric power sold into the PJM market from the Homer City facilities in the past three fiscal years and from the Illinois Plants in 2005 and 2004. Sales into the PJM pool accounted for approximately 70%, 23% and 18% of EME's consolidated operating revenues for the years ended December 31, 2005, 2004 and 2003, respectively. Moody's Investor Service rates PJM's senior unsecured debt Aa3. PJM, an independent system operator with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default is shared by all members based upon a predetermined formula. At December 31, 2005, EME's account receivable due from PJM was $223 million.

       In 2004 and 2003, EME also 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. These power purchase agreements had all expired by the end of 2004. Exelon Generation accounted for 36% in 2004 and 40% in 2003 of EME's consolidated operating revenues.

       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.

Non-Trading Derivative Financial Instruments

       The following table summarizes the carrying amounts and fair values for outstanding derivative financial instruments used in EME's continuing operations for purposes other than trading by risk category (in millions):

		December 31, 2005						December 31, 2004
		Carrying Amount			Fair Value			Carrying Amount		Fair Value
Commodity price:
	Electricity	$	(434	)	$	(434	)	$	10	$	10

       In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance

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sheet date. The fair value of the commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors.

Energy Trading

       EME engages in energy trading activities in markets where its merchant power plants are located. EME trades power, fuel and transmission using products available over the counter, through exchanges and from independent system operators. Energy trading activity is limited by EME's risk management policies, including a limit on value at risk.

       The carrying amounts and fair values of the commodity financial instruments related to energy trading activities as of December 31, 2005 and December 31, 2004, are set forth below (in millions):

	December 31, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities
Electricity	$	127	$	27	$	125	$	36
Other		1		—		—		—
Total	$	128	$	27	$	125	$	36

       Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement.

       EME recorded net gains of approximately $202 million, $29 million and $40 million in 2005, 2004 and 2003, respectively, arising from energy trading activities reflected in net gains from price risk management and energy trading in EME's consolidated income statement. In accordance with Emerging Issues Task Force No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," EME netted 3.9 million MWh and 2.9 million MWh of sales and purchases of physically settled, gross purchases and sales during 2005 and 2004, respectively.

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Note 13. Income Taxes

Current and Deferred Taxes

       The provision (benefit) for income taxes is comprised of the following:

			Years Ended December 31,
			2005			2004			2003
			(in millions)
Continuing Operations:
Current
	Federal		$	230		$	(311	)	$	(61	)
	State			38			(68	)		(38	)
	Foreign			(1	)		(1	)		6
		Total current		267			(380	)		(93	)
Deferred
	Federal		$	(36	)	$	(13	)	$	(25	)
	State			(10	)		(8	)		2
	Foreign			—			—			2
		Total deferred		(46	)		(21	)		(21	)
Provision (benefit) for income taxes from continuing operations				221			(401	)		(114	)
Discontinued operations				(40	)		47			91
Change in accounting				(1	)		—			(4	)
		Total	$	180		$	(354	)	$	(27	)

       The components of income (loss) before income taxes and minority interest applicable to continuing operations, discontinued operations, and cumulative effect of change in accounting are as follows:

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Continuing Operations
	U.S.	$	617		$	(974	)	$	(219	)
	Foreign		8			6			12
	Total, continuing operations		625			(968	)		(207	)
Discontinued operations			(11	)		788			252
Change in accounting			(2	)		—			(13	)
	Total	$	612		$	(180	)	$	32

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       Variations from the 35% federal statutory rate for income from continuing operations are as follows:

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Expected provision for federal income taxes		$	218		$	(339	)	$	(73	)
Increase (decrease) in the provision for taxes resulting from:
	State tax—net of federal deduction		20			(50	)		(25	)
	Dividends received deduction		—			—			(12	)
	Taxes on foreign operations at different rates		(4	)		(3	)		4
	Resolution of IRS audit issue		(11	)		—			—
	Other		(2	)		(9	)		(8	)
	Provision (benefit) for income taxes	$	221		$	(401	)	$	(114	)
	Effective tax rate		35%			41%			55%

       The components of the net accumulated deferred income tax liability are:

			December 31,
			2005		2004
			(in millions)
Deferred tax assets
	Accrued charges		$	126	$	68
	Price risk management			162		(12	)
	Deferred income			5		3
	Other			—		1
		Total		293		60
Deferred tax liabilities
	Basis differences.		$	297	$	246
	Tax credits, net			11		12
	Other			1		—
		Total		309		258
Deferred taxes and tax credits, net			$	16	$	198
Classification of accumulated deferred income taxes:
	Included in current assets		$	155	$	—
	Included in non-current liabilities		$	171	$	198

       State loss carryforwards for various states totaled $6 million and $13 million at December 31, 2005 and 2004, respectively, with expiration dates beginning in 2022.

       EME is, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions it takes in connection with the filing of its tax returns. Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in EME's opinion, it is unlikely that the resolution of any such matters will have a material adverse effect upon EME's financial condition or results of operations.

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Note 14. Employee Benefit Plans

Pension Plans

       Defined benefit pension plans (the non-executive plan has a cash balance feature) cover employees who fulfill minimum service and other requirements.

       At December 31, 2005 and 2004, the accumulated benefit obligations of the executive pension plans exceeded the related plan assets at the measurement dates. In accordance with accounting standards, EME's consolidated balance sheets include an additional minimum liability, with corresponding charges to intangible assets and shareholders' equity (through a charge to accumulated other comprehensive income).

       The expected contributions (all by the employer) are approximately $14 million for the year ended December 31, 2006. This amount is subject to change based on, among other things, the limits established for federal tax deductibility.

       EME uses a December 31 measurement date for all of its plans. The fair value of plan assets is determined by market value.

       Information on plan assets and benefit obligations is shown below:

			Years Ended December 31,
			2005			2004
			(in millions)
Change in projected benefit obligation
	Projected benefit obligation at beginning of year		$	153		$	119
	Service cost			16			16
	Interest cost			8			7
	Actuarial (gains) loss			(10	)		11
	Benefits paid			(8	)		—
		Projected benefit obligation at end of year	$	159		$	153
Accumulated benefit obligation at end of year			$	137		$	123
Change in plan assets
	Fair value of plan assets at beginning of year		$	77		$	53
	Actual return on plan assets			9			7
	Employer contributions			13			17
	Benefits paid			(8	)		—
		Fair value of plan assets at end of year	$	91		$	77
Funded status			$	(68	)	$	(76	)
Unrecognized net loss				14			29
Unrecognized prior service cost				1			2
Recorded liability			$	(53	)	$	(45	)

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	Years Ended December 31,
	2005			2004
	(in millions)
Additional detail of amounts recognized in balance sheets:
Intangible asset	$	1		$	1
Accumulated other comprehensive income		(5	)		(2	)
Pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation	$	159		$	99
Accumulated benefit obligation		137			72
Fair value of plan assets		91			45
Weighted-average assumptions at end of year:
Discount rate		5.50%			5.50%
Rate of compensation increase		5.00%			5.00%

       Components of pension expense are:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Service cost	$	16		$	16		$	14
Interest cost		8			7			6
Expected return on plan assets		(6	)		(4	)		(4	)
Net amortization and deferral		1			1			2
Total expense recognized	$	19		$	20		$	18
Change in accumulated other comprehensive income		(3	)		(2	)		—
Weighted-average assumptions:
Discount rate		5.50%			6.00%			6.50%
Rate of compensation increase		5.00%			5.00%			5.00%
Expected return on plan assets		7.50%			7.50%			8.50%

       Asset allocations for plans are:

		December 31,
	Target for 2006
		2005	2004
United States equity	45%	47%	47%
Non-United States equity	25%	26%	25%
Private equity	4%	2%	2%
Fixed income	26%	25%	26%

Postretirement Benefits Other Than Pensions

       Most non-union employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health and dental care, life insurance and other benefits. Eligibility depends on a number of factors, including the employee's hire date.

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       On December 8, 2003, President Bush signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act authorized a federal subsidy to be provided to plan sponsors for certain prescription drug benefits under Medicare. EME adopted FASB Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," for the effects of the Act, effective July 1, 2004, which reduced EME's accumulated benefits obligation by $3 million upon adoption.

       The expected contributions (all by the employer) for the postretirement benefits other than pensions are $1 million for the year ended December 31, 2006. This amount is subject to change based on, among other things, the limits established for federal tax deductibility.

       EME uses a December 31 measurement date.

       Information on plan assets and benefit obligations is shown below:

			Years Ended December 31,
			2005			2004
			(in millions)
Change in benefit obligation
	Benefit obligation at beginning of year		$	58		$	54
	Service cost			2			2
	Interest cost			4			3
	Amendments			—			1
	Actuarial loss (gain)			9			(1	)
	Benefits paid			(1	)		(1	)
	Benefit obligation at end of year		$	72		$	58
Change in plan assets
	Fair value of plan assets at beginning of year		$	—		$	—
	Employer contributions			1			1
	Benefits paid			(1	)		(1	)
		Fair value of plan assets at end of year	$	—		$	—
Funded status			$	(72	)	$	(58	)
Unrecognized net loss				22			14
Unrecognized prior service cost				(10	)		(12	)
Recorded liability			$	(60	)	$	(56	)
Assumed health care cost trend rates:
Rate assumed for following year				10.25%			10.00%
Ultimate rate				5.00%			5.00%
Year ultimate rate reached				2011			2010
Weighted-average assumptions at end of year:
Discount rate				5.50%			5.75%

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       Expense components of postretirement benefits are:

	Years Ended December 31,
	2005		2004			2003
	(in millions)
Service cost	$	2	$	2		$	2
Interest cost		4		3			3
Net amortization and deferral		—		(1	)		(1	)
Total expense	$	6	$	4		$	4
Assumed health care cost trend rates:
Current year		10.00%		12.00%			9.75%
Ultimate rate		5.00%		5.00%			5.00%
Year ultimate rate reached		2010		2010			2008
Weighted-average assumptions:
Discount rate		5.75%		6.25%			6.40%

       Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2005, by $13 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2005, by $11 million and annual aggregate service and interest costs by $1 million.

Discount Rate

       The discount rate enables EME to state expected future cash flows at a present value on the measurement date. EME selects its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. Three yield curves were considered: two corporate yield curves (Citigroup and AON) and a curve based on treasury rates (plus 90 basis points). EME also compared the yield curve analysis against the Moody's AA Corporate bond rate. At the December 31, 2005 measurement date, EME used a discount rate of 5.5% for both pensions and postretirement benefits other than pensions.

Description of Investment Strategies

       The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active and passive investment strategies within asset classes. EME employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches. Risk is controlled through diversification among multiple asset classes, managers, styles, and securities. Plan, asset class and individual manager performance is measured against targets. EME also monitors the stability of its investments managers' organizations.

       Allowable investment types include:

•

United States Equity: Common and preferred stocks of large, medium, and small companies which are predominantly United States-based.

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•

Non-United States Equity: Equity securities issued by companies domiciled outside the United States and in depository receipts which represent ownership of securities of non-United States companies.

•

Private Equity: Limited partnerships that invest in non-publicly traded entities.

•

Fixed Income: Fixed income securities issued or guaranteed by the United States government, non-United States governments, government agencies and instrumentalities, mortgage backed securities and corporate debt obligations. A small portion of the fixed income position may be held in debt securities that are below investment grade.

       Permitted ranges around asset class portfolio weights are plus or minus 5%. Where approved by the fiduciary investment committee, futures contracts are used for portfolio rebalancing and to approach fully invested portfolio positions. Where authorized, a few of the plans' investment managers employ limited use of derivatives, including futures contracts, options, options on futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.

Determination of the Expected Long-Term Rate of Return on Assets

       The overall expected long-term rate of return on assets assumption is based on the target asset allocation for plan assets, capital markets return forecasts for asset classes employed, and active management excess return expectations.

Capital Markets Return Forecasts

       The estimated total return for fixed income is based on an equilibrium yield for intermediate United States government bonds plus a premium for exposure to non-government bonds in the broad fixed income market. The equilibrium yield is based on analysis of historic data and is consistent with experience over various economic environments. The premium of the broad market over United States government bonds is a historic average premium. The estimated rate of return for equity is estimated to be a 3% premium over the estimated total return of intermediate United States government bonds. This value is determined by combining estimates of real earnings growth, dividend yields and inflation, each of which was determined using historical analysis. The rate of return for private equity is estimated to be a 5% premium over public equity, reflecting a premium for higher volatility and illiquidity.

Active Management Excess Return Expectations

       For asset classes that are actively managed, an excess return premium is added to the capital market return forecasts discussed above.

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Estimated Future Benefits Payable

       Estimated future benefits payable under the pension and other postretirement benefits as of December 31, 2005 are as follows:

Years Ended December 31,	Pension Plans		Other Postretirement Benefits(1)
	(in millions)
2006	$	5	$	1
2007		6		1
2008		7		2
2009		8		2
2010		9		2
2011-2015		70		16

        (1)   The impact of the medicare subsidy does not change the amounts reported in the table.

Employee Stock Plans

       A 401(k) plan is maintained to supplement eligible United States employees' retirement income. The plan received contributions from EME of $6 million in 2005, $5 million in 2004 and $6 million in 2003.

Note 15. Stock Compensation Plans

Stock-Based Compensation

       Under various plans, EME may grant stock options at exercise prices equal to the market price at the grant date and other awards based on Edison International common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of up to five years, with expense accruing evenly over the vesting period. Edison International has approximately 12.5 million shares remaining for future issuance under equity compensation plans.

       Most Edison International stock options issued prior to 2000 accrue dividend equivalents, subject to certain performance criteria. The 2003 to 2005 options accrue dividend equivalents for the first five years of the option term. Unless deferred, dividend equivalents accumulate without interest. The liability and associated expense is accrued each quarter for the dividend equivalents for each option year. At the end of the performance measurement period, the expense and related liability is adjusted accordingly. Upon exercise, the dividends are paid out and the associated liability is reduced on EME's consolidated balance sheet.

       The fair value for each option granted, reflecting the basis for the pro forma disclosures in Note 2, was determined as of the date of grant using the Black-Scholes option-pricing model. The following assumptions were used in determining fair value through the model:

	2005	2004	2003
Expected years until exercise	9-10	9-10	10
Risk-free interest rate	4.1% to 4.3%	4.0% to 4.3%	3.8% to 4.5%
Expected dividend yield	2.1% to 3.1%	2.7% to 3.7%	1.8%
Expected volatility	15% to 20%	19% to 22%	44% to 53%

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       The weighted-average fair value of options granted during 2005, 2004 and 2003 was $9.38 per share option, $6.60 per share option and $7.31 per share option, respectively.

       A summary of the status of Edison International's stock options granted to EME employees is as follows:

	Share Options		Exercise Price		Weighted Exercise Price
Outstanding, December 31, 2002	2,181,812		$	9.10 - $28.94	$	18.60
Granted	1,020,910		$	11.88 - $18.87	$	12.37
Transferred from (to) affiliates	(32,351	)	$	9.57 - $28.94	$	17.70
Forfeited	(315,788	)	$	9.57 - $28.94	$	23.09
Exercised	(69,769	)	$	9.10 - $20.19	$	14.12
Outstanding, December 31, 2003	2,784,814		$	9.10 - $28.94	$	15.95
Granted	1,212,026		$	21.88 - $29.09	$	22.02
Transferred from (to) affiliates	(69,924	)	$	12.29 - $28.13	$	15.85
Forfeited	(104,975	)	$	9.57 - $23.14	$	18.16
Exercised	(691,988	)	$	9.10 - $28.13	$	14.52
Outstanding, December 31, 2004	3,129,953		$	9.15 - $29.09	$	18.44
Granted	693,578		$	31.94 - $40.52	$	31.99
Transferred from (to) affiliates	790,394		$	12.29 - $46.47	$	21.56
Forfeited	(172,595	)	$	12.29 - $31.94	$	19.58
Exercised	(814,965	)	$	9.15 - $31.94	$	16.81
Outstanding, December 31, 2005	3,626,365		$	9.57 - $46.47	$	22.06

       A summary of stock options outstanding at December 31, 2005 is as follows:

	Outstanding				Exercisable
Range of Exercise Prices	Number of Options	Weighed Average Remaining Years of Contractual Life	Weighted Average Exercise Price		Number of Options	Weighted Average Exercise Price
$9.57 - $13.99	751,790	6.85	$	12.09	521,318	$	12.01
$14.00 - $20.99	626,597	5.75		18.65	536,879		18.69
$21.00 - $31.49	1,451,454	6.88		23.14	644,356		24.56
$31.50 - $46.47	796,524	9.03		32.16	15,337		31.58
Total	3,626,365	7.15	$	22.06	1,717,890	$	18.98

       The number of options exercisable and their weighted-average exercise prices at December 31, 2004 and 2003 were 1,051,147 at $18.30 and 863,116 at $19.26, respectively.

Other Equity-Based Awards

       Performance shares were awarded in January 2003, January 2004 and January 2005 and vest at the end of December 2005, 2006 and 2007, respectively. The number of common shares paid out from the performance share awards depends on the performance of Edison International common stock relative to the stock performance of a specified group of companies. Performance share values are accrued ratably

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over the vesting period based on the value of the underlying Edison International common stock. The number of performance shares granted and their weighted-average grant-date value for 2005, 2004 and 2003 were 51,843 at $32.04, 89,911 at $21.94 and 147,367 at $12.29, respectively. In the pro forma disclosure reflected in Note 2, the portions of these performance shares settled in stock, which were half of the total shares outstanding, were treated as equity awards. The weighted-average grant-date fair values of these performance shares were $46.09, $33.62, and $21.42, for 2005, 2004, and 2003, respectively.

       EME measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation program was approximately $20 million, $24 million and $11 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Note 16. Commitments and Contingencies

Capital Improvements

       At December 31, 2005, EME's subsidiaries had firm commitments to spend approximately $8 million on capital expenditures in 2006 primarily for component replacement projects. These expenditures are planned to be financed by existing subsidiary credit facilities and cash generated from these operations.

Fuel Supply Contracts

       At December 31, 2005, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers. The remaining contracts' lengths range from one year to seven years. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $1.0 billion in the next five years summarized as follows: 2006—$367 million; 2007—$340 million; 2008—$147 million; 2009—$94 million; and 2010—$64 million.

Gas Transportation Agreements

       At December 31, 2005, EME had a contractual commitment to transport natural gas. EME's share of the commitment to pay minimum fees under its gas transportation agreement, which has a remaining contract length of 12 years, is currently estimated to aggregate $40 million in the next five years, $8 million each year, 2006 through 2010.

Coal Transportation Agreements

       At December 31, 2005, EME's subsidiaries had contractual commitments for the transport of coal to their respective facilities, with remaining contract lengths that range from one year to six years. Midwest Generation's primary contract is with Union Pacific Railroad (and various delivering carriers) which extends through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, Midwest Generation's contractual obligations for transportation are based on coal volumes set forth in their fuel supply contracts. EME Homer City commitments under its agreements are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses. Only a portion of total coal shipments to the Homer City facilities are shipped by rail. Trucking remains the predominant mode of transportation for coal shipments to the Homer City facilities. Based on the committed coal volumes in the fuel supply contracts described above, these minimum commitments are currently estimated to aggregate $680 million in the next five years, summarized as follows: 2006—$226 million; 2007—$216 million; 2008—$85 million; 2009—$76 million; and 2010—$77 million.

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Other Contractual Obligations

       At December 31, 2005, Midwest Generation was party to a long-term power purchase contract with Calumet Energy Team LLC entered into as part of the settlement agreement with Commonwealth Edison, which terminated Midwest Generation's obligation to build additional gas-fired generation in the Chicago area. The contract requires Midwest Generation to pay a monthly capacity payment and gives Midwest Generation an option to purchase energy from Calumet Energy Team at prices based primarily on operations and maintenance and fuel costs. These minimum commitments are currently estimated to aggregate $20.1 million in the next five years, summarized as follows: 2006—$3.8 million; 2007—$3.9 million; 2008—$4.0 million; and 2010—$4.3 million.

Commercial Commitments

Introduction

       EME and certain of is subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, standby letters of credit, guarantees of debt and indemnifications.

Turbine Commitments

       At December 31, 2005, in connection with wind projects in development, EME had entered into agreements with two turbine vendors securing 105 turbines for $114 million in 2006 and $78 million in 2007. In addition, EME has options to acquire an additional 100 turbines for deliveries in 2007.

Guarantees and Indemnities

Tax Indemnity Agreements—

       In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins Station lease in April 2004 (See Note 5—Restructuring, Loss on Lease Termination, Asset Impairment and Other Charges), Midwest Generation will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

Indemnities Provided as Part of the Acquisition of the Illinois Plants—

       In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison take all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental

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liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

       Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were between 185 and 195 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2005. Midwest Generation had recorded a $67 million and $69 million liability at December 31, 2005 and 2004, respectively, related to this matter.

       The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities—

       In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. Payments would be triggered under this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements—

       The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. The right of first refusal matter has been submitted to arbitration, with hearings having been conducted during February 2006. It is expected that a decision of the arbitration panel will be rendered in the coming months. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At December 31, 2005 and 2004, EME had recorded a liability of $122 million and $87 million, respectively, related to these matters.

       In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example,

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specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

       On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which held a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through January 2007. At December 31, 2005 and 2004, EME had recorded a liability of $8 million and $11 million, respectively, related to this indemnity.

Capacity Indemnification Agreements—

       EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project's power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of December 31, 2005, if payment were required, would be $124 million. EME has not recorded a liability related to these indemnities.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

       A subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement. This agreement runs through 2007. EME believes there is sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Contingencies

Litigation

       EME experiences routine litigation in the normal course of its business. Pending routine litigation is not expected to have a material adverse effect on EME's consolidated financial position or results of operations.

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Environmental Matters and Regulations

Introduction

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

       Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects, which may involve significant capital expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by regulatory authorities.

Federal—United States of America

Clean Air Act

Clean Air Interstate Rule—

       On May 12, 2005, the Clean Air Interstate Rule (CAIR) was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address ozone attainment issues by reducing regional nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions. The CAIR reduces the current Clean Air Act Title IV Phase II SO2 emissions allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR also reduces regional NOx emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The CAIR has been challenged in court by state, environmental and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation.

       EME expects that compliance with the CAIR and the regulations and revised state implementation plans developed as a consequence of the CAIR will result in increased capital expenditures and operating expenses. Given the uncertainty of the requirements that will need to be implemented and the options available to meet the NOx and SO2 reductions fleetwide, EME at this time cannot accurately estimate the cost to meet these obligations. EME's approach to meeting these obligations will consist of a blending of capital expenditure and emission allowance purchases that will be based on an ongoing assessment of the dynamics of its market conditions.

Mercury Regulation—

       The Clean Air Mercury Rule (CAMR), published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual nationwide cap will be 38 tons. Emissions of mercury are to be reduced primarily by taking advantage of mercury reductions achieved by reducing SO2 and NOx emissions under the CAIR. In the second phase, which is

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to take effect in 2018, coal-fired power plants will be subject to a lower annual cap, which will reduce emissions nationwide to 15 tons. States may join the trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's suggested cap-and-trade program. Any program adopted by a state must be approved by the United States Environmental Protection Agency (US EPA).

       Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated as a hazardous air pollutant pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards. Litigation has been filed challenging the US EPA's rescission action and claiming that the agency should have imposed technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR. As a result of these challenges, the CAMR rules and timetables may change.

       If Illinois and Pennsylvania implement the CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, EME may have the option to purchase mercury emission allowances, to install pollution control equipment, to otherwise alter its operations to reduce mercury emissions, or to implement some combination thereof. If EME were to implement environmental control technology at its Homer City facilities instead of purchasing allowances to comply with the CAMR and other Clean Air Act developments described herein, it currently estimates capital expenditures for such improvements to be approximately $350 million to $400 million in the 2006-2010 timeframe. However, because the mercury state implementation plans are not due until the fourth quarter of 2006 and such plans may not adopt the CAMR's cap-and-trade program, and because EME cannot predict the outcome of the legal challenge to the CAMR and the US EPA's decision not to regulate mercury emissions pursuant to Section 112 of the federal Clean Air Act, the full impact of this regulation currently cannot be assessed. Additional capital costs, particularly for the Illinois coal units, related to these regulations could be required in the future and they could be material. EME's approach to meeting these obligations will continue to be based upon an ongoing assessment of applicable legal requirements and market conditions.

National Ambient Air Quality Standards—

       Ambient air quality standards for ozone and fine particulate matter were adopted by the US EPA in July 1997. These standards were challenged in the courts, and on March 26, 2002, the United States Court of Appeals for the District of Columbia Circuit upheld the US EPA's revised ozone and fine particulate matter ambient air quality standards.

       The US EPA designated non-attainment areas for the 8-hour ozone standard on April 30, 2004, and for the fine particulate standard on January 5, 2005. Almost all of EME's facilities are located in counties that have been identified as being in non-attainment with both standards. States are required to revise their implementation plans for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised state implementation plans are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates. Any additional obligations on EME's facilities to further reduce their emissions of SO2, NOx and fine particulates to address local non-attainment with the 8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans. Depending upon the final standards that are adopted, EME may incur substantial costs or experience other financial impacts resulting from required capital improvements or operational changes.

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       On January 17, 2006, the US EPA proposed revisions to its fine particulate standard. Under the proposal, the annual standard would remain the same but the 24-hour fine particulate standard would be significantly lowered. The US EPA is under court order to issue a final rule in December 2006. If the US EPA retains its proposed new 24-hour standard or lowers the annual standard, states may be required to impose further emission reductions beyond what would be necessary to meet the existing standards. Although EME may incur substantial costs or experience financial impacts as a result of any new standards, the uncertainties associated with this ongoing rulemaking at this time render EME unable to accurately estimate the costs to meet any such obligation. EME anticipates, however, that any such further emission reduction obligations would not be imposed until 2010 at the earliest.

Regional Haze—

       The goal of the 1999 regional haze regulations is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions in 60 years. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install Best Available Retrofit Technology (BART) or implement other control strategies to meet regional haze control requirements. States are required to revise their state implementation plans to demonstrate reasonable further progress towards meeting regional haze goals. Emission reductions that are achieved through other ongoing control programs may be sufficient to demonstrate reasonable progress toward the long-term goal, particularly for the first 10 to 15 year phase of the program. States must develop implementation plans by December 2007. It is possible that sources that are subject to the CAIR will be able to satisfy their obligations under the regional haze regulations through compliance with the more stringent CAIR. However, until the state implementation plans are revised, EME cannot predict whether it will be required to install BART or implement other control strategies, and cannot identify the financial impacts of any additional control requirements.

New Source Review Requirements—

       Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address Clean Air Act New Source Review (NSR) compliance issues at the nation's coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, in the event that modifications are made to air emissions sources at a facility. The US EPA's strategy included both the filing of a number of suits against power plant owners, and the issuance of a number of administrative notices of violation to power plant owners alleging NSR violations. Neither EME nor any of its subsidiaries has been named as a defendant in these lawsuits and have not received any administrative Notices of Violation alleging NSR violations at any of their facilities.

       In response to conflicting court decisions concerning the applicable emissions test used to determine whether an operational or physical change at an electric generating station would require the plant to install additional pollution controls, the US EPA, on October 13, 2005, proposed a change to the NSR program. The proposal put forth several options for a new emissions test based on the impact of a facility modification on a facility's maximum hourly emissions or its emissions per unit of energy produced. The existing NSR emissions test is based on the impact of a modification on a generating station's net annual emissions.

       In October 2005, the US EPA announced a revised NSR strategy to take account of recent US EPA rulemakings, such as the CAIR and regional haze rules, affecting coal-fired power plants. Under the revised strategy, while the US EPA will continue to pursue filed cases and cases in active negotiation, it intends to shift its future enforcement focus from coal-fired power plants to other sectors where compliance assurance activities have the potential to produce significant environmental benefits.

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       Prior to EME's purchase of the Homer City facilities, the US EPA requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning physical changes at the plant. This request was part of the US EPA's industry-wide investigation of compliance by coal-fired plants with the Clean Air Act NSR requirements. On February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois coal plants from the US EPA. On July 28, 2003, Commonwealth Edison received a substantially similar request for information from the US EPA related to these same plants. Under date of February 1, 2005, the US EPA submitted a request for additional information to Midwest Generation. Midwest Generation has provided responses to these requests. Other than these requests for information, no NSR enforcement-related proceedings have been initiated by the US EPA with respect to any of EME's facilities. See "State—Illinois—Air Quality."

       Developments with respect to changes to the NSR program and NSR enforcement will continue to be monitored by EME to assess what implications, if any, they will have on the operation of power plants owned or operated by EME or its subsidiaries, or on EME's results of operations or financial position.

Clean Water Act—Cooling Water Intake Structures

       On July 9, 2004, the US EPA published the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for cooling purposes. The purpose of the regulation is to reduce substantially the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems. Pursuant to the regulation, a demonstration study must be conducted when applying for a new or renewed National Pollutant Discharge Elimination System (NPDES) wastewater discharge permit. If one can demonstrate that the costs of meeting the presumptive standards set forth in the regulation are significantly greater than the costs that the US EPA assumed in its rule making or are significantly disproportionate to the expected environmental benefits, a site-specific analysis may be performed to establish alternative standards. Depending on the findings of the demonstration studies, cooling towers and/or other mechanical means of reducing impingement/ entrainment may be required. EME has begun to collect impingement and entrainment data at its potentially affected Midwest Generation facilities in Illinois to begin the process of determining what corrective actions may need to be taken.

       After the final promulgation of the Phase II cooling water intake structure regulation, legal challenges were filed by environmental groups, the attorneys general for six states, a utility trade association and several individual electric power generating companies. These cases have been consolidated and transferred to the United States Court of Appeals for the Second Circuit. A briefing schedule has been established for the case and a decision is not expected until sometime in 2006. The final requirements of the Phase II rule will not be fully known until these appeals are resolved and, if necessary, the regulation is revised by the US EPA. Although the Phase II rule could have a material impact on EME's operations, EME cannot reasonably determine the financial impact on it at this time because it is in the beginning stages of collecting the data required by the regulation and due to the legal challenges mentioned above which may affect the obligations imposed by the rule.

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Federal Legislative Initiatives

       There have been a number of bills introduced in Congress that would amend the Clean Air Act to specifically target emissions of specific pollutants from electric utility generating stations. These bills would mandate reductions in emissions of NOx, SO2 and mercury. Some bills would also impose limitations on carbon dioxide emissions. The various proposals differ in many details, including the timing of any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these bills with existing legal requirements. There is significant uncertainty as to whether any of the proposed legislative initiatives will pass in its current form or whether any compromise can be reached that would facilitate passage of legislation. Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

Environmental Remediation

       Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs to remediate releases of hazardous substances from such facilities even where the disposal of such wastes was undertaken in compliance with applicable laws. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several.

       With respect to EME's potential liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $2 million at December 31, 2005 for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for environmental activity where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

       Federal, state and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor condition or in the event of construction, remodeling, renovation or demolition of a building. Those laws and regulations may impose liability for release of asbestos-containing materials and may provide for the ability of third parties to seek recovery from owners or operators of these properties for personal injury associated with asbestos-containing materials. In connection with the ownership and operation of its facilities, EME may be liable for these costs. EME has agreed to indemnify the sellers of the Illinois Plants and the Homer City

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facilities with respect to specified environmental liabilities. See "—Commercial Commitments—Guarantees and Indemnities" for a discussion of these indemnities.

State—Illinois

Air Quality

       Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NOx emission rate of 0.25 lb NOx/mmBtu of heat input. This limitation is commonly referred to as the East St. Louis State Implementation Plan. This regulation is a State of Illinois requirement. Each of the Illinois Plants complied with this standard in 2004. Beginning with the 2004 ozone season, the Illinois Plants became subject to the federally mandated "NOx SIP Call" regulation that provided ozone-season NOx emission allowances to a 19-state region east of the Mississippi. This program provides for NOx allowance trading similar to the SO2 (acid rain) trading program already in effect. EME has qualified for early reduction allowances by reducing NOx emissions at various plants ahead of the imposed deadline. Additionally, the installation of emission control technology at certain plants has demonstrated over-compliance at those individual plants with the pending NOx emission limitations. Finally, NOx emission trading will be utilized, as needed, to comply with any shortfall at plants where installation of emission control technology has demonstrated reductions at levels short of the NOx limitations.

       During 2004, the Illinois Plants stayed within their NOx allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois Plants used banked allowances, along with some purchased allowances, to stay within their NOx allocations. After 2005, EME plans to continue to purchase allowances while evaluating the costs and benefits of various technologies to determine whether any additional pollution controls should be installed at the Illinois facilities.

       On January 5, 2006, Illinois Governor Rod Blagojevich announced that he was directing the Illinois Environmental Protection Agency to draft rules that would impose state limits on mercury emissions from coal-fired power plants which would be more stringent than the US EPA's CAMR issued in May 2005. Illinois is required to submit a state implementation plan (SIP) for CAMR to the US EPA by November 17, 2006. The Governor or his spokespersons have said that rules to be submitted to the Illinois Pollution Control Board will require a 90% reduction in mercury emissions averaged across company-owned Illinois generators and a minimum reduction of 75% for individual generating units by June 30, 2009. A 90% reduction at each generating unit would be required by 2013. Buying or selling of emission allowances under the CAMR federal cap and trade program would be prohibited. The Pollution Control Board must act on proposed rules submitted by the Illinois EPA after evidentiary hearings, including the presentation and cross-examination of expert testimony. After the Pollution Control Board adopts rules, they must be submitted to the General Assembly's Joint Committee on Administrative Rules for notice, hearing, and adoption, rejection or modification. Rules adopted through such state proceedings are also subject to court appeal. EME is not able at this time to predict the final form of these rules or provide an estimate of their financial impact.

       During 2006, the Illinois EPA is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. This SIP is to be submitted to the US EPA by September 11, 2006. The Illinois EPA has also begun to develop SIPs to meet National Ambient Air Quality Standards for 8-hour ozone and fine particulates. These SIPs will be developed with the intent of bringing non-attainment areas, such as Chicago, into attainment. They are expected to deal with all emission sources, not just power generators, and to address emissions of NOx, SO2, and Volatile Organic

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Carbon. These SIPs are to be submitted to the US EPA by June 15, 2007 for 8-hour ozone, and by April 5, 2008 for fine particulates. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

       The Illinois EPA is reviewing the water quality standards for the Des Plaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. An upgraded use classification could result in more stringent limits being applied to wastewater discharges to the river from these plants. If the existing use classification is changed, the limits on the temperature of the discharges from the Joliet and Will County plants may be made more stringent. The Illinois EPA has also begun a review of the water quality standards for the Chicago River and Chicago Sanitary and Ship Canal which are adjacent to the Fisk and Crawford Stations. Proposed changes to the existing standards are still being developed. Accordingly, EME is not able to estimate the financial impact of potential changes to the water quality standards. However, the cost of additional cooling water treatment, if required, could be substantial.

State—Pennsylvania

Air Quality

       During 2006, the Pennsylvania Department of Environmental Protection (PADEP) is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. This SIP is to be submitted to the US EPA by September 11, 2006. The Ozone Transport Commission, of which Pennsylvania is a member, is developing a model rule that would continue to allow SO2 and NOx emissions trading, but would impose more stringent limits on SO2 and NOx emissions and would phase in these reductions more quickly than is required by CAIR. EME does not know whether the northeast states will ultimately agree to this model rule or whether Pennsylvania will implement such a rule. Pennsylvania is also required to develop a SIP to implement the federal CAMR, which SIP is to be submitted to the US EPA by November 17, 2006. With respect to mercury, the PADEP has recently announced that it plans to issue a proposed rule that would require coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015. The proposed rule would not allow the use of emissions trading to achieve compliance. However, the proposal would apparently allow facilities to comply with the mercury regulation by installing specific pollution control technology for sulfur dioxide and nitrogen oxides and by burning 100% bituminous coal. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

       The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas desulfurization system at the Homer City facilities has exceeded the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME was notified in April 2002 by PADEP that it was included in the Quarterly Noncompliance Report submitted to the US EPA. EME investigated a number of technical alternatives for maximizing the level of selenium removal in the discharge and performed various pilot studies. While some of the pilot studies improved the performance of the treatment system, the discharge still was not able to consistently meet the selenium effluent limits. EME identified additional options for achieving the selenium limits, and, with PADEP's approval, has undertaken a pilot program utilizing biological treatment. EME prepared a draft of a consent order and agreement addressing the selenium issue and presented it to PADEP for consideration in connection with the renewal of the station's NPDES permit. PADEP has included civil penalties in consent agreements

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related to other facilities with selenium treatment issues, but the amount of civil penalties that may be assessed against EME cannot be estimated at this time.

Climate Change

       The Kyoto Protocol on climate change officially came into effect on February 16, 2005. Under the Kyoto Protocol, the United States would have been required, by 2008-2012, to reduce its greenhouse gas emissions, such as carbon dioxide, by 7% from 1990 levels. Under the Bush administration, however, the United States has chosen not to pursue ratification of the Kyoto Protocol. Instead, the Bush administration has proposed several alternatives to mandatory reductions of greenhouse gases.

       There have been several petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. Also, in 2004, several states and environmental organizations brought a complaint in federal court in New York, alleging that several electric utility corporations are jointly and severally liable under a theory of public nuisance for damages caused by the alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. Neither EME nor its subsidiaries were named as defendants in the complaint. The case was dismissed and is currently on appeal with the United States Court of Appeals for the Second Circuit.

       On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap and trade greenhouse gas program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule is scheduled to be announced within the next few months. The current proposal is to commence the program in 2009 by setting a cap (for the 2009 to 2015 period) on allowances based on carbon dioxide emissions from 2000 to 2004 and reducing emissions by 10% between 2015 and 2020. The Memorandum of Understanding provides that at least 25% of the state allowance allocations be set aside for public purposes, suggesting that from the commencement of the program, generators subject to the RGGI may receive allowances that are materially less than their carbon dioxide emissions. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania has participated as an observer of the process. If Pennsylvania were to join the RGGI, this could have a material impact on EME's Homer City facility.

       In California, Governor Schwarzenegger issued an executive order on June 1, 2005, setting forth targets for greenhouse gas reductions. The targets call for a reduction of greenhouse gas emissions to 2000 levels by 2010; a reduction of greenhouse gas emissions to 1990 levels by 2020; and a reduction of greenhouse gas emissions to 80% below 1990 levels by 2050. The California Public Utilities Commission is addressing climate change related issues in various regulatory proceedings.

       The ultimate outcome of the climate change debate could have a significant economic effect on EME. Any legal obligation that would require EME to reduce substantially its emissions of carbon dioxide would likely require extensive mitigation efforts and would raise considerable uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generating facilities.

Note 17. Lease Commitments

       EME leases office space, property and equipment under noncancelable lease agreements that expire in various years through 2019.

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       Future minimum payments for operating leases at December 31, 2005 are:

Years Ending December 31,	Operating Leases
	(in millions)
2006	$	362
2007		360
2008		357
2009		353
2010		340
Thereafter		2,983
Total future commitments	$	4,755

       Operating lease expense amounted to $201 million, $210 million and $234 million in 2005, 2004 and 2003, respectively.

Sale-Leaseback Transactions

       On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City facilities to third-party lessors for an aggregate purchase price of $1.6 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809 million). Under the terms of the 33.67-year leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $152 million in 2006, $152 million in 2007, $152 million in 2008, $151 million in 2009, and $155 million in 2010, and the total remaining minimum lease payments are $2.0 billion. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.

       On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power facilities located in Illinois to third-party lessors for an aggregate purchase price of $1.4 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EME's subsidiary makes semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $185 million each year in 2006 through 2009, and $170 million in 2010, and the total remaining minimum lease payments are $942 million. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases.

Note 18. Related Party Transactions

       Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or Southern California Edison Company employees, are shared among all affiliates of Edison International, and the costs of these corporate support services are allocated to all affiliates, including EME. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). In addition, services of Edison International or Southern California Edison employees are sometimes directly requested by EME and these services are performed for EME's benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. EME believes the allocation methodologies utilized are reasonable. EME

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made reimbursements for the cost of these programs and other services, which amounted to $84 million, $60 million and $63 million in 2005, 2004 and 2003, respectively. At December 31, 2005 and 2004, the amount due to Edison International was $7 million and $26 million, respectively.

       EME participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. EME's insurance premiums are generally based on EME's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International.

       EME records accruals for tax liabilities and/or tax benefits which are settled quarterly according to a series of tax-allocation agreements as described in Note 2. Under these agreements, EME recognized tax liabilities (benefits) applicable to continuing operations of $268 million, $(379) million and $(99) million for 2005, 2004 and 2003, respectively. See Note 13—Income Taxes. Amounts included in Accounts payable—affiliates associated with the tax liabilities totaled $22 million at December 31, 2005. Amounts included in Accounts receivable—affiliates associated with the tax benefits totaled $46 million at December 31, 2004.

       Edison Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities and may also earn an incentive compensation as set forth in the agreements. EME recorded revenues under the operation and maintenance agreements of $24 million for each year in 2005, 2004 and 2003. Accounts receivable—affiliates for Edison Mission Operation & Maintenance totaled $7 million and $6 million at December 31, 2005 and 2004, respectively.

       Specified EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to Southern California Edison Company and others under the terms of long-term power purchase agreements. Sales by these partnerships to Southern California Edison Company under these agreements amounted to $932 million, $824 million and $754 million in 2005, 2004 and 2003, respectively.

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Note 19. Supplemental Statements of Cash Flows Information

		Years Ended December 31,
		2005		2004		2003
		(in millions)
Cash paid
	Interest (net of amount capitalized)	$	307	$	307	$	279
	Income taxes (receipts)		149		6		(102	)
	Cash payments under plant operating leases		293		240		271
Details of assets acquired
	Fair value of assets acquired	$	154	$	—	$	3
	Liabilities assumed		—		—		—
	Net cash paid for acquisitions	$	154	$	—	$	3
Non-cash activities from consolidation of variable interest entity
	Assets	$	37	$	—	$	—
	Liabilities		27		—		—
Non-cash activities from de-consolidation of variable interest entities
	Assets	$	—	$	220	$	—
	Liabilities		—		254		—

       During the year ended December 31, 2005, EME received a capital contribution of $20 million from its parent for investments in an entity which was previously owned by EME's affiliate, Edison Capital. This entity holds interests in various wind projects.

       During the year ended December 31, 2004, EME declared a dividend payable to MEHC totaling $305 million.

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Note 20. Quarterly Financial Data (unaudited)

2005	First		Second		Third(i)			Fourth			Total
	(in millions)
Operating revenues	$	511	$	417	$	677		$	643		$	2,248
Operating income		124		17		278			265			684
Income (loss) from continuing operations		55		17		172	(ii)		160			404
Discontinued operations, net(iii)		7		21		27			(26	)		29
Income (loss) before accounting change		62		38		199			134			433
Net income (loss)		62		38		199			133			432

2004	First			Second			Third(i)			Fourth			Total
Operating revenues	$	389		$	359		$	509		$	382		$	1,639
Operating income (loss)		(16	)		(976	)(iv)		95	(v)		(45	)(vi)		(942	)
Income (loss) from continuing operations		(15	)		(611	)(iv)		87	(v)		(29	)(vi)		(568	)
Discontinued operations, net(iii)		46			26			498	(vii)		120	(vii)		690
Net income (loss)		31			(585	)		585			91			122

(i)

Reflects EME's seasonal pattern, in which the majority of earnings from domestic projects are earned and recorded in the third quarter of each year.



(ii)

Reflects a $55 million pre-tax ($34 million, after tax) impairment loss on equity method investment related to the March Point project.



(iii)

See Note 8. Divestitures—Discontinued Operations for more information.



(iv)

Reflects a $951 million pre-tax ($585 million, after tax) loss on termination of the lease related to the Collins Station and the return of its ownership to EME.



(v)

Reflects asset impairment charge of $29 million pre-tax ($18 million, after tax) related to impairment of six of the eight remaining small peaking units in Illinois.



(vi)

Reflects a $56 million pre-tax ($34 million, after tax) charge related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999.



(vii)

Reflects gain on sale of international projects. See Note 8. Divestitures—Discontinued Operations for further explanation.

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PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

       Information concerning executive officers of Edison Mission Energy is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 is set forth below.

Directors

Name and Age	Director Continuously Since	Term Expires
Theodore F. Craver, Jr., 54	2001	2006
Thomas R. McDaniel, 56	2002	2006
Jacob A. Bouknight, Jr., 61	2005	2006

Business Experience

       Below is a description of the principal business experience during the past five years of each of the directors named above and the name of each public company in which each is a director.

       Refer to "Executive Officers of the Registrant" set forth in Part I for Mr. Craver's business experience.

Mr. McDaniel has been director of Edison Mission Energy since August 2002. Mr. McDaniel has been executive vice president, chief financial officer and treasurer of Edison International since January 2005. Mr. McDaniel has served as director of Edison Capital since September 1987. From August 2002 until January 2005, Mr. McDaniel was president and chief executive officer of Edison Mission Energy, and from January 2003 until January 2005, served as chairman of the board. From September 1987 until January 2005, Mr. McDaniel served as chief executive officer and director of Edison Capital.

Mr. Bouknight has been director of Edison Mission Energy since July 2005. Mr. Bouknight has been executive vice president and general counsel of Edison International since July 2005. Prior to joining Edison International, Mr. Bouknight was a partner at the law firm of Steptoe and Johnson since 1994.

Audit Committee Financial Expert

       The board of directors has determined that Edison Mission Energy has at least one audit committee financial expert (as defined in rules of the Securities and Exchange Commission) serving on its audit committee. The name of the audit committee financial expert is Thomas R. McDaniel, who is not an independent director.

Ethics and Compliance Code for Principal Officers

       Edison Mission Energy has adopted a Ethics and Compliance Code that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, or persons

141

performing similar functions. The Ethics and Compliance Code is posted on the Internet website maintained by Edison Mission Energy's ultimate parent, Edison International, at www.edisonethics.com. Any amendment to or waiver from a provision of the Ethics and Compliance Code that must be disclosed under rules and forms of the Securities and Exchange Commission will be disclosed at the same Internet website address within four business days following the date of the amendment or waiver.

Section 16(a) Beneficial Ownership Reporting Compliance

       Section 16(a) of the Securities Exchange Act of 1934, as amended, requires EME's directors and executive officers and the holders of 10% or more of its common stock to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of EME's equity securities. EME currently has no publicly traded securities. Pursuant to Item 405 of Regulation S-K, EME is required to disclose that each of the following persons had one late Form 3: directors Theodore F. Craver, Jr., Thomas R. McDaniel, and Jacob A. Bouknight, Jr., and executive officers Gerard P. Loughman, W. James Scilacci, Guy F. Gorney, and Paul Jacob. To date, all late Form 3 reports have been filed.

ITEM 11.    EXECUTIVE COMPENSATION

       Information responding to Item 11 will appear in EME's Amendment to Form 10-K for the year ended December 31, 2005 which will be filed with the Securities and Exchange Commission concurrently with Edison International's definitive proxy statement, which will be incorporated herein by reference when filed.

Compensation of Directors

       EME's directors do not receive any compensation for serving on its board of directors or attending meetings.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Certain Beneficial Owners

       Set forth below is certain information regarding each person who is known to EME to be the beneficial owner of more than five percent of EME's common stock.

Title of Class	Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class
Common Stock, no par value	Mission Energy Holding Company 2600 Michelson Drive, Suite 1700 Irvine, California 92612	100 shares held directly and with exclusive voting and investment power	100	%

       For information concerning the number of equity securities of Edison International beneficially owned by all directors and executive officers of EME, individually and as a group, see Item 12 of EME's Amendment to Form 10-K for the year ended December 31, 2005, which will be filed with the Securities and Exchange Commission concurrently with Edison International's filing of its definitive proxy statement, which will be incorporated herein by reference when filed.

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Changes in Control

       On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, MEHC borrowed $385 million under a term loan ($100 million of the term loan was repaid in July 2004 and the remaining $285 million of the term loan was repaid in January 2005). The senior secured notes are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes would result in a change in control of EME.

Equity Compensation Plans

       Item 201(d) of Regulation S-K, "Securities Authorized For Issuance Under Equity Compensation Plans," is not applicable because EME has no compensation plans under which equity securities of EME are authorized for issuance.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

       For information concerning transactions between EME and specified security holders, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement" and paragraphs one and three related to administrative services and tax-allocation agreement, under "Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 18. Related Party Transactions."

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

INDEPENDENT ACCOUNTANT FEES

       The following table sets forth the aggregate fees billed to EME (consolidated total including EME and its subsidiaries), for the fiscal years ended December 31, 2005 and December 31, 2004, by PricewaterhouseCoopers LLP:

	EME and Subsidiaries ($000)
	2005		2004
Audit Fees	$	2,936	$	4,557
Audit Related Fees(1)		44		204
Tax Fees(2)		926		2,123
All Other Fees		—		—
Total	$	3,906	$	6,884

(1)

The nature of the services comprising these fees were assurance and related services related to the performance of the audit or review of the financial statements and not reported under "Audit Fees" above.

(2)

The nature of the services comprising these fees were to support compliance with federal, state and foreign tax reporting and payment requirements, including tax return review and review of tax laws, regulations or cases.

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       The Edison International Audit Committee reviews with management and pre-approves all audit services to be performed by the independent accountants and all non-audit services that are not prohibited and that require pre-approval under the Securities Exchange Act. The Edison International Audit Committee's pre-approval responsibilities may be delegated to one or more Edison International Audit Committee members, provided that such delegate(s) presents any pre-approval decisions to the Edison International Audit Committee at its next meeting. The independent auditors must assure that all audit and non-audit services provided to EME and its subsidiaries have been approved by the Edison International Audit Committee.

       During the fiscal year ended December 31, 2005, all services performed by the independent accountants were pre-approved by the Edison International Audit Committee, regardless of whether the services required pre-approval under the Securities Exchange Act.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	(1)	List of Financial Statements
		See Index to Consolidated Financial Statements at Item 8 of this report.
	(2)	List of Financial Statement Schedules
		The following financial statement schedules are included in this report:

	Page
Schedule I—Condensed Financial Information of Parent	152
Schedule II—Valuation and Qualifying Accounts	155

	All other schedules have been omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
(3)	List of Exhibits

Exhibit No.	Description
2.1	Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.2	Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.3	Purchase and Sale Agreement, dated May 10, 2000, between Edison Mission Energy, P & L Coal Holdings Corporation and Gold Fields Mining Corporation, incorporated by reference to Exhibit 2.9 to Edison Mission Energy's 10-Q for the quarter ended September 30, 2000.
2.4	Stock Purchase Agreement, dated November 17, 2000 between Mission Del Sol, LLC and Texaco Inc., incorporated by reference to Exhibit 2.11 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
2.5	Purchase Agreement, dated July 20, 2004, between Edison Mission Energy and Origin Energy New Zealand Limited, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 8-K dated September 30, 2004.
2.6	Purchase Agreement, dated July 29, 2004, by and among Edison Mission Energy, IPM Eagle LLP, International Power plc, Mitsui & Co., Ltd. and the other sellers on the signature page thereto, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2004.
3.1	Certificate of Incorporation of Edison Mission Energy, dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K dated October 26, 2001.

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3.1.1	Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy dated May 4, 2004, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
3.2.	By-Laws of Edison Mission Energy dated May 4, 2004, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
4.1	Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.1.1	Form of 10% Senior Note due 2008 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).
4.2	Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities (USA) Inc. and Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.3	Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.3.1	Form of 9.875% Senior Note due 2011 (included in Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).
4.4	Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.
4.5	Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5.1	Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.5 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6	Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

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4.6.1	Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.6 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.7	Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.8	Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.12 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.8.1	Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.8 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9	Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9.1	Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.10	Indenture, dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
4.10.1	First Supplemental Indenture, dated as of June 28, 1999, to Indenture dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
4.11	Registration Rights Agreement, dated as of June 23, 1999, between Edison Mission Energy and the Initial Purchasers specified therein, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.

147

4.12	Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.12.1	Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.12 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.13	Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.13.1	Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.13 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.13.2	Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.13 hereto, incorporated by reference to Exhibit 4.4.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2004.
4.14	Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.14.1	Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.14 hereto, incorporated by reference to Exhibit 4.9.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2003.
10.1	Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.2	Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.16.4 to EME Homer City Generation L.P.'s Form 10-K for the year ended December 31, 2001.
10.3	Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.

148

10.4	Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000.
10.5	Exchange and Registration Rights Agreement, dated as of May 27, 1999, by and among the Initial Purchasers named therein, the Guarantors named therein and Edison Mission Holdings Co., incorporated by reference to Exhibit 10.1 to Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999.
10.6	Reimbursement Agreement, dated as of October 26, 2001, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.15 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.7	Credit Agreement, dated as of April 27, 2004, among Edison Mission Energy, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.13 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.7.1	Amendment One to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.7 herein) dated as of April 22, 2005, by and among Edison Mission Energy, the Lenders referred to therein, and Citicorp North America, Inc., as Administrative Agent for the Lenders, incorporated by reference to Exhibit 10.3 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2005.
10.7.2*	Amendment Two to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.7 herein) dated as of December 9, 2005, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent.
10.8	Security Agreement, dated as of April 27, 2004, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.14 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.9	Tax Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.
10.10	Administrative Agreement Re Tax Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.
18.1	Preferability Letter Regarding Change in Accounting Principle for Major Maintenance Costs, incorporated by reference to Exhibit 18.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
21*	List of Subsidiaries of Edison Mission Energy.
31.1*	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

149

31.2*	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
32*	Statement Pursuant to 18 U.S.C. Section 1350.

*

Filed herewith.

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SIGNATURES

       Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EDISON MISSION ENERGY (REGISTRANT)
By:	/s/ W. James Scilacci  W. James Scilacci   Senior Vice President and Chief Financial   Officer
Date:	March 6, 2006

       Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Theodore F. Craver, Jr.
Theodore F. Craver, Jr.	Director, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)	March 6, 2006
/s/ Mark C. Clarke
Mark C. Clarke	Vice President and Controller (Controller or Principal Accounting Officer)	March 6, 2006
/s/ Thomas R. McDaniel
Thomas R. McDaniel	Director	March 6, 2006
/s/ Jacob A. Bouknight, Jr.
Jacob A. Bouknight, Jr.	Director	March 6, 2006

151

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Balance Sheets
(In millions)

	December 31,
	2005		2004
Assets
Cash and cash equivalents	$	800	$	1,976
Short-term investments		183		120
Affiliate receivables		2		48
Assets under energy trading and price risk management		—		—
Other current assets		7		27
Total current assets		992		2,171
Investments in subsidiaries		4,236		5,955
Investment in discontinued operations		—		—
Other long-term assets		89		39
Total Assets	$	5,317	$	8,165
Liabilities and Shareholder's Equity
Accounts payable and accrued liabilities	$	81	$	467
Affiliate payables		287		2,927
Short-term obligations		—		—
Current maturities of long-term debt		—		—
Total current liabilities		368		3,394
Long-term obligations		1,598		1,598
Long-term affiliate debt		1,440		1,442
Deferred taxes and other		67		49
Total Liabilities		3,473		6,483
Common Shareholder's Equity		1,844		1,682
Total Liabilities and Shareholder's Equity	$	5,317	$	8,165

152

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Income
(In millions)

	Years Ended December 31,
	2005			2004			2003
Net gains (losses) from energy trading and price risk management	$	—		$	(26	)	$	—
Operating expenses		(110	)		(138	)		(108	)
Operating loss		(110	)		(164	)		(108	)
Equity in income from continuing operations of subsidiaries		670			—			182
Equity in income (loss) from discontinued operations of subsidiaries		—			352			1
Interest expense and other		(270	)		(389	)		(295	)
Income (loss) before income taxes		290			(201	)		(220	)
Benefit for income taxes		(142	)		(323	)		(240	)
Net income	$	432		$	122		$	20

153

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Cash Flows
(In millions)

	Years Ended December 31,
	2005			2004			2003
Net cash provided by (used in) operating activities	$	(2,594	)	$	1,997		$	998
Net cash provided by (used in) financing activities		(378	)		(52	)		—
Net cash provided by (used in) investing activities		1,796			(85	)		(930	)
Net increase (decrease) in cash and cash equivalents		(1,176	)		1,860			68
Cash and cash equivalents at beginning of period		1,976			116			48
Cash and cash equivalents at end of period	$	800		$	1,976		$	116
Cash dividends received from subsidiaries	$	250		$	529		$	974

154

SCHEDULE II

EDISON MISSION ENERGY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(In millions)

			Additions
Description	Balance at Beginning of Year		Charged to Costs and Expenses		Charged to Other Accounts		Deductions		Balance at End of Year
Year Ended December 31, 2005 Allowance for doubtful accounts	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2004 Allowance for doubtful accounts	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2003 Allowance for doubtful accounts(1)	$	8.9	$	—	$	—	$	8.9	$	—

(1)

Excludes allowance for doubtful accounts of discontinued operations of $6.5 million at December 31, 2003.

155

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PART I

ITEM 1. BUSINESS

ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE REGISTRANT

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
ITEM 6. SELECTED FINANCIAL DATA

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

SIGNATURES

EX-10.7.2

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Exhibit 10.7.2

AMENDMENT TWO

        AMENDMENT TWO dated as of December 9, 2005 between EDISON MISSION ENERGY (the "Borrower") and CITICORP NORTH AMERICA, INC, in its capacity as Administrative Agent (in such capacity, the "Administrative Agent") pursuant to authority granted by the Required Lenders pursuant to Section 10.1 of the Credit Agreement referred to below.

        The Borrower, the lenders party thereto, and the Administrative Agent, are parties to a Credit Agreement dated as of April 27, 2004 (as modified and supplemented and in effect from time to time, the "Credit Agreement"), providing, subject to the terms and conditions thereof, for extensions of credit (by means of loans and letters of credit) to be made by said lenders to the Borrower in an aggregate principal or face amount not exceeding $98,000,000.

        The Borrower and the Administrative Agent, pursuant to authority granted by, and having obtained the consent of Lenders party to the Credit Agreement constituting the Required Lenders wish now to amend the Credit Agreement in certain respects, and accordingly, the parties hereto hereby agree as follows:

        Section 1.    Definitions.    Except as otherwise defined in this Amendment Two, terms defined in the Credit Agreement are used herein (and in the introductions and recitals hereto) as defined therein.

        Section 2.    Amendments.    Subject to the satisfaction of the conditions precedent specified in Section 4 below, but effective as of the date hereof, the Credit Agreement shall be amended as follows:

        2.01.    References Generally.    References in the Credit Agreement (including references to the Credit Agreement as amended hereby) to "this Agreement" (and indirect references such as "hereunder", "hereby", "herein" and "hereof") shall be deemed to be references to the Credit Agreement as amended hereby.

        2.02.    Definitions.    Section 1.1 of the Credit Agreement shall be amended by amending and restating in their entirety the following definitions (to the extent already included in said Section 1.1) and adding the following definitions in the appropriate alphabetical location (to the extent not already included in said Section 1.1):

        ""Development Subsidiary" means any Subsidiary (other than a Collateral Party) of the Borrower created after the date of this Amendment or set forth on Schedule 1.1(d) hereto, in each case that is primarily engaged (directly or through its Subsidiaries) in the power generation, power sales or power transmission business or any Subsidiary of the Borrower holding interests in an Unrestricted Joint Enterprise.

        "Permitted Guarantees" means any of (a) guarantees, whether unsecured or permitted to be secured pursuant to Section 7.2.2(g), by the Borrower in connection with non-speculative Permitted Trading Activities of its Subsidiaries, Joint Enterprises and Unrestricted Joint Enterprises, (b) unsecured guarantees by the Borrower of payment obligations of Development Subsidiaries or Unrestricted Joint Enterprises to suppliers or contractors of such Development Subsidiaries or Unrestricted Joint Enterprises in connection with the development of assets, the supply of equipment and the provision of services, in each case, in connection with its power generation, power sales or power transmission business or (c) unsecured guarantees by the Borrower of Indebtedness permitted pursuant to Section 7.2.1(b)(iv)(B).

        "Permitted Intercompany Indebtedness" means unsecured Indebtedness between the Borrower and its Subsidiaries or between its Subsidiaries for money borrowed which, in the case of Indebtedness of the Borrower, any Collateral Party or any Subsidiary of a Collateral Party, is subordinated in right of payment to the payment in full in cash of all Obligations pursuant to the terms of subordination substantially in the form of Exhibit G hereto. Permitted Intercompany Indebtedness shall exclude, to the extent included, Indebtedness of a Collateral Party to the

Borrower or to any Subsidiary of the Borrower that is not a Collateral Party or a Subsidiary of a Collateral Party, in each case, in excess of $20,000,000 in the aggregate.

        "Permitted Trading Activities" means (a) the daily or forward purchase and/or sale, or other acquisition or disposition, of wholesale or retail electric energy, capacity, ancillary services, transmission rights, emissions allowances, weather derivatives and/or related commodities, in each case, whether physical or financial, (b) the daily or forward purchase and/or sale, or other acquisition or disposition, of fuel, mineral rights and/or related commodities, including swaps, options and swaptions, in each case, whether physical or financial, (c) electric energy-related tolling transactions, as seller of tolling services, (d) price risk management activities or services, (e) other similar electric industry activities or services, or (f) additional services as may be consistent with Prudent Industry Practice from time to time to support the marketing and trading related to the Subsidiaries of the Borrower, Joint Enterprises and Unrestricted Joint Enterprises, in each case, consistent with the energy and fuel risk management policies of such Subsidiary, Joint Enterprise or Unrestricted Joint Enterprise (or, if the relevant Subsidiary, Joint Enterprise or Unrestricted Joint Enterprise does not have any such policies, the energy and fuel risk management policies of the Borrower).

        "Pledged Development Subsidiary" means any Development Subsidiary or, in the case of an Unrestricted Joint Enterprise, a Subsidiary of the Borrower that directly or indirectly holds 100% of the Borrower's interests in such Unrestricted Joint Enterprise, in each case, the Borrower's interest (direct or indirect) in which is required hereunder to be pledged to the Administrative Agent for the benefit of the Lenders.

        "Prudent Industry Practice" means, at a particular time, (a) any of the practices, methods and acts engaged in or approved by a significant portion of the competitive electric generating industry at such time, or (b) with respect to any matter to which clause (a) does not apply, any of the practices, methods and acts which, in the exercise of reasonable judgment at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. "Prudent Industry Practice" is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be a spectrum of possible practices, methods or acts having due regard for, among other things, manufacturers' warranties and the requirements of any Governmental Authority of competent jurisdiction.

        "Unrestricted Joint Enterprise" means a general partnership, limited partnership, joint venture or similar entity that is primarily engaged in the power generation, power sales or power transmission business in which the Borrower or a Subsidiary of the Borrower (other than a Collateral Party or a Subsidiary of a Collateral Party) is a partner, joint venturer or equity participant. The term "Unrestricted Joint Enterprise" shall exclude, to the extent included, partnerships or other business entities included in the definition of "Subsidiary".".

        2.03.    Indebtedness.    Section 7.2.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

        "Section 7.2.1    Restrictions on Indebtedness.

        (a)   The Borrower will not create, incur, assume or suffer to exist any secured Indebtedness other than (i) Capitalized Lease Liabilities, (ii) other secured Indebtedness of any kind whatsoever existing on the Effective Date, (iii) Non-Recourse Debt with respect to which the Borrower has pledged the stock of a Subsidiary in order to secure initial project financing (or a refinancing of such initial project financing) obtained or being obtained after the Effective Date hereof by such Subsidiary (or the Partnership in which such Subsidiary is a partner) or (iv) Permitted Guarantees.

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        (b)   Except as permitted by clause (a) of this Section 7.2.1, the Borrower will not, will not permit the Collateral Parties (and each Subsidiary of a Collateral Party) and will use reasonable efforts to not permit Joint Enterprises (to the extent consistent with such Collateral Party's or such Subsidiary of a Collateral Party's obligations to other members of such Joint Enterprise) to, create, incur, assume or suffer to exist any Indebtedness other than:

        (i)    Indebtedness of the Borrower, Collateral Parties, each Subsidiary of a Collateral Party or Joint Enterprises of any kind whatsoever existing on the Effective Date;

        (ii)   Permitted Refinancing Indebtedness;

        (iii)  Permitted Intercompany Indebtedness;

        (iv)  interest rate hedging obligations of the Borrower (A) with respect to Indebtedness of the Borrower or (B) with respect to Financings reasonably anticipated to be necessary for Development Subsidiaries or Unrestricted Joint Enterprises of the Borrower or its Subsidiaries provided that, in the case of clause (B) above, such interest rate hedging obligations are terminated (or assigned by the Borrower to such Development Subsidiary or Unrestricted Joint Enterprise) on the date such Financing is incurred;

        (v)   Indebtedness secured by Liens set forth on Schedule 7.2.1; and

        (vi)  Permitted Guarantees;

provided that, in the case of each Financed Enterprise, compliance with the Correlative Financing Provisions shall be deemed to be compliance by such Financed Enterprise with this Section 7.2.1 (provided that, in the event that the Financed Enterprise shall not be in compliance with the Correlative Financing Provisions, this Section 7.2.1 will apply to such Financed Enterprise without giving effect to the Correlative Financing Provision).".

        2.04.    Liens.    Section 7.2.2 of the Credit Agreement is hereby amended by adding the following clauses (f) and (g) after clause (e) of such Section:

        "(f)  Liens to secure Indebtedness permitted by clause (a)(iii) of Section 7.2.1; and

        (g)   Liens on cash and short-term investments (i) deposited by the Borrower in margin accounts with or on behalf of futures contract brokers or paid over to other counterparties or (ii) pledged or deposited as collateral to a contract counterparty or issuer of surety bonds by the Borrower, in the case of clause (i) or (ii), to secure obligations with respect to Permitted Trading Activities of the Borrower, its Subsidiaries, Joint Enterprises or Unrestricted Joint Enterprises;".

        2.05.    Investments.    Section 7.2.3 of the Credit Agreement is hereby amended in its entirety to read as follows:

        "Section 7.2.3    Investments.    The Borrower will not, and will not permit any of its Subsidiaries to, make, incur, assume or suffer to exist any Investment in any other Person, except:

        (a)   Investments existing on the Effective Date;

        (b)   Cash Equivalent Investments;

        (c)   without duplication, Investments permitted as Indebtedness pursuant to Section 7.2.1;

        (d)   Investments in the Collateral Parties, Subsidiaries of a Collateral Party or Joint Enterprises in the ordinary course of business;

        (e)   Investments permitted pursuant to Section 7.2.4(b);

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        (f)    Investments in the Collateral Parties, Subsidiaries of a Collateral Party or Joint Enterprises that are primarily engaged in the power generation, power sales or power transmission business;

        (g)   Investments in any Subsidiary of the Borrower existing on the Effective Date and any other Person if as a result of such Investment such Person becomes a Collateral Party or a Subsidiary of a Collateral Party;

        (h)   Investments by the Borrower or Subsidiaries of the Borrower (other than Collateral Parties, Subsidiaries of Collateral Parties or Joint Enterprises) consisting of loans to Persons (other than the Borrower, its Subsidiaries, Joint Enterprises or Unrestricted Joint Enterprises) that are primarily engaged in the power generation, power sales or power transmission business in connection with the development of, or acquisition of, assets in such business in an amount for all such Investments not in excess of $100,000,000 at any time outstanding in the aggregate; provided that the Borrower or its Subsidiaries shall have the right to acquire an equity interest in such Person or an enterprise to be organized by such Person for the purpose of owning such power generation, power sales or power transmission assets and such Person (directly or indirectly) holds such assets;

        (i)    Investments by the Borrower or Subsidiaries of the Borrower (other than Collateral Parties, Subsidiaries of Collateral Parties or Joint Enterprises) in any Development Subsidiaries or Unrestricted Joint Enterprises; provided that such Person or, in the case of an Unrestricted Joint Enterprise, a Subsidiary of the Borrower that directly or indirectly holds 100% of the Borrower's interests in such Unrestricted Joint Enterprise shall become a Pledged Development Subsidiary (and the Borrower shall promptly deliver notice and other documentation reasonably requested by the Administrative Agent to pledge the interests in such Pledged Development Subsidiary as Collateral under the Borrower Security Agreement); and

        (j)    Permitted Guarantees;

provided that, in the case of each Financed Enterprise, compliance with the Correlative Financing Provisions shall be deemed to be compliance by such Financed Enterprise with this Section 7.2.3 (provided that, in the event that the Financed Enterprise shall not be in compliance with the Correlative Financing Provisions, this Section 7.2.3 will apply to such Financed Enterprise without giving effect to the Correlative Financing Provision).".

        2.06.    Asset Dispositions.    Section 7.2.5 of the Credit Agreement is hereby amended by amending and restating the first paragraph thereof in its entirety to read as follows:

        "Section 7.2.5    Asset Dispositions.    The Borrower will not, will not permit the Collateral Parties (and each Subsidiary of a Collateral Party) to and will use reasonable efforts to not permit Joint Enterprises (to the extent consistent with its obligations to other members of such Joint Enterprise) to, Dispose of, lease, contribute or otherwise convey, or grant options, warrants or other rights with respect to, all or any substantial part of its assets (including accounts receivable and capital stock of Subsidiaries) to any Person (other than Investments in Persons consisting of a sale, assignment, transfer or other disposition or a lease, contribution, conveyance or grant of equipment of the Borrower or any of its Subsidiaries to any Development Subsidiary or Unrestricted Joint Enterprise permitted pursuant to Section 7.2.3(i)), unless:".

        2.07.    Restrictive Agreements.    Section 7.2.8 of the Credit Agreement is hereby amended by amending and restating the last paragraph thereof in its entirety to read as follows:

"The restriction set forth in clause (b) above shall not apply to prohibitions or restrictions on Subsidiary Payments directly or indirectly to the Borrower set forth in any agreement entered into in connection with (i) a refinancing of any Indebtedness of the Borrower or any of its Subsidiaries (each

4

such agreement entered into after the Effective Date, a "Restrictive Financing Document") if, prior to entering into such Restrictive Financing Document, the Borrower shall have delivered to the Administrative Agent: (A) a certificate of an Authorized Representative stating that the projected financial or coverage ratios of the affected Subsidiary as calculated on the basis of the pro forma financials prepared in good faith on the basis of reasonable assumptions in connection with, and after giving effect to, the transactions contemplated by such Restrictive Financing Document will, during the remaining life to maturity of the Obligations, equal or exceed the financial or coverage ratios, if any, required for the affected Subsidiary to make any Subsidiary Payments directly or indirectly to the Borrower in accordance with such Restrictive Financing Document; and (B) letters from Moody's and S&P confirming the then current Debt Rating or (ii) the incurrence of Non-Recourse Debt after the effective date of this Amendment by Development Subsidiaries or Unrestricted Joint Enterprises.".

        2.08.    Development Subsidiaries.    A new Schedule 1.1.(d) shall be added to the Credit Agreement substantially in the form of Annex 1 hereto.

        2.09.    Terms of Subordination.    A new Exhibit G shall be added to the Credit Agreement substantially in the form of Annex 2 hereto.

        Section 3.    Representations and Warranties.    The Borrower represents and warrants to the Lenders and the Administrative Agent, as to itself and each of the Collateral Parties, that (a) the representations and warranties set forth in Article VI (as hereby amended) of the Credit Agreement, and in each of the other Loan Documents, are true and complete on the date hereof as if made on and as of the date hereof (or, if any such representation or warranty is expressly stated to have been made as of a specific date, such representation or warranty shall be true and correct as of such specific date), and as if each reference in said Article VI to "this Agreement" included reference to this Amendment Two and (b) no Default or Event of Default has occurred and is continuing.

        Section 4.    Conditions Precedent.    The amendments set forth in Section 2 hereof shall become effective, as of the date hereof, upon the receipt by the Administrative Agent of counterparts of this Amendment Two executed by the Borrower and the Administrative Agent.

        Section 5.    Miscellaneous.    Except as herein provided, the Credit Agreement shall remain unchanged and in full force and effect. This Amendment Two may be executed in any number of counterparts, all of which taken together shall constitute one and the same amendatory instrument and any of the parties hereto may execute this Amendment Two by signing any such counterpart. Delivery of an executed counterpart of a signature page of this Amendment by facsimile (or other electronic transmission) shall be effective as delivery of a manually executed counterparty hereof. This Amendment Two shall be governed by, and construed in accordance with, the law of the State of New York.

        IN WITNESS WHEREOF, the parties hereto have caused this Amendment Two to Credit Agreement to be duly executed and delivered as of the day and year first above written.

EDISON MISSION ENERGY
By:	/s/  W. JAMES SCILACCI Name: W. James Scilacci Title: Senior Vice President & CFO

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ADMINISTRATIVE AGENT

CITICORP NORTH AMERICA, INC.,     as Administrative Agent
By:	/s/  ROBERT J. HARRITY, JR. Name: Robert J. Harrity, Jr. Title: Managing Director

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ANNEX 1

SCHEDULE 1.1(d)
to Credit Agreement

DEVELOPMENT SUBSIDIARIES
Valle del Sol Energy, LLC
Walnut Creek Energy, LLC

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ANNEX 2

EXHIBIT G
to Credit Agreement

[FORM OF]
TERMS OF SUBORDINATION

        SECTION 1.    Definitions.    Terms defined in the Credit Agreement are used herein as defined therein. In addition, as used herein:

        "Permitted Refinancing" means any extension, renewal, refunding or refinancing, or any restructuring, or any other modification (collectively, a "Refinancing"), of any Senior Debt at any time outstanding under the Credit Agreement or any document or instrument evidencing a Permitted Refinancing thereof.

        "Proceeding" means any: (a) insolvency, bankruptcy, receivership, liquidation, reorganization, readjustment, composition or other similar proceeding, whether voluntary or involuntary, of or against the Subordinated Borrower, its property or its creditors as such; (b) proceeding for any liquidation, dissolution or other winding-up of the Subordinated Borrower, whether voluntary or involuntary, and whether or not involving insolvency, receivership or bankruptcy proceedings; (c) general assignment for the benefit of creditors of the Subordinated Borrower; or (d) other marshalling of the assets of the Subordinated Borrower.

        "Reorganization Debt Securities" means, with respect to each Subordinated Borrower, debt or equity securities of such Subordinated Borrower as reorganized or readjusted, or debt or equity securities of such Subordinated Borrower (or any other company, trust or organization provided for by a plan of reorganization or readjustment succeeding to the assets and liabilities of such Subordinated Borrower), that are subordinated, to at least the same extent as the Subordinated Debt, to the payment of all Senior Debt that will be outstanding after giving effect to such plan of reorganization or readjustment, so long as (a) the rate of interest on such debt securities shall not exceed the effective rate of interest on the Subordinated Debt on the date hereof, (b) such debt securities shall not be entitled to the benefits of covenants or defaults materially more beneficial to the holders of such debt securities than those in effect with respect to the Subordinated Debt on the date hereof (or the Senior Debt, after giving effect to such plan of reorganization or readjustment) and (c) such debt securities shall not provide for amortization (including sinking fund and mandatory prepayment provisions) commencing prior to the date six months following the final scheduled maturity date of the Senior Debt (as modified by such plan of reorganization or readjustment).

        "Senior Debt" means, collectively, the following indebtedness and obligations of the Borrower:

        (a)   all indebtedness and other obligations of the Borrower under the Credit Agreement and the other Loan Documents, including all interest, expenses, indemnities and penalties and all commitment and agency fees payable from time to time under such documents; and

        (b)   any Permitted Refinancing.

The term "Senior Debt" shall include any interest accruing after the date of any filing by the Borrower of any petition in bankruptcy or the commencing of any bankruptcy, insolvency or similar proceedings with respect to the Borrower, whether or not such interest is allowable as a claim in any such proceeding. Notwithstanding the foregoing, "Senior Debt" shall not include any obligations or other indebtedness of the Borrower that by its terms is expressly stated not to be superior in right of payment to the Subordinated Debt.

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        "Senior Parties" means the holders from time to time of the Senior Debt, including any transferee or assignee of any such holder.

        "Subordinated Borrower" means any of the Borrower or any Collateral Party or Subsidiary of a Collateral Party, in each case, that is directly and primarily liable in respect of Permitted Intercompany Indebtedness that is subject to these Terms of Subordination.

        "Subordinated Creditors" means the holders from time to time of the Subordinated Debt, including any transferee or assignee of any such holder, which shall, for the avoidance of doubt, exclude the Borrower, the Collateral Parties and Subsidiaries of Collateral Parties.

        "Subordinated Debt" means any and all Indebtedness, liabilities and other obligations, whether for principal, interest, premium, fees, costs, expenses, reimbursements, indemnities or other amounts (including any amounts owing in respect of a breach of the representations, warranties or covenants thereunder) in respect of Permitted Intercompany Indebtedness and rights of subrogation against the Subordinated Borrower obtained under any Loan Document, now or hereafter owing by the Subordinated Borrower to any of its Affiliates that is a Subsidiary of the Borrower and not a Collateral Party or a Subsidiary of a Collateral Party, including interest on any thereof accruing after the date of any filing by the Subordinated Borrower of any petition in bankruptcy or the commencement of any bankruptcy, reorganization, insolvency or similar proceedings with respect to the Subordinated Borrower.

        "Termination Date" means the date upon which all of the Senior Debt shall have been indefeasibly paid in cash.

        "Terms of Subordination" means the terms of subordination set out in this Exhibit G.

        SECTION 2.    Subordination.

        SECTION 2.01    Subordination of Subordinated Debt.    Each Subordinated Borrower, for itself and its successors and assigns, covenants and agrees, and the Subordinated Creditors, on each of their own behalf and on behalf of each subsequent holder of Subordinated Debt, likewise covenant and agree, that, to the extent and in the manner set forth in these Terms of Subordination, the Subordinated Debt, and the payment from whatever source of the principal of, and interest and premium (if any) on, the Subordinated Debt, are hereby expressly made subordinate and subject in right of payment to the prior payment in full in cash of all Senior Debt.

        SECTION 2.02    Payment of Proceeds Upon Dissolution.    In the event of (a) any insolvency or bankruptcy case or proceeding, or any receivership, liquidation, reorganization or other similar case or proceeding in connection therewith, relative to any Subordinated Borrower or to its creditors, as such, or to its assets, or (b) any liquidation, dissolution or other winding up of any Subordinated Borrower, whether voluntary or involuntary and whether or not involving insolvency or bankruptcy, or (c) any assignment for the benefit of creditors or any other marshalling of assets and liabilities of any Subordinated Borrower, then and in any such event:

        (1)   the Senior Parties shall be entitled to receive payment in full in cash of all amounts due or to become due on or in respect of all Senior Debt, or provision shall be made for such payment, before the Subordinated Creditors shall be entitled to receive any payment on account of principal of, or interest or premium (if any) on, the Subordinated Debt;

        (2)   any payment or distribution of assets of such Subordinated Borrower of any kind or character, whether in cash, property or securities, by set-off or otherwise, to which the Subordinated Creditors would be entitled but for the provisions of these Terms of Subordination, including any such payment or distribution that may be payable or deliverable by reason of the payment of any other indebtedness of such Subordinated Borrower being subordinated to the payment of the Subordinated Debt (other than Reorganization Debt Securities), shall be paid by

9

the liquidating trustee or agent or other Person making such payment or distribution, whether a trustee in bankruptcy, a receiver or liquidating trustee or otherwise, directly to the Administrative Agent, to be paid to the Senior Parties, ratably according to the aggregate amounts remaining unpaid on account of the principal of, and interest and premium (if any) on, the Senior Debt held or represented by any Senior Party, to the extent necessary to make payment in full in cash of all Senior Debt remaining unpaid, after giving effect to any concurrent payment or distribution to the Senior Parties;

        (3)   in the event that, notwithstanding the foregoing provisions of this Section 2.02, any of the Subordinated Creditors shall have received, before all Senior Debt is paid in full in cash or payment thereof provided for, any such payment or distribution of assets of such Subordinated Borrower of any kind or character, whether in cash, property or securities (other than Reorganization Debt Securities), including any such payment or distribution arising out of the exercise by the Subordinated Creditors of a right of set-off or counterclaim and any such payment or distribution received by reason of any other indebtedness of such Subordinated Borrower being subordinated to the Subordinated Debt, then, and in such event, such payment or distribution shall be held in trust for the benefit of, and shall be immediately paid over or delivered to, the Administrative Agent, to be paid to the Senior Parties, ratably according to the aggregate amounts remaining unpaid on account of the principal of, and interest and premium (if any) on, the Senior Debt held or represented by each Senior Party, to the extent necessary to make payment in full in cash of all Senior Debt remaining unpaid, after giving effect to any concurrent payment or distribution to the Senior Parties; and

        (4)   if any of the Subordinated Creditors shall have failed to file claims or proofs of claim with respect to the Subordinated Debt earlier than 30 days prior to the deadline for any such filing, each such Subordinated Creditor shall execute and deliver to the Administrative Agent such powers of attorney, assignments or other instruments as the Administrative Agent may reasonably request to file such claims or proofs of claim.

        SECTION 2.03    No Payment of Subordinated Debt.    In the event that any default with respect to any Senior Debt shall have occurred and be continuing permitting the Senior Parties to declare such Senior Debt due and payable prior to the date on which it would otherwise have become due and payable, then no payment on account of the principal of, or interest or premium (if any) on, the Subordinated Debt or any judgment with respect thereto (and no payment on account of the purchase or redemption or other acquisition of the Subordinated Debt) shall be made by or on behalf of any Subordinated Borrower unless and until such payment shall have been made or the Senior Parties have waived the benefits of this Section 2.03 in respect of such default.

        Immediately upon the expiration of any period under this Section 2.03 during which no payment may be made on account of the Subordinated Debt, the Subordinated Borrowers may resume making any and all payments of principal of, and interest and premium (if any) on, the Subordinated Debt (including any payment of principal, interest or premium missed during such period).

        If (a) any Senior Debt shall have been accelerated, (b) the maturity of the Subordinated Debt shall have been accelerated pursuant to any document or instrument relating thereto, (c) no default shall have occurred and be continuing on the date of such acceleration other than by reason of a default based upon the acceleration of the maturity of such Senior Debt, (d) after the date of such acceleration the holders of such Senior Debt shall duly rescind and annul an acceleration of the maturity of such Senior Debt previously effected by them in accordance with the terms of the Credit Agreement (or the comparable provisions of any instrument evidencing or relating to any other Senior Debt), and (e) on the date of such rescission and annulment, no default shall have occurred and be continuing in respect of the Subordinated Debt other than by reason of a default based upon the acceleration of the maturity of such Senior Debt, then such acceleration of the maturity of the Subordinated Debt shall

10

thereupon be deemed rescinded and annulled without action on the part of the Subordinated Creditors, but such rescission and annulment shall not affect the rights of the Subordinated Creditors with respect to any subsequent or other default that may occur.

        In the event that, notwithstanding the foregoing provisions of this Section 2.03, the Subordinated Creditors shall have received any payment prohibited by the foregoing provisions of this Section 2.03, including, without limitation, any such payment arising out of the exercise by the Subordinated Creditors of a right of set-off or counterclaim and any such payment received by reason of other indebtedness of such Subordinated Borrower being subordinated to the Subordinated Debt, then, and in any such event, such payment shall be held in trust for the benefit of, and shall be immediately paid over or delivered to, the Administrative Agent, to be paid (x) to the Senior Parties any amounts due and payable on, or in respect of, the Senior Debt (y) prior to acceleration of the Senior Debt, to the Subordinated Borrower and (z) upon acceleration of the Senior Debt, to the Senior Parties, ratably according to the aggregate amounts remaining unpaid on account of the principal of, and interest and premium (if any) on, the Senior Debt held or represented by each Senior Party, for application to such Senior Debt remaining unpaid, whether or not then due and payable.

        The provisions of this Section 2.03 shall not alter the rights of the holders of Senior Debt under the provisions of Section 2.02.

        SECTION 2.04    Payment Permitted if No Default.    Nothing contained in these Terms of Subordination or in any of the documents or instruments relating to the Subordinate Debt shall affect the obligation of any Subordinated Borrower to make (or prevent any Subordinated Borrower from making) regularly scheduled payments of principal of, or interest and premium (if any) on, the Subordinated Debt or any other amount payable by such Subordinated Borrower under any of the documents or instruments relating to the Subordinate Debt except during the pendency of any case, proceeding, dissolution, liquidation or other winding up, assignment for the benefit of creditors or other marshalling of assets and liabilities of such Subordinated Borrower referred to in Section 2.02, or under the conditions described in Section 2.03.

        SECTION 2.05    Provisions Solely to Define Relative Rights.    The provisions of this Section 2 are and are intended solely for the purpose of defining the relative rights of the Subordinated Creditors on the one hand and the Senior Parties on the other hand. Nothing contained in this Section 2 or elsewhere in these Terms of Subordination or in any of the documents or instruments relating to the Subordinate Debt is intended to or shall:

        (a)   impair, as among any Subordinated Borrower, its creditors other than the Senior Parties and the Subordinated Creditors, the obligation of such Subordinated Borrower, which is absolute and unconditional, to pay to the Subordinated Creditors the principal of and interest on the Subordinated Debt as and when the same shall become due and payable in accordance with its terms;

        (b)   affect the relative rights against such Subordinated Borrower of the Subordinated Creditors and creditors of such Subordinated Borrower other than the Senior Parties;

        (c)   vitiate the occurrence of a default under any of the documents or instruments relating to the Subordinated Debt to the extent that any failure to make a payment of principal of, or interest or premium (if any) on, any Subordinated Debt by reason of the conditions specified in Section 2.02 or 2.03 would otherwise constitute such a default; or

        (d)   prevent the Subordinated Creditors from exercising all remedies otherwise permitted by applicable law upon default under these Terms of Subordination or any of the documents or instruments relating to the Subordinate Debt, subject to the rights, if any, under this Section 2 of the Senior Parties (i) in any case, proceeding, dissolution, liquidation or other winding up, assignment for the benefit of creditors or other marshalling of assets and liabilities of such

11

Subordinated Borrower referred to in Section 2.02, to receive, pursuant to and in accordance with Section 2.02, cash, property and securities otherwise payable or deliverable to the Subordinated Creditors, or (ii) under the conditions specified in Section 2.03, to prevent any payment prohibited by Section 2.03.

        SECTION 2.06    No Waiver of Subordination Provisions.    (a) No right of the Administrative Agent or any Senior Party to enforce subordination as herein provided shall at any time in any way be prejudiced or impaired by any act or failure to act on the part of any Subordinated Borrower or by any act or failure to act, in good faith, by the Administrative Agent or any Senior Party, or by any non-compliance by any Subordinated Borrower with the terms, provisions and covenants of these Terms of Subordination, regardless of any knowledge thereof the Administrative Agent or any Senior Party may have or be otherwise charged with.

        (b)   Without in any way limiting the generality of the foregoing paragraph, the occurrence of any one or more of the following (with or without the consent of or notice to any Subordinated Creditor), shall not cause any Senior Party to incur any obligation to any Subordinated Creditor and shall not impair or release the subordination provided in these Terms of Subordination or the obligations hereunder of any Subordinated Creditor to the Senior Parties, even if any right of reimbursement or subrogation or other right or remedy of the Subordinated Creditors is extinguished, affected or impaired thereby:

(i)

at any time or from time to time, the time for any performance of or compliance with any Subordinated Debt or any Senior Debt shall be extended, or such performance or compliance shall be waived;



(ii)

the terms, covenants or obligations relating to any Senior Debt are in any way amended, modified or supplemented (including pursuant to any amendment, modification or supplement to any Financing Document or any document or instrument relating to any of the foregoing);



(iii)

the maturity of any Subordinated Debt or any Senior Debt shall be accelerated, or any Subordinated Debt shall be modified, supplemented or amended in any respect (regardless of whether the consent of the Senior Parties shall be given pursuant to Section 9 below);



(iv)

any Lien or Guarantee shall be granted to, or in favor of, any Senior Party as security for any Senior Debt (regardless of whether any such Lien shall be perfected or whether any such Guarantee shall be valid or shall at any time be released);



(v)

any Lien shall be granted to, or in favor of, any Subordinated Creditor as security for any Subordinated Debt (regardless of whether any such Lien shall be perfected);



(vi)

the assignment or transfer of any Senior Party's rights under or interest in any Senior Debt; or



(vii)

any other circumstance which might otherwise constitute a defense available to, or a discharge of, the Subordinated Borrower or any Subordinated Creditor.

        (c)   Without in any way limiting the generality of the foregoing paragraph (b), any Senior Party may, at any time and from time to time, without the consent of or notice to the Subordinated Creditors, without incurring any obligation to the Subordinated Creditors, and without impairing or releasing the subordination provided herein or the obligations hereunder of the Subordinated Creditors, do any one or more of the following, even if any right of

12

reimbursement or subrogation or other right or remedy of the Subordinated Creditors is extinguished, affected or impaired thereby:

(i)

change the manner, place or terms of payment of or extend the time of payment of, or renew or alter, Senior Debt owed to it or any collateral security or guarantee therefor, or otherwise amend or supplement in any manner, or enter into any compromise or settlement in respect of, the Senior Debt owed to it or any instrument evidencing the same or any agreement under which any Senior Debt owed to them are outstanding;



(ii)

sell, exchange, release, enforce, delay in enforcing, or otherwise deal with any property pledged, mortgaged or otherwise securing any Senior Debt owed to it;



(iii)

release any Person liable in any manner for any Senior Debt owed to it (including any guarantor thereof); and



(iv)

exercise or refrain from exercising any rights against the Subordinated Borrower and any other Person.

        (d)    Waiver of Notice.    Each Subordinated Creditor unconditionally waives notice of the incurring of any Senior Debt or any part thereof.

        SECTION 2.07    Notice to Subordinated Creditors.    The Subordinated Creditors shall be entitled to rely on the delivery to each of a written notice by a Person representing itself to be a Senior Party (or a trustee, fiduciary or agent therefor) to establish that such notice has been given by a Senior Party (or a trustee, fiduciary or agent therefor). In the event that any Subordinated Creditor determines in good faith that further evidence is required with respect to the right of any Person as a Senior Party to participate in any payment or distribution pursuant to this Section 2, such Subordinated Creditor may request such Person to furnish evidence to the reasonable satisfaction of such Subordinated Creditors as to the amount of Senior Debt held by such Person, the extent to which such Person is entitled to participate in such payment or distribution and any other facts pertinent to the rights of such Person under this Section 2 and if such evidence is not furnished, such Subordinated Creditor may defer any payment to such Person pending judicial determination as to the right of such Person to receive such payment.

        SECTION 2.08    Reliance on Judicial Order or Certificate of Liquidation Agent.    Upon any payment or distribution of assets of any Subordinated Borrower referred to in this Section 2, the Subordinated Creditors shall be entitled to rely upon any order or decree entered by any court of competent jurisdiction in which such insolvency, bankruptcy, receivership, liquidation, reorganization, dissolution, winding up or similar case or proceeding is pending, or a certificate of the trustee in bankruptcy, receiver, liquidating trustee, custodian, assignee for the benefit of creditors, agent or other Person making such payment or distribution, delivered to the Subordinated Creditors, for the purpose of ascertaining the Persons entitled to participate in such payment or distribution, the holders of Senior Debt and other indebtedness of such Subordinated Borrower, the amount thereof or payable thereon, the amount or amounts paid or distributed thereon and all other facts pertinent thereto or to this Section 2.

        SECTION 3.    Certain Agreements Relating to Subordinated Debt.    Each Subordinated Creditor hereby agrees that it will not, without the prior written consent of the Senior Parties, amend, modify, supplement or otherwise alter any Subordinated Debt or any document or instrument relating thereto.

        SECTION 4.    Reinstatement.    The obligations of the Subordinated Creditors under these Terms of Subordination shall continue to be effective, or be reinstated, as the case may be, if at any time any payment in respect of any Senior Debt, or any other payment to any Senior Party in its capacity as such, is rescinded or must otherwise be restored or returned by the holder of such Senior Debt upon the occurrence of any Proceeding, or upon or as a result of the appointment of a receiver, intervenor

13

or conservator of, or trustee or similar officer for, the Subordinated Borrower or any substantial part of its property, or otherwise, all as though such payment had not been made.

        SECTION 5.    Bankruptcy.    These Terms of Subordination shall remain in full force and effect as between the Subordinated Creditors and Senior Parties notwithstanding the occurrence of any Proceeding affecting the Subordinated Borrower.

        SECTION 6.    Rights Acquired by Virtue of Subrogation.    Subject to (a) (and only after) the occurrence of the Termination Date, (b) the final sentence of this paragraph and (c) any similar rights held by any guarantor of the Senior Debt, the Subordinated Creditors shall be subrogated (equally and ratably with the holders of all indebtedness of the Subordinated Borrower that by its express terms is subordinated to the Senior Debt to the same extent as the Subordinated Debt are subordinated thereto and that is entitled to like rights of subrogation) to the rights of the Senior Parties to receive payments and distributions of cash, property and securities applicable to the Senior Debt until the principal of, and interest and premium (if any) on, the Subordinated Debt shall be paid in full in cash. For purposes of such subrogation, no payments or distributions to the Senior Parties of any cash, property or securities to which the Subordinated Creditors would be entitled except for the provisions of these Terms of Subordination, and no payments pursuant to the provisions of these Terms of Subordination to the Senior Parties by the Subordinated Creditors, shall, as among the Subordinated Borrower, its creditors other than the Senior Parties, and the Subordinated Creditors, be deemed to be a payment or distribution by the Subordinated Borrower to or on account of the Senior Debt. No payment or distribution to the Senior Parties pursuant to these Terms of Subordination shall entitle the Subordinated Creditors to exercise any rights acquired directly or indirectly by virtue of assignment, subrogation or otherwise in respect of the Subordinated Debt until the termination of the Credit Agreement.

        SECTION 7.    Amendments.    Notwithstanding anything to the contrary in these Terms of Subordination or any agreement into which they are incorporated, these Terms of Subordination may be waived, modified, amended or otherwise changed only by a written agreement signed by the parties hereto and Senior Parties holding at least 50.01% of the Senior Debt (calculated as if such Senior Debt facility were fully drawn) at the time of such modification, amendment or other change.

        SECTION 8.    Submission to Jurisdiction; Waivers.    Each Subordinated Creditor and each Senior Party hereby irrevocably and unconditionally:

        (a)   submits for itself and its property in any legal action or proceeding relating to the Financing Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non-exclusive general jurisdiction of the courts of the State of New York, the courts of the United States for the Southern District of New York, and appellate courts from any thereof; and

        (b)   consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same.

        SECTION 9.    WAIVERS OF JURY TRIAL.    EACH SUBORDINATED CREDITOR, EACH SUBORDINATED BORROWER AND EACH SENIOR PARTY HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THESE TERMS OF SUBORDINATION OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH SUBORDINATED CREDITOR, EACH SUBORDINATED BORROWER AND EACH SENIOR PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR

14

ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THESE TERMS OF SUBORDINATION BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

        SECTION 10.    Notices.    All notices, requests, consents and demands hereunder shall be in writing and telecopied or delivered to the intended recipient as specified in Section 10.2 of the Credit Agreement or, if such recipient is not party to the Credit Agreement, at the "Address for Notices" specified beneath its name on the signature pages to the agreement containing these Terms of Subordination or, as to any party, at such other address as shall be designated by such party in a notice to each other party. Except as otherwise provided in these Terms of Subordination, all such communications shall be deemed to have been duly given when transmitted by telecopier or personally delivered or, in the case of a mailed notice, upon receipt, in each case given or addressed as aforesaid.

        SECTION 11.    Service of Process.    Each Subordinated Creditor irrevocably consents to service of process in the manner provided for notices in Section 17. Each Subordinated Creditor not organized in the United States of America or a State thereof (each such Subordinated Creditor, a "Foreign Party") hereby irrevocably appoints [CT Corporation System (the "Process Agent") with an office on the date hereof at 111 Eighth Street, 13th Floor, New York, New York 10011, United States], as its agent to receive on behalf of such Foreign Party and its property service of copies of the summons and complaint and any other process which may be served in any such action or proceeding. Such service may be made by mailing or delivering a copy of such process to such Foreign Party in care of the Process Agent at the Process Agent's above address, and such Foreign Party hereby irrevocably authorizes and directs the Process Agent to accept such service on its behalf. As an alternative method of service, each Foreign Party also irrevocably consents to the service of any and all process in any such action or proceeding by the mailing of copies of such process to such Foreign Party at its address specified pursuant to Section 10 (such service to be effective seven days after mailing thereof). Each Foreign Party covenants and agrees that it shall take any and all reasonable action, including the execution and filing of any and all documents, that may be necessary to continue the designation of the Process Agent above in full force and effect, and to cause the Process Agent to continue to act as such. Nothing in these Terms of Subordination will affect the right of any party under these Terms of Subordination to serve process in any other manner permitted by law.

        SECTION 12.    Governing Law.    These Terms of Subordination, and the rights and obligations of the parties under these Terms of Subordination, shall be governed by, and construed and interpreted in accordance with, the law of the State of New York without regard to the conflicts of law rules thereof that would require the application of the law of another jurisdiction.

        SECTION 13.    No Responsibility.    The Senior Parties shall not incur any responsibility or liability to the Subordinated Creditors or the Subordinated Borrower for any loss whatsoever which either such party may suffer arising out of or in any way in connection with the Subordinated Debt or these Terms of Subordination.

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AMENDMENT TWO
[FORM OF] TERMS OF SUBORDINATION

EX-21

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Exhibit 21

EDISON MISSION ENERGY
LIST OF SUBSIDIARIES
As of December 31, 2005

Entity	Jurisdiction Of Organization
Aguila Energy Company	California
Anacapa Energy Company	California
Arrowhead Energy Company	California
Athens Funding, L.L.C.	Delaware
Beheer-en Beleggingsmaatschappij Plogema B.V.	The Netherlands
Brookhaven Cogeneration, L.P.	Delaware
Camino Energy Company	California
Caresale Services Limited	United Kingdom
Chester Energy Company	California
Chestnut Ridge Energy Company	California
Citizens Power Holdings One, LLC	Delaware
CL Power Sales One, L.L.C.	Delaware
CL Power Sales Two, L.L.C.	Delaware
CL Power Sales Seven, L.L.C.	Delaware
CL Power Sales Eight, L.L.C.	Delaware
CL Power Sales Ten L.L.C.	Delaware
Collins Holdings EME, LLC	Delaware
CP Power Sales Nineteen, L.L.C.	Delaware
CP Power Sales Seventeen, L.L.C.	Delaware
CP Power Sales Twelve, L.L.C.	Delaware
CP Power Sales Twenty, L.L.C.	Delaware
Del Mar Energy Company	California
Desert Sunrise Energy Company	Nevada
Doga Enerji Uretim Sanayi ve Ticaret L.S.	Turkey
Doga Isletme ve Bakim Ticaret L.S.	Turkey
Doga Isi Satis Hizmetleri ve Ticaret L.S.	Turkey
Edison First Power Holdings I	United Kingdom
Edison First Power Holdings II	United Kingdom

1

Edison First Power Limited	Guernsey
Edison Mission Development, Inc.	Delaware
Edison Mission Energy Fuel	California
Edison Mission Energy Fuel Services, LLC	Delaware
Edison Mission Energy Interface Ltd.	British Columbia
Edison Mission Energy Petroleum	California
Edison Mission Energy Services, Inc.	California
Edison Mission Finance Co.	California
Edison Mission Fuel Resources, Inc.	Delaware
Edison Mission Fuel Transportation, Inc.	Delaware
Edison Mission Holdings Co.	California
Edison Mission Marketing & Trading, Inc.	California
Edison Mission Midwest Holdings Co.	Delaware
Edison Mission Midwest, Inc.	Delaware
Edison Mission Operation & Maintenance, Inc.	California
Edison Mission Overseas Limited.	United Kingdom
Edison Mission Project Co.	Delaware
Edison Mission Wind, Inc.	Delaware
EME Ascot Limited	United Kingdom
EME Atlantic Holdings Limited	United Kingdom
EME Buckingham Limited	United Kingdom
EME CP Holdings Co.	Delaware
EME Eastern Holdings Co.	Delaware
EME Finance UK Limited	United Kingdom
EME Homer City Generation L.P.	Pennsylvania
EME Investments, LLC	Delaware
EME Investments II, LLC	Delaware
EME Southwest Power Corporation	Delaware
EME UK International LLC	Delaware
EMP, Inc.	Oregon
Energy Generation Finance UK PLC	United Kingdom
First Hydro Renewables Limited	United Kingdom

2

First Hydro Renewables Number 2 Limited	Wales
Global Power Investors, Inc.	California
Hancock Generation LLC	Delaware
Homer City Property Holdings, Inc.	California
Laguna Energy Company	California
Lakeland Power Development Company Limited	United Kingdom
Lakeland Power Ltd.	United Kingdom
Lehigh River Energy Company	California
Madison Energy Company	California
Maine Mountain Power, LLC	Delaware
Maplekey Holdings Limited	United Kingdom
Maplekey UK Finance Limited	United Kingdom
Maplekey UK Limited	United Kingdom
MEC Esenyurt B.V.	The Netherlands
MEC San Pascual B.V.	The Netherlands
Midwest Finance Corp.	Delaware
Midwest Generation EME, LLC	Delaware
Midwest Generation, LLC	Delaware
Midwest Generation Energy Services, LLC	Delaware
Midwest Peaker Holdings, Inc.	Delaware
Mission Capital, L.P.	Delaware
Mission De Las Estrellas LLC	Delaware
Mission Del Cielo Inc.	Delaware
Mission Del Sol, LLC	Delaware
Mission/Eagle Energy Company	California
Mission Energy Construction Services, Inc.	California
Mission Energy Generation, Inc.	California
Mission Energy Holdings, Inc.	California
Mission Energy Holdings International, Inc.	Delaware
Mission Energy Singapore Pte Ltd	Singapore
Mission Energy Wales Company	California
Mission Energy Westside, Inc.	California
Mission Triple Cycle Systems Company	California

3

Mission Wind Maine, Inc.	Delaware
Mission Wind New Mexico, Inc.	Delaware
Mission Wind Pennsylvania, Inc.	Delaware
Mission Wind Texas, Inc.	Delaware
Mission Wind Wildorado, Inc.	Delaware
North Shore Energy, L.P.	Delaware
Northville Energy Corporation	New York
Ortega Energy Company	California
Panther Timber Company	California
Paradise Energy Company	California
Pego Limited	United Kingdom
Pleasant Valley Energy Company	California
Pride Hold Limited	United Kingdom
Rapidan Energy Company	California
Redbill Contracts Limited	United Kingdom
Reeves Bay Energy Company	California
Riverport Energy Company	California
San Gabriel Energy Company	California
San Joaquin Energy Company	California
San Juan Energy Company	California
San Juan Mesa Wind Project, LLC	Delaware
San Juan Mesa Investments, LLC	Delaware
San Pedro Energy Company	California
Santa Clara Energy Company	California
Silverado Energy Company	California
Southern Sierra Energy Company	California
Thorofare Energy Company	California
Valle Del Sol Energy, LLC	Delaware
Viejo Energy Company	California
Vista Energy Company	New Jersey
Walnut Creek Energy, LLC	Delaware
Western Sierra Energy Company	California

4

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EDISON MISSION ENERGY LIST OF SUBSIDIARIES As of December 31, 2005

EX-31.1

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Exhibit 31.1

CERTIFICATIONS

        I, Theodore F. Craver, Jr., certify that:

1.

I have reviewed this annual report on Form 10-K of Edison Mission Energy (the "annual report");

2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

(c)

Disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:    March 6, 2006 /s/  THEODORE F. CRAVER, JR. Theodore F. Craver, Jr.
President and
Chief Executive Officer

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CERTIFICATIONS

EX-31.2

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Exhibit 31.2

CERTIFICATIONS

        I, W. James Scilacci, certify that:

1.

I have reviewed this annual report on Form 10-K of Edison Mission Energy (the "annual report");

2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

(c)

Disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:    March 6, 2006 /s/  W. JAMES SCILACCI W. James Scilacci
Senior Vice President and Chief
Financial Officer

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CERTIFICATIONS

EX-32

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Exhibit 32

STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350,
AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the accompanying Annual Report on Form 10-K for the year ended December 31, 2005 (the "Annual Report") of Edison Mission Energy (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his knowledge and belief, that:

1.

The Annual Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

2.

The information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  THEODORE F. CRAVER, JR. Theodore F. Craver, Jr.
Chief Executive Officer
Edison Mission Energy

/s/  W. JAMES SCILACCI W. James Scilacci
Chief Financial Officer
Edison Mission Energy

        This statement accompanies the Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

        A signed original of this written statement required by Section 906 has been provided to Edison Mission Energy and will be retained by Edison Mission Energy and furnished to the Securities and Exchange Commission or its staff upon request.

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STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350, AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002