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

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

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. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "accelerated filer," "large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

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, 2008: $0. Number of shares outstanding of the registrant's Common Stock as of March 2, 2009: 100 shares (all shares held by an affiliate of the registrant).

The registrant meets the conditions set forth in General Instruction I.(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K under the reduced disclosure format.

		Page

	Glossary	ii
	Forward-Looking Statements	1
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Submission of Matters to a Vote of Security Holders	37
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	39
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	100
Item 8.	Financial Statements and Supplementary Data	101
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	101
Item 9A.	Controls and Procedures	101
Item 9A(T).	Controls and Procedures	102
Item 9B.	Other Information	102
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	173
Item 11.	Executive Compensation	173
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	173
Item 13.	Certain Relationships and Related Transactions, and Director Independence	173
Item 14.	Principal Accountant Fees and Services	174
PART IV
Item 15.	Exhibits and Financial Statement Schedules	175
	Signatures	181

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.


Ameren		Ameren Corporation
ARO(s)		asset retirement obligation(s)
Btu		British thermal units
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
Commonwealth Edison		Commonwealth Edison Company
CONE		cost of new entry
CPS		Combined Pollutant Standard
DOJ		United States Department of Justice
EIA		Energy Information Administration
EME		Edison Mission Energy
EME Homer City		EME Homer City Generation L.P.
EMMT		Edison Mission Marketing & Trading, Inc.
EPAct 2005		Energy Policy Act of 2005
ERCOT		Electric Reliability Council of Texas
EWG(s)		exempt wholesale generator(s)
Exelon Generation		Exelon Generation Company LLC
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		flue gas desulfurization
FIN No. 39-1		Financial Accounting Standards Board Staff Position No. 39-1, "Amendment of FASB Interpretation No. 39"
FIN No. 48		Financial Accounting Standards Interpretation No. 48, "Accounting for Uncertainty in Income Taxes"
Fitch		Fitch Ratings
FPA		Federal Power Act
FSP SFAS No. 142-3		Financial Accounting Standards Board Staff Position SFAS No. 142-3, "Determination of the Useful Life of Intangible Assets"
GAAP		United States generally accepted accounting principles
GHG		greenhouse gas
GWh		gigawatt-hours
Illinois EPA		Illinois Environmental Protection Agency
Illinois Plants		EME's largest power plants (fossil fuel) located in Illinois
IPM		a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%)
ISO(s)		independent system operator(s)


LIBOR		London Interbank Offered Rate
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations
MEHC		Mission Energy Holding Company
Midwest Generation		Midwest Generation, LLC
MISO		Midwest Independent Transmission System Operator
MMBtu		million British thermal units
Moody's		Moody's Investors Service, Inc.
MW		megawatts
MWh		megawatt-hours
NAPP		Northern Appalachian
NOV		notice of violation
NO_X		nitrogen oxide
NSR		New Source Review
NYISO		New York Independent System Operator
PADEP		Pennsylvania Department of Environmental Protection
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
PUHCA 1935		Public Utility Holding Company Act of 1935 (as amended)
PUHCA 2005		Public Utility Holding Company Act of 2005
PURPA		Public Utility Regulatory Policies Act of 1978 (as amended)
RPM		reliability pricing model
RTO(s)		regional transmission organization(s)
S&P		Standard & Poor's Ratings Services
SCAQMD		South Coast Air Quality Management District
SCE		Southern California Edison Company
SCR		selective catalytic reduction
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS No. 98		Statement of Financial Accounting Standards No. 98, "Sale-Leaseback Transactions Involving Real Estate"
SFAS No. 123(R)		Statement of Financial Accounting Standards No. 123(R), "Share-Based Payment"
SFAS No. 133		Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS No. 141(R)		Statement of Financial Accounting Standards No. 141(R), "Business Combinations"
SFAS No. 144		Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS No. 157		Statement of Financial Accounting Standards No. 157, "Fair Value Measurements"

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:

Certain of the risk factors listed above are discussed in more detail in "Item 1A. Risk Factors" 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.

EME was formed in 1986 with two domestic operating power plants. EME's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. EME's operating projects primarily consist of coal-fired generating facilities, natural gas-fired generating facilities and wind farms. As of December 31, 2008, EME's subsidiaries and affiliates owned or leased interests in 37 operating projects with an aggregate net physical capacity of 11,019 MW of which EME's capacity pro rata share was 9,849 MW. At December 31, 2008, three wind projects with an EME capacity pro rata share totaling 223 MW of net generating capacity were under construction.

Global financial markets are experiencing severe credit tightening and a significant increase in volatility, causing access to capital markets to become subject to increased uncertainty and borrowing costs. In response, U.S. and foreign governments and central banks have intervened with programs designed to increase liquidity and restore confidence.

EME is in a capital intensive business and depends on access to the financial markets to fund capital expenditures, meet contractual obligations and support margin and collateral requirements. EME has expanded its business development activities to grow and diversify its existing portfolio of power projects, including building new power plants. In addition, EME has environmental compliance requirements and ongoing capital expenditures for its existing generation fleet. All of these activities require liquidity and access to capital markets at reasonable rates in the future. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Business Development" and "Liquidity and Capital Resources—Capital Expenditures."

Disruptions in the capital markets affected in 2008, and may continue to affect, EME's ability to finance already-developed wind projects and future commitments and projects, including significant outstanding capital commitments for wind turbines. Furthermore, these disruptions may affect how EME addresses its commitments with respect to environmental compliance, as discussed further in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview; Critical Accounting Policies and Estimates—Management's Overview—Environmental Developments—Air Quality Regulation in Illinois." As a result, pending recovery of the capital markets, EME intends to preserve capital by focusing on a selective growth strategy (primarily completion of projects under construction, including the Big Sky wind project in Illinois, and development of sites for future renewable projects deploying current turbine commitments), and using its cash and future cash flow to meet its existing contractual commitments. Depending upon financing conditions, EME may elect to postpone and/or cancel wind turbine commitments, subject to the provisions of the relevant contracts. Moreover, disruption in the financial markets appears to have reduced trading activity in power markets

which may affect the level and duration of future hedging activity and potentially increase the volatility of earnings. Long-term disruption in the capital markets could adversely affect EME's business plans and financial position.

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, as amended, and are available on the Securities and Exchange Commission's internet web site at http://www.sec.gov.

Historically, investor-owned utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. However, the United States electric industry, including companies engaged in providing generation, transmission, distribution and retail sales and service of electric power, has undergone significant deregulation over the last three decades, which has led to increased competition, especially in the generation sector. Most recently, through EPAct 2005, the U.S. Congress recognized that a significant market for electric power generated by independent power producers, such as EME, has developed in the United States and indicated that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.

As part of the developments discussed above, the FERC has encouraged the formation of ISOs and RTOs. In those areas where ISOs and RTOs have been formed, market participants have open access to transmission service typically at a system-wide rate. 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 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."

In various regional markets, electricity market administrators have acknowledged that the markets for generating capacity do not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage new generating capacity to be constructed. Capacity auctions have been implemented in some markets, including PJM, to address this issue. This approach is currently expected to provide significant additional capacity revenues for independent power producers.

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, an RTO which includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

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. It can also be affected by, among other things, market mitigation measures and energy market price caps.

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, with respect to the Illinois Plants, and 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. For a discussion of legal challenges to the prices resulting from PJM's capacity auctions, see "Regulatory Matters—PJM Matters—RPM Buyers' Complaint."

The Homer City facilities have direct, high voltage interconnections to PJM and also to the NYISO, which controls the transmission grid and energy and capacity markets for New York State. 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.

For a discussion of the market 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."

EME is subject to intense competition from energy marketers, investor-owned utilities, government-owned power agencies, industrial companies, financial institutions, and other independent power producers. Some of EME's competitors have a lower cost of capital than most independent power producers and, in the case of utilities, are often 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. These companies may also have competitive advantages as a result of their scale and the location of their generation facilities.

Environmental regulations, particularly those that impose stringent state specific emission limits, could put EME's coal-fired plants at a disadvantage compared with competing power plants operating in nearby states and subject only to federal emission limits. Potential future climate change regulations could also put EME's coal-fired power plants at a disadvantage compared to both power plants utilizing other fuels and utilities that may be able to recover climate change compliance costs through rate mechanisms. In addition, EME's ability to compete may be affected by governmental and regulatory activities designed to support the construction and operation of power generation facilities fueled by renewable energy sources.

EME operates in one line of business, independent power production, with all its continuing operations located in the United States, except the Doga project in Turkey. Operating revenues are primarily derived from the sale of energy and capacity 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.

As of December 31, 2008, EME's operations consisted of ownership or leasehold interests in the following operating projects:

Power Plants(1)			Location	Primary Electric Purchaser(2)	Fuel Type

MERCHANT POWER PLANTS
	Illinois Plants		Illinois	PJM	Coal	100	%	5,471	5,471
	Illinois Plants		Illinois	PJM	Oil/Gas	100	%	305	305
	Homer City facilities		Pennsylvania	PJM	Coal	100	%	1,884	1,884
	Goat Wind (Phase I)		Texas	ERCOT	Wind	99.9	%(3)	80	80
	Lookout		Pennsylvania	PJM	Wind	100	%	38	38
CONTRACTED POWER PLANTS—Domestic
*Natural Gas*
	Big 4 Projects
		Kern River	California	SCE	Natural Gas	50	%	300	150
		Midway-Sunset	California	SCE	Natural Gas	50	%	225	113
		Sycamore	California	SCE	Natural Gas	50	%	300	150
		Watson	California	SCE	Natural Gas	49	%	385	189
	Westside Projects
		Coalinga	California	PG&E	Natural Gas	50	%	38	19
		Mid-Set	California	PG&E	Natural Gas	50	%	38	19
		Salinas River	California	PG&E	Natural Gas	50	%	38	19
		Sargent Canyon	California	PG&E	Natural Gas	50	%	38	19
	March Point		Washington	PSE	Natural Gas	50	%	140	70
	Sunrise		California	CDWR	Natural Gas	50	%	572	286
*Wind*
	Buffalo Bear		Oklahoma	WFEC	Wind	100	%	19	19
	Crosswinds		Iowa	CBPC	Wind	99	%(3)	21	21
	Forward		Pennsylvania	CECG	Wind	100	%	29	29
	Hardin		Iowa	IPLC	Wind	99	%(3)	15	15
	Jeffers		Minnesota	NSPC	Wind	99.9	%(3)	50	50
	Minnesota Wind projects(4)		Minnesota	NSPC/IPLC	Wind	75-99	%(3)	83	75
	Mountain Wind I		Wyoming	PC	Wind	100	%	61	61
	Mountain Wind II		Wyoming	PC	Wind	100	%	80	80
	Odin		Minnesota	MRES	Wind	99.9	%(3)	20	20
	San Juan Mesa		New Mexico	SPS	Wind	75	%	120	90
	Sleeping Bear		Oklahoma	PSCO	Wind	100	%	95	95
	Spanish Fork		Utah	PC	Wind	100	%	19	19
	Storm Lake		Iowa	MEC	Wind	100	%	109	109
	Wildorado		Texas	SPS	Wind	99.9	%(3)	161	161
*Coal and Other*
	American Bituminous		West Virginia	MPC	Waste Coal	50	%	80	40
	Huntington Waste-to-Energy		New York	LIPA	Biomass	38	%	25	9
CONTRACTED POWER PLANTS—International
	Doga		Turkey	TEDAS	Natural Gas	80	%	180	144

		Total						11,019	9,849

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.

Operating Plant or Site		Location	Leased/ Owned	Fuel

Electric Generating Facilities
	Crawford Station	Chicago, Illinois	owned	coal	532
	Fisk Station	Chicago, Illinois	owned	coal	326
	Joliet Unit 6	Joliet, Illinois	owned	coal	290
	Joliet Units 7 and 8	Joliet, Illinois	leased	coal	1,036
	Powerton Station	Pekin, Illinois	leased	coal	1,538
	Waukegan Station	Waukegan, Illinois	owned	coal	689	(1)
	Will County Station	Romeoville, Illinois	owned	coal	1,060	(2)
Peaking Units
	Fisk	Chicago, Illinois	owned	oil/gas	197
	Waukegan	Waukegan, Illinois	owned	oil/gas	108

	Total				5,776

Other Plant or Site
	Collins Station(3)	Grundy County, Illinois
	Crawford peaker(4)	Chicago, Illinois
	Joliet peaker(5)	Joliet, Illinois
	Calumet peaker(5)	Chicago, Illinois
	Electric Junction peaker(5)	Aurora, Illinois
	Lombard peaker(5)	Lombard, Illinois
	Sabrooke peaker(5)	Rockford, Illinois

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 prior to December 31, 2004, by which time 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 "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Transactions."

Energy generated at the Illinois Plants after their acquisition in 1999 was sold under three power purchase agreements between Midwest Generation and 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 had been terminated by December 31, 2004.

All the energy and capacity from the Illinois Plants is now sold under terms, including price and quantity, arranged by EMMT, an EME subsidiary engaged in the power marketing and trading business, with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), 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. PJM has a short-term market, which establishes an hourly clearing price.

In September 2006, the first Illinois power procurement auction was held according to the rules approved by the Illinois Commerce Commission. Through the auction, EMMT entered into two load requirements service contracts. Under the terms of these agreements, Midwest Generation is delivering, through EMMT, electricity, capacity and specified ancillary, transmission and load following services necessary to serve a portion of Commonwealth Edison's residential and small commercial customer load.

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."

Coal is used to fuel 5,471 MW of Midwest Generation's generating capacity. The coal is purchased from several suppliers that operate mines in the Southern PRB of Wyoming. The total volume of coal consumed annually is largely dependent on the amount of generation and ranges between 17.5 million to 19.5 million tons.

All coal is transported under long-term transportation agreements with the Union Pacific Railroad and various delivering carriers. As of December 31, 2008, Midwest Generation leased approximately 4,000 railcars to transport the coal from the mines to the generating stations and the leases have remaining terms that range from less than two years to 11 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 typically 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. Occasionally, third-party transloading facilities are utilized.

Midwest Generation has approximately 305 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.

On March 18, 1999, EME Homer City 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.

On December 7, 2001, EME Homer City completed a sale-leaseback of the Homer City facilities to third-party lessors. EME Homer City 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."

All the energy and capacity from the Homer City facilities is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM 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. For a discussion of the risks related to EME Homer City's sale of electricity, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

Units 1 and 2 collectively 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 as needed. A wet scrubber FGD 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.

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances sufficient to cover their annual emissions. Illinois and Pennsylvania regulations implemented the federal NO_X SIP Call which required, through 2008, the holding of NO_X allowances to cover ozone season NO_X emissions. In addition, pursuant to Pennsylvania's and Illinois' implementation of the CAIR, electric generating stations are required to hold seasonal and annual NO_X allowances beginning January 1, 2009. 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. 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.

See "Item 8. Financial Statements and Supplementary Data—Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—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.

EME owns a 99.9% interest in Goat Wind LP, which owns an 80 MW wind farm project in Texas, which EME refers to as the Goat Wind Phase I wind project. The project sells electricity into the ERCOT market as a merchant wind generator. The Goat Wind Phase I wind project achieved commercial operation in April 2008.

EME owns a 100% interest in Lookout WindPower LLC, which owns a 38 MW wind farm located in Pennsylvania, which EME refers to as the Lookout wind project. The project sells electricity into PJM as a merchant wind generator. The Lookout wind project achieved commercial operation in October 2008.

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 SCE, an affiliate of EME. Because these projects have similar economic characteristics, EME views these 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 1. Summary of Significant Accounting Policies," for discussion of EME's accounting for the Big 4 projects.

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 SCE and its steam supply agreement with Texaco Exploration and Production Inc., 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 with SCE, which was in effect until June 1, 2006 when it was replaced by a new five-year bilateral agreement with SCE. On August 10, 2005, Kern River Cogeneration also entered into a new Steam Purchase and Sale Agreement with Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc., with a term equivalent to the new power purchase agreement.

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 electricity to SCE, Aera Energy LLC and PG&E under power purchase agreements that expire in May 2009 and steam to Aera Energy LLC under a steam supply agreement that also expires in May 2009. Thereafter, Midway-Sunset expects to continue selling electricity either pursuant to a new power sales agreement or to SCE under the terms and conditions contained in its prior long-term power sales agreement, with revised pricing terms as mandated by the California Public Utilities Commission. 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—Big 4 Projects" for further discussion.

EME owns a 50% partnership interest in Sycamore Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Sycamore project. Sycamore Cogeneration's prior long-term power purchase agreement with SCE and its steam supply agreement with Chevron North America Exploration and Production Company, a wholly owned subsidiary of Chevron Corporation, both expired on December 31, 2007. Sycamore Cogeneration is currently selling electricity to SCE under the terms and conditions contained in its prior long-term power purchase agreement, with revised pricing terms as mandated by California Public Utilities Commission Decision 07-09-040, dated September 20, 2007. EME expects that this arrangement will eventually be replaced by a new power purchase agreement between Sycamore and SCE, but cannot predict at this time whether or when this will occur. Sycamore Cogeneration entered into a new steam supply agreement with Chevron North America Exploration and Production Company that expires in 2013.

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. According to SCE, Watson Cogeneration's prior long-term power purchase agreement with SCE expired on December 31, 2007. Watson Cogeneration contends that the agreement expired in April 2008 and is considering filing a claim for recovery of lost profits due to the early expiration date. Watson Cogeneration is currently selling electricity to SCE under the terms and conditions contained in its prior long-term power purchase agreement, with revised pricing terms as mandated by California Public Utilities Commission Decision 07-09-040, dated September 20, 2007. EME expects that this arrangement will eventually be replaced by a new power purchase agreement between Watson and SCE, but cannot predict at this time whether or when this will occur. Watson Cogeneration currently sells power and steam to BP West Coast Products LLC under agreements that expire in 2013 or upon the termination of any new power purchase agreement executed between Watson and SCE, whichever is earlier.

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 sold electricity to PG&E under 15-year power purchase agreements which expired during the first quarter of 2007. These projects executed agreements with PG&E for the continued sale of electricity at "as available" rates. Mid-Set Cogeneration's original power purchase agreement with PG&E expired in May 2004. Mid-Set Cogeneration continues to sell electricity to PG&E at "as available" rates under an agreement that expires on December 31, 2009.

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

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

EME owns a 100% interest in Buffalo Bear, LLC, which owns a 19 MW wind farm located in Oklahoma, which EME refers to as the Buffalo Bear wind project. The project sells electricity to

Western Farmers Electric Cooperative under a 25-year power purchase agreement. The Buffalo Bear wind project achieved commercial operation in December 2008.

EME owns a 99% interest in Crosswinds Energy Projects consisting of 10 separate limited liability companies, which collectively form a 21 MW wind farm located in northwestern Iowa, which EME refers to as the Crosswinds wind project. The projects sell electricity to Corn Belt Power Cooperative under 15-year (with a 5-year renewal option) power purchase agreements. The Crosswinds wind project achieved commercial operation in June 2007.

EME owns a 100% interest in Forward WindPower LLC, which owns a 29 MW wind farm located in Pennsylvania, which EME refers to as the Forward wind project. The project sells electricity to Constellation Energy Commodities Group, Inc. under a power purchase agreement that expires in 2017. The Forward wind project achieved commercial operation in April 2008.

EME owns a 99% interest in Hardin Hilltop Projects consisting of seven separate limited liability companies, which collectively form a 15 MW wind farm located in western Iowa, which EME refers to as the Hardin wind project. The projects sell electricity to Interstate Power and Light Company under 20-year power purchase agreements. The Hardin wind project achieved commercial operation in May 2007.

EME owns a 99.9% interest in Jeffers Wind 20 LLC, which owns a 50 MW wind farm located in western Minnesota, which EME refers to as the Jeffers wind project. The project sells electricity to Northern States Power Company under Minnesota's Community-Based Energy Development Program under a 20-year power purchase agreement. The Jeffers wind project achieved commercial operation in October 2008.

EME owns interests of between 75% and 99% in 37 separate Minnesota limited liability companies, each of which owns a small wind-powered electric generation facility in Minnesota, which EME refers to collectively as the Minnesota wind projects. The Minnesota wind projects collectively total approximately 83 MW. Each of the Minnesota wind projects sells electricity to either (i) Northern States Power Company under a power purchase agreement that expires between 2025 and 2034 or (ii) Interstate Power and Light Company under a power purchase agreement that expires in 2021.

EME owns a 100% interest in each of Mountain WindPower LLC, which owns a 61 MW wind farm in Wyoming, which EME refers to as the Mountain Wind I project, and Mountain WindPower II, LLC, which owns an 80 MW wind farm, also located in Wyoming, which EME refers to as the Mountain Wind II project. These projects sell electricity to PacifiCorp under 25-year power purchase agreements. The Mountain Wind I project achieved commercial operation in July 2008 and the Mountain Wind II project achieved commercial operation in September 2008.

EME owns a 99.9% interest in Odin Wind Farm, LLC, which owns a 20 MW wind farm located in Minnesota, which EME refers to as the Odin wind project. The project sells electricity to Missouri River Energy Services under 20-year power purchase agreements. The Odin wind project achieved commercial operation in May 2008.

EME owns a 75% interest in San Juan Mesa Wind Project LLC, which owns a 120 MW wind farm located near Elida, New Mexico, which EME refers to as the San Juan Mesa wind project. The project sells electricity to Southwestern Public Service Company, a subsidiary of Xcel Energy, under a power purchase agreement that expires in 2025. The San Juan Mesa wind project achieved commercial operation in December 2005.

EME owns a 100% interest in Sleeping Bear LLC, which owns a 95 MW wind farm located in northwestern Oklahoma, which EME refers to as the Sleeping Bear wind project. The project sells electricity to Public Service Company of Oklahoma, a unit of American Electric Power, under a 25-year power purchase agreement. The Sleeping Bear wind project achieved commercial operation effective September 2007.

EME owns a 100% interest in Spanish Fork Wind Farm 2, LLC, which owns a 19 MW wind farm located in Utah, which EME refers to as the Spanish Fork wind project. The project sells electricity to PacifiCorp under a 20-year power purchase agreement. The Spanish Fork wind project achieved commercial operation in July 2008.

EME owns a 100% interest in Storm Lake Power Partners I, LLC, which owns a 109 MW wind farm located near Alta, Iowa, which EME refers to as the Storm Lake wind project. The project sells electricity to Mid-American Energy Company under a power purchase agreement that expires in 2020.

EME owns a 99.9% interest in Wildorado Wind, LLC, which owns a 161 MW wind farm located in the panhandle of northern Texas, which EME refers to as the Wildorado wind project. The project sells electricity to Southwestern Public Service Company under a 20-year power purchase agreement. The Wildorado wind project achieved commercial operation in April 2007.

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 2035.

EME owns a 38% limited partnership interest in Covanta Huntington LP, which owns a 25 MW waste-to-energy facility located near the Town of Huntington, New York, which EME refers to as the Huntington project. The project processes waste materials under a solid waste disposal services agreement with the Town of Huntington, which is set to expire in 2012 with an option to renew. The project also sells electricity to Long Island Power Authority under a power purchase agreement that expires in 2012.

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

As of December 31, 2008, EME had the projects described below under construction. Each project will, after its completion, use wind to generate electricity from turbines, which will be sold pursuant to the project's power purchase agreement or as a merchant wind generator.

EME owns a 99.9% interest in Goat Wind LP, which, in addition to the Goat Wind Phase I wind project in operation in Texas, owns a 70 MW wind farm project in Texas, which EME refers to as the Goat Wind Phase II wind project. Construction of this project commenced during the third quarter of 2007 and is scheduled for completion during the first half of 2009. The project plans to sell electricity into the ERCOT market as a merchant wind generator.

EME owns a 66.67% interest in Elkhorn Ridge Wind, LLC, which owns an 80 MW wind farm located in Nebraska, which EME refers to as the Elkhorn Ridge wind project. This project started construction in May 2008 and is scheduled for completion during the first quarter of 2009. The project plans to sell electricity to Nebraska Public Power District under a 20-year power purchase agreement.

EME owns a 100% interest in High Lonesome Mesa, LLC, which owns a 100 MW wind farm located in New Mexico, which EME refers to as the High Lonesome wind project. This project started construction in July 2008 and is scheduled for completion during the third quarter of 2009. The project plans to sell electricity to Arizona Public Service Company under a 30-year power purchase agreement.

EME has made significant investments in wind projects and plans to continue to do so over the next several years, subject to market conditions. Historically, wind projects have received federal subsidies in the form of production tax credits. Production tax credits for a ten-year period are available for new projects placed in service by December 31, 2012.

In seeking to find and invest in new wind projects, EME has entered into joint development agreements with third-party development companies that provide for funding by an EME subsidiary of development costs including through loans (referred to as development loans) and joint decision-making on key contractual agreements such as power purchase contracts, site agreements and permits. Joint development agreements and development loans may be for a specific project or a group of identified and future projects and generally grant EME the exclusive right to acquire related projects. In addition to joint development agreements, EME may purchase wind projects from third-party developers in various stages of development, construction or operation. See "Item 8. Financial Statements and Supplementary Data—Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Acquisitions and Variable Interest Entities—Variable Interest Entities" for further discussion.

In general, EME funds development costs under joint development agreements through development loans which are secured by project specific assets. A project's development loans are repaid upon the completion of the project. If the project is purchased by EME, repayment is made from proceeds received from EME in connection with the purchase. In the event EME declines to purchase a project, repayment is to be made from proceeds received from the sale of the project to third parties or from other sources as available.

As of December 31, 2008, EME had a development pipeline of potential wind projects with a projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits and agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed.

During 2008, EME submitted bids in competitive solicitations to supply power from solar projects under development in the southwestern United States. Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission interconnection, site control, and construction costs estimates, and to negotiate power sales agreements. To support development activities, EME entered into an agreement with First Solar Electric, LLC to provide design, engineering, procurement, and construction services for solar projects for identified customers, subject to the satisfaction of certain contingencies and entering into definitive agreements for such services for each project.

During the first quarter of 2008, a subsidiary of EME was awarded by SCE, through a competitive bidding process, a ten-year power sales contract for the output of a 479 MW gas-fired peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. Deliveries under the power sales agreement are scheduled to commence in 2013. During the fourth quarter of 2008, EME and its subsidiary terminated a turbine supply agreement for the project to preserve capital and recorded a pre-tax charge of $23 million ($14 million, after tax). EME plans to purchase turbines for the project subject to resolution of uncertainty regarding the availability of required emissions credits. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Expenditures for New Projects," for further details on the status of this project.

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

In conducting EME's hedging 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 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 EME would expect to incur if a counterparty failed to perform pursuant to the terms of its 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.

EME has established processes to determine and monitor the creditworthiness of counterparties. EME manages the credit risk of its counterparties 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's merchant operations expose it to commodity price risk. 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. EME uses "gross margin at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions of the Illinois Plants, the Homer City facilities, and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify risk factors. Value at risk measures the possible loss, and gross margin at risk measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

In executing agreements with counterparties to conduct hedging 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."

In the past three fiscal years, EME's merchant plants sold electric power generally into the PJM market by participating in PJM's capacity and energy markets or by selling capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 50%, 51% and 58% of EME's consolidated operating revenues for the years ended December 31, 2008, 2007 and 2006, respectively. Beginning in January 2007, EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 12% and 19% of EME's consolidated

operating revenues for the years ended December 31, 2008 and 2007, respectively. For the year ended December 31, 2008, a third customer, Constellation Energy Commodities Group, Inc. accounted for 10% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from EME's merchant plants and largely consist of energy sales under forward contracts.

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 EME Homer City property insurance program currently covers losses up to $1.325 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 will permit it to maintain its current insurance coverage through June 1, 2009.

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the Illinois Plants and the Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinois Plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants" and "—Energy Price Risk Affecting Sales from the Homer City Facilities" for further discussion regarding market prices.

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.

During 2004 and early 2005, EME sold assets totaling 6,452 MW, which constituted most of its international assets. Except for the Doga project, which was not sold, these international assets are accounted for as discontinued operations in accordance with SFAS No. 144 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:

See "Item 8. Financial Statements and Supplementary Data—Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Divestitures" for further details of discontinued operations.

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 development, ownership and operation of its projects, and the use of electric energy, capacity and related products, including ancillary services from its projects. In addition, EME is subject to the market rules, procedures, and protocols of the markets in which it participates.

The laws and regulations that affect EME and its operations are in a state of flux. Complex 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 if a project were to become unable to function as planned due to changing requirements or local opposition.

The FERC has ratemaking jurisdiction and other authority with respect to wholesale sales and interstate transmission of electric energy (other than transmission that is "bundled" with retail sales) under the FPA and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. 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 FPA and PUHCA 1935 for the owners of qualifying facilities. Independent power production has been further encouraged by the passage of the Energy Policy Act in 1992, which provided additional exemptions from PUHCA 1935 for EWGs and foreign utility companies, and the EPAct 2005, which included provisions for the repeal of PUHCA 1935, amendments to PURPA, merger review reform, the introduction of new regulations regarding transmission operation improvements, FERC authority to impose civil penalties for

violation of its regulations, transmission rate reform, incentives for various generation technologies and the extension of production tax credits for wind and other specified types of generation.

On July 20, 2006, the FERC certified the North American Electric Reliability Corporation (NERC) as its Electric Reliability Organization to establish and enforce reliability standards for the bulk power system. Compliance with these standards became mandatory on June 18, 2007. EME believes it has taken all steps to be compliant with current NERC reliability standards that apply to its operations.

The FPA 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 FPA. EWGs certified in accordance with the FERC's rules under PUHCA 2005 are subject to the FPA and to the FERC's ratemaking jurisdiction thereunder, but the FERC typically grants EWGs the authority to sell power at market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. As of December 31, 2008, EME's power marketing subsidiaries, including EMMT, and a number of EME's operating projects, including the Homer City facilities and the Illinois Plants, were authorized by the FERC to make wholesale market sales of power at market-based rates and were subject to the FERC ratemaking regulation under the FPA. EME's future domestic non-qualifying facility independent power projects will also be subject to the FERC jurisdiction on rates.

The FPA also grants the FERC jurisdiction over the sale or transfer of specified assets, including wholesale power sales contracts and generation facilities, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. Dispositions of EME's jurisdictional assets or certain types of financing arrangements may require FERC approval.

PURPA provides two primary benefits to qualifying facilities. First, all cogeneration facilities that are qualifying facilities are exempt from certain provisions of the FPA and regulations of the FERC thereunder. Second, the FERC regulations promulgated under PURPA required 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 has determined 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 permitted qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs.

Several of EME's projects, including the Big 4 projects, the Westside projects, American Bituminous, and March Point, are qualifying cogeneration facilities. To be a qualifying cogeneration facility, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial

process or heating or cooling applications in certain proportions to the facility's total energy output, and must meet certain efficiency standards. If one of the projects in which EME has an interest were to lose its qualifying facility status, 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 FPA 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 refund claims from utility customers, 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, it might not be possible to recover the costs incurred in connection with the project through sales to other purchasers. 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.

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 FPA.

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 EWGs under PUHCA 1935 to more effectively compete in the wholesale market.

The Illinois Power Agency Act, signed into law on August 28, 2007, establishes a new process for Commonwealth Edison and the Ameren Illinois utilities to procure power for their bundled-rate customers. On July 1, 2008, the two utilities began procuring power for bundled-rate customers by means of existing full requirements contracts that have not yet expired, certain multi-year swap contracts that they entered into with their affiliates pursuant to the Illinois Power Agency Act, and a competitive request for proposal procurement of standard wholesale power products run by independent procurement administrators with the oversight and approval of the Illinois Commerce Commission. The Illinois Power Agency Act provides further that starting in June 2009, a newly created Illinois Power Agency will be responsible for the administration, planning and procurement of power for Commonwealth Edison and the Ameren Illinois utilities' bundled-rate customers using a portfolio-managed approach that is to include competitively procured standard wholesale products and renewable energy resources. The Illinois Commerce Commission will continue in its role of oversight and approval of the power planning and procurement for bundled retail customers of the utilities.

On January 7, 2009, the Illinois Commerce Commission approved a procurement plan for 2009 that was proposed by the Illinois Power Agency. The plan, which is based on five-year demand forecasts, proposes a laddered procurement strategy for the period beginning in 2009 and ending in 2014. In 2009, the Illinois Power Agency is expected to acquire through a single request for proposals roughly one third

of the forecasted demand for bundled load for Commonwealth Edison and Ameren. Renewable requirements, in the first year, will be purchased by way of one-year renewable energy credits; longer contracts may be included in future procurements if required by law or if approved by the Illinois Commerce Commission. The Illinois Power Agency issued its request for proposals in February 2009 and plans to conduct its procurement between mid-March and mid-April 2009.

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region's need for generation capacity, the cost of which is allocated to load-serving entities through a locational reliability charge. Also on June 1, 2007, PJM implemented marginal losses for transmission for its competitive wholesale electric market. For further discussion regarding the RPM and recent auctions, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Capacity Price Risk."

On May 30, 2008, a group of entities referring to themselves as the "RPM Buyers" filed a complaint at the FERC asking that PJM's RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. On September 19, 2008, the FERC dismissed the RPM Buyers' complaint, finding that the RPM Buyers had failed to allege or prove that any party violated PJM's tariff and market rules, and that the prices determined during the transition period were determined in accordance with PJM's FERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC's order dismissing their complaint. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

On December 12, 2008, PJM submitted revised RPM Tariff sheets pursuant to Section 205 of the FPA, proposing RPM auction modifications relating to CONE values, including a proposal to modify how scarcity pricing revenues are incorporated in the Net Energy and Ancillary Services Revenue Offset, new rules for participation of demand side management resources in the RPM auctions, and a proposed holdback of 2.5% of the reliability requirement from the Base Residual Auction. The CONE is used to construct the demand curve for RPM auctions, and its level affects the clearing price for those auctions (which is determined at the intersection of the supply and demand curves).

On February 9, 2009, PJM and several other parties to the proceedings filed a proposed settlement with the FERC with a proposed effective date of March 27, 2009. The CONE values in the proposed settlement represent a 10% decrease from those contained in PJM's December 12, 2008 filing. The proposed settlement would retain the 2.5% holdback proposed in PJM's December 12 filing and would increase the length of forward commitment for new capacity resources to seven years, instead of the five years originally proposed by PJM.

There was a high level of opposition to PJM's proposed modifications from buyers and consumers, and a similarly high level of opposition is expected with respect to the proposed settlement. The effect of the FERC's actions on future RPM auctions cannot be determined at this time. The CONE as proposed for the May 2009 RPM auction for the 2012/2013 delivery year is higher than what is currently effective in the tariff.

See the discussion on environmental matters and regulations in Note 12—Commitments and Contingencies under "Item 8. Financial Statements and Supplementary Data—Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements," as well as the discussions on NOVs issued to Midwest Generation and EME Homer City under "Item 3. Legal Proceedings."

At December 31, 2008, EME and its subsidiaries employed 1,889 people, including:

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

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 were secured by a first priority security interest in EME's common stock. On May 7, 2007, MEHC purchased substantially all of its senior secured notes with a dividend payment from EME.

On June 25, 2007, MEHC redeemed in full its senior secured notes. As a result of the redemption, EME is no longer subject to financial and investment restrictions that were contained in the indenture pursuant to which the senior secured notes were issued. Following the redemption, MEHC no longer files reports with the Securities and Exchange Commission.

The global financial crisis may have a material adverse impact on EME's access to capital necessary to fund contractual obligations and the ability of EME's counterparties to perform their contractual obligations.

Financial market and economic conditions had in 2008, and may continue to have, an adverse effect on EME's business and financial condition. The capital markets were not available to EME during the fourth quarter of 2008, and market uncertainty has continued into 2009. EME's ability to raise capital has been, and could continue to be, adversely affected by volatile and unpredictable global market and economic conditions. Even after the capital markets recover, recent disruptions in the credit markets may have lasting effects on the availability of credit, cost of borrowing, and terms and conditions of new borrowings.

In September 2008, Lehman Commercial Paper Inc., a lender in EME's credit agreement representing a commitment of $36 million, declined requests for funding under that agreement. Thereafter, in October 2008, it filed for bankruptcy protection. While the Lehman Commercial Paper bankruptcy is not expected to have a material adverse effect on EME, the situation may worsen if other lenders under the credit agreement file for bankruptcy or otherwise fail to perform their obligations.

Liquidity is essential to EME's business. EME cannot provide assurance that its projected sources of capital will be available when needed or that its actual cash requirements will not be greater than expected. Lack of available capital may affect EME's ability to complete environmental improvements of the Illinois Plants as prescribed by the CPS, which could lead to the eventual shutdown of a material part of the Illinois Plants. Lack of available capital could also affect EME's ability to complete the development of sites for renewable projects deploying current turbine commitments, which could lead to postponement or cancellation of the turbine commitments subject to the provisions of the related contracts.

In addition to the potential effect on EME's liquidity, the global financial crisis could have a negative effect on the markets in which EME and its subsidiaries sell power, purchase fuel and perform other trading and marketing activities. In recent years, global financial institutions have been active participants in such markets. As such financial institutions consolidate and operate under more restrictive capital constraints in response to the financial crisis, there could be less liquidity in the energy and commodity markets, which could have a negative effect on EME's ability to hedge and transact with creditworthy counterparties. In addition, EME is exposed to the risk that its counterparties, including customers, suppliers and business partners, may fail to perform according to the terms of their contractual arrangements. Deterioration in the financial condition of EME's counterparties as a result of the global financial crisis, and the resulting failure to pay amounts owed or to perform obligations in excess of posted collateral, could have a negative effect on EME's business and financial condition.

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 market price for energy, capacity and ancillary services is influenced by multiple factors beyond EME's control, which include:

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. In particular, due to the volume of sales into PJM from the Illinois Plants and Homer City facilities, EME has concentrated exposure to market conditions and fluctuations in PJM. 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.

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.

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.

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. However, EME cannot provide assurance that these strategies will successfully mitigate market risks.

EME may not cover the entire exposure of its assets or positions to market price volatility, and the level of coverage will vary over time. Fluctuating commodity prices may affect EME's financial results, either favorably or unfavorably, to the extent that assets and positions have not been hedged.

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:

As a result of these and other factors, EME cannot predict the effect that risk management decisions may have on its business, operating results or financial position.

EME's future financial condition, results of operation and cash flows will depend in large part upon its ability to successfully implement its long-term strategy, which includes the development and acquisition of electric power generation facilities, with an emphasis on renewable energy (primarily wind and solar) and gas-fired power plants. EME may be unable to identify attractive acquisition or development opportunities and/or to complete and integrate them on a successful and timely basis. Furthermore, implementation of this strategy may be affected by factors beyond EME's control, such as increased competition, legal and regulatory developments, price volatility in electric or fuel markets, and general economic conditions.

In support of its development activities, EME has entered into commitments to purchase wind turbines for future projects and may make substantial additional commitments in the future. In addition, EME expends significant amounts for preliminary engineering, permitting, legal and other expenses before it can determine whether it will win a competitive bid, or whether a project is feasible or economically attractive.

Historically, wind projects have received federal subsidies in the form of production tax credits. Currently, production tax credits are available for new wind projects placed in service by December 31, 2012. If the deadline for production tax credits is not extended, EME's development activities related to wind projects slated for completion after December 31, 2012 could be adversely affected.

EME's development activities are subject to risks including, without limitation, risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project agreements, including power purchase agreements. Moreover, recent economic conditions may affect the willingness of local utilities to enter into new power purchase agreements due to uncertainties over future load requirements, among other factors. As a result of these risks, EME may not be successful in developing new projects, or the timing of such development may be delayed beyond the date that turbines are ready for installation. Projects under development may be adversely affected by delays in turbine deliveries or start-up problems related to turbine performance, and agreements with off-takers may contain damages and termination provisions related to failures to meet specified milestones. If a project under development is abandoned, EME would expense all capitalized costs incurred in connection with that project, and could incur additional losses associated with any related contingent liabilities. If EME is not successful in developing new projects, it may be required to cancel turbine orders, or sell turbines that were purchased and such cancellation and/or sales may result in substantial losses.

Finally, EME cannot provide assurance that its development projects or acquired assets will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them, or that EME will ultimately realize a satisfactory rate of return.

A substantial portion of wind turbines purchased by EME may not perform as expected during start-up or operations, thereby adversely affecting the expected return on investment.

EME has purchased a significant number of wind turbines in support of its renewable energy activities. The turbines of one turbine manufacturer have experienced rotor blade cracks, and the turbines of another turbine manufacturer have also experienced blade problems. EME cannot provide assurance that repairs or replacements of the affected turbines will be timely or effective or that expected performance levels will be achieved. Significant delays in meeting commercial operation deadlines and/or reductions in project output could subject projects to damages under their power purchase agreements and, potentially, the risk of termination under some agreements. Turbine problems have also impacted EME's ability to secure project financing for these projects. EME cannot predict at this time the amount of damages that will be recovered by EME from the turbine suppliers. Furthermore, limited data is presently available regarding the performance of new wind turbines of a size over 2 MW over an extended period of time. Accordingly, EME cannot provide assurance that it will earn its expected return over the life of the projects.

The independent power industry is characterized by numerous capable competitors, some of whom may have more extensive experience in the acquisition and development of power projects, larger staffs, and greater financial resources than EME. 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.

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. Over time, some of EME's merchant facilities may become obsolete in their markets, or be unable to compete, because of the construction of newer, more efficient power plants.

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 as a result of further consolidation of the power industry by mergers and asset reallocations, which could create larger competitors, as well as new market entrants. In addition, regulatory initiatives may result in changes in the power industry to which EME may not be able to respond in as timely and effective manner as its competitors.

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:

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

EME's operations are subject to extensive environmental regulations with respect to, among other things, air quality, water quality, waste disposal, and noise. 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 devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. EME believes that it is currently in substantial compliance with environmental regulatory requirements. However, the US EPA has issued NOVs alleging violations of the CAA and certain opacity and particulate matter standards at the Illinois Plants and the Homer City facilities. The current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. 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 NO_X and SO₂, mercury and particulates are subject to increased controls and mitigation expenses under current regulations and may be subject to new, possibly stricter, regulation in the future. The continued operation of EME's facilities, particularly its coal-fired facilities, is expected to require substantial capital expenditures for environmental controls.

Midwest Generation has entered into an agreement with the Illinois EPA to reduce mercury, NO_X and SO₂ emissions at the Illinois Plants. The agreement has been embodied in an Illinois rule called the CPS. All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. Capital expenditures relating to controls contemplated by the CPS could be significant. Midwest Generation may ultimately decide to comply with CPS requirements by shutting down units rather than making improvements. Midwest Generation is evaluating all technology and unit shutdown combinations, including interim compliance solutions, to determine the economic effects of compliance with the CPS and optimal methods of compliance. For more information about the CPS requirements and Midwest Generation's plans for compliance, see "Item 8. Financial Statements and Supplementary Data—Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12 Commitments and Contingencies—Environmental Matters and Regulations—Air Quality Regulation—Clean Air Interstate Rule—Illinois."

In addition, 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. 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. Furthermore, changing environmental regulations could make some units uneconomical to maintain or operate. If EME cannot comply 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.

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 or operational expenditures. EME cannot provide assurance that it will be able to obtain and comply with all necessary licenses, permits and approvals for its plants. If there is a delay in obtaining required approvals or permits or if EME fails to obtain and comply with such permits, the operation of EME's facilities may be interrupted or become subject to additional costs.

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.

The FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines that potential market power might exist and that the public interest requires mitigation. In addition, many of EME's facilities are subject to rules, restrictions and terms of participation imposed and administered by various RTOs and ISOs. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to facilitate market functions. Such actions may materially affect EME's results of operations.

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

As of December 31, 2008 EME's consolidated debt was $4.7 billion. In addition, EME's subsidiaries have $3.6 billion of long-term, power plant lease obligations that are due over a period ranging up to 26 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, to operate successfully under adverse economic conditions, or to plan for and react to business and industry changes. 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 (including environmental improvements required by the CPS, which could in turn lead to unit shutdowns), 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.

In addition, in connection with the entry into new financings or amendments to existing financing arrangements, EME's 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.

Restrictions in the instruments governing EME's indebtedness and the indebtedness and lease obligations of its subsidiaries limit EME's and its subsidiaries' ability to enter into specified transactions that EME or they otherwise may enter into.

The instruments governing EME's indebtedness and the indebtedness of its subsidiaries contain financial and investment covenants. Restrictions contained in these documents or documents EME or its subsidiaries enter in the future could affect, and in some cases significantly limit or prohibit, EME's ability and the ability of its subsidiaries 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 EME's ability and the ability of its subsidiaries to take advantage of business opportunities as they arise, to grow its business or to compete effectively. In addition, these restrictions may significantly impede the ability of EME's subsidiaries to make distributions to EME.

The creditworthiness of EME's customers, suppliers, transporters and other business partners could affect EME's business and operations.

EME is exposed to risks associated with the creditworthiness of its key customers, suppliers and business partners, many of whom may be adversely affected by the current conditions in the financial markets. Deterioration in the financial condition of EME's counterparties increases the possibility that EME may incur losses from the failure of counterparties to perform according to the terms of their contractual arrangements.

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

The accounting for EME's hedging and proprietary trading activities may increase the volatility of its quarterly and annual financial results.

EME engages in hedging activities in order to mitigate its exposure to market risk with respect to electricity sales from its generation facilities, fuel utilized by those facilities and emission allowances. EME generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. EME also uses derivative contracts with

respect to its limited proprietary trading activities, through which EME attempts to achieve incremental returns by transacting where it has specific market expertise. These derivative contracts are recorded on its balance sheet at fair value pursuant to SFAS No. 133. Some of these derivative contracts do not qualify under SFAS No. 133 for hedge accounting, and changes in their fair value are therefore recognized currently in earnings as unrealized gains or losses. As a result, EME's financial results will at times be volatile and subject to fluctuations in value primarily due to changes in electricity prices.

EME leases its principal office in Irvine, California. The office lease is currently for approximately 90,000 square feet and expires on December 31, 2010. EME also leases office space in Chicago, Illinois; Chantilly, Virginia; and Boston, Massachusetts. The Chicago lease is for approximately 53,000 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 41,000 square feet and expires on July 31, 2017.

The following table shows, as of December 31, 2008, 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.

On July 12, 2005, EMMT received a letter from the staff of the FERC Office of Enforcement (FERC Staff) stating that, by the letter, it was commencing a preliminary, non-public investigation of certain bidding practices of EMMT. In October 2006, EMMT was advised that the FERC Staff was prepared to recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged violation of the EPAct 2005 and the FERC's rules regarding market behavior, all with respect to certain bidding practices previously employed by EMMT.

In a settlement agreement approved by the FERC on May 19, 2008, EMMT, Midwest Generation, and EME acknowledged that during the course of the investigation, although they had no intent to mislead the FERC Staff, they had at times failed to provide complete and accurate information in response to FERC Staff inquiries, as required by FERC's regulation (18 CFR § 35.41(b) (2007)). The settlement agreement required the payment of $7 million in civil penalties for violation of 18 CFR §

35.41(b) (2007) and development and implementation of a comprehensive regulatory compliance program at an estimated cost of $2 million. The order and settlement agreement operate to terminate the investigation with no assertion of findings of violation of FERC's rules with respect to the bidding practices that were the subject of the investigation.

On June 18 and 19, 2008, various parties, including the Attorney General of the State of Illinois and a number of state regulatory agencies, filed various motions and protests seeking to intervene in the FERC investigation docket for the purpose of seeking clarification that the order and settlement agreement did not foreclose third party rights to seek redress against EMMT, Midwest Generation and EME for any alleged market manipulation as a result of the bidding behavior or, in the alternative, obtaining an order reopening the investigation docket to allow further investigation into the bidding behavior. On October 7, 2008, the FERC issued an order denying the motions to intervene and dismissing the requests for rehearing and other relief. On December 8, 2008, the FERC denied the intervening parties' further requests for rehearing.

Also on December 8, 2008, two of the intervening parties filed an appeal with the United States Court of Appeals for the District of Columbia Circuit, appealing the FERC's October 7, 2008 order denying intervention. The appellate case is pending and the outcome cannot be determined at this time.

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990's and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations or financial position.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the CAA. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. EME Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME Homer City cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.

EME Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.

EME Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, have sought indemnification and defense from EME Homer City for costs and liability associated with the EME Homer City NOV. EME Homer City responded by undertaking the indemnity obligation and defense of the claims.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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 are paid when declared by EME's board of directors. EME did not pay or declare any dividends during 2008. EME made cash dividend payments totaling $925 million in 2007 and $51 million in 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 in EME's corporate credit facility.

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. In April 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. These projects were previously owned by EME's affiliate, Edison Capital. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control for a net book value of approximately $76 million. The historical consolidated financial and operating results data reflects the acquisition as though EME had ownership of such projects for all periods presented.

		Years Ended December 31,

		2008			2007			2006			2005			2004
		(in millions)
INCOME STATEMENT DATA
Operating revenues		$	2,811		$	2,580		$	2,239		$	2,265		$	1,653
Operating expenses
	Fuel, plant operations and plant operating lease		1,544			1,444			1,332			1,287			1,300
	Gain on buyout of contract, loss on contract and lease termination, asset impairment and other charges and credits(1)		14			1			—			7			989
	Depreciation and amortization		194			162			144			134			152
	Administrative and general		207			209			140			154			149

			1,959			1,816			1,616			1,582			2,590

Operating income (loss)			852			764			623			683			(937	)
Equity in income from unconsolidated affiliates			122			200			186			229			218
Impairment loss on equity method investment			—			—			—			(55	)		—
Interest and other income			48			103			120			69			52
Interest expense			(279	)		(273	)		(279	)		(300	)		(298	)
Loss on early extinguishment of debt			—			(160	)		(146	)		(4	)		—

Income (loss) from continuing operations before income taxes and minority interest			743			634			504			622			(965	)
Provision (benefit) for income taxes			243			219			189			208			(406	)
Minority interest			—			1			1			—			(1	)

Income (loss) from continuing operations			500			416			316			414			(560	)
Income (loss) from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004), net of tax			1			(2	)		98			29			690

Income before accounting change			501			414			414			443			130
Cumulative effect of change in accounting, net of tax(2)			—			—			—			(1	)		—

Net income		$	501		$	414		$	414		$	442		$	130

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

This 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 "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.

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 full or partial interests 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, 2008, EME's subsidiaries and affiliates owned or leased interests in 37 operating projects and three wind projects under construction. Since EME as a holding company does not 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, and to pay for general and administrative expenses. Distributions to EME from projects are subject to approval of the applicable entities' governing bodies and are generally only available after all obligations, including debt service if applicable, at the project level have been paid. In addition, to the extent there is project level debt, distributions may be restricted by contractual limitations included in such project level debt obligations. For further information on distributions to EME, see "Liquidity and Capital Resources—EME's Liquidity as Holding Company."

EME is in a capital intensive business and depends on access to the financial markets to fund capital expenditures, meet contractual obligations and support margin and collateral requirements. EME has expanded its business development activities to grow and diversify its existing portfolio of power projects, including building new power plants. In addition, EME has environmental compliance requirements, discussed below, as well as ongoing capital expenditures for its existing generation fleet. All of these activities require liquidity and access to capital markets at reasonable rates in the future. For further discussion, see "Liquidity and Capital Resources—Business Development" and "Liquidity and Capital Resources—Capital Expenditures."

EME and its subsidiary, Midwest Generation, made borrowings under their respective credit agreements during 2008 to improve liquidity and protect against uncertainty resulting from the status of the financial markets. Proceeds from these borrowings were invested in U.S. Treasury securities, U.S. government agency securities and money market funds invested directly in U.S. Treasury securities and U.S. government agency securities. At December 31, 2008, EME had consolidated cash and cash equivalents and short-term investments of $1.8 billion. Although EME does not have any material debt obligations that mature until 2012, EME's projected capital expenditures require liquidity and access to capital markets in the future.

Disruptions in the capital markets affected in 2008, and may continue to affect, EME's ability to finance already-developed wind projects and future commitments and projects, including significant outstanding capital commitments for wind turbines. Furthermore, these disruptions may affect how EME addresses its commitments with respect to environmental compliance, as discussed below. As a result, pending recovery of the capital markets, EME intends to preserve capital by focusing on a selective growth strategy (primarily completion of projects under construction, including the Big Sky wind project in Illinois, and development of sites for future renewable projects deploying current turbine commitments), and using its cash and future cash flow to meet its existing contractual commitments. Depending upon financing conditions, EME may elect to postpone and/or cancel wind turbine commitments, subject to the provisions of the relevant contracts. Moreover, disruption in the financial markets appears to have reduced trading activity in power markets which may affect the level and duration of future hedging activity and potentially increase the volatility of earnings. Long-term disruption in the capital markets could adversely affect EME's business plans and financial position.

The market price for merchant energy in PJM increased significantly during the first half of 2008 and then decreased significantly in the second half of the year. The average 24-hour PJM market price for energy per MWh at the Northern Illinois Hub and Homer City busbar was higher in 2008 as compared to 2007 by 7.6% and 13.1%, respectively. However, since June 30, 2008, forward energy prices in PJM have decreased substantially driven by lower natural gas prices and the financial market developments discussed above. At December 31, 2008, forward energy market prices for 2009 for the Northern Illinois Hub and PJM West Hub have decreased by 38% and 42%, respectively, since June 30, 2008. At the same time, the average cost of fuel per MWh increased in 2008 by 16% at Midwest

Generation and 4% at EME Homer City. At December 31, 2008, Midwest Generation and EME Homer City had contracted for substantially all of their coal requirements for 2009. Unless these energy prices change, energy gross margins for unhedged volumes from Midwest Generation and EME Homer City will decrease from 2008. See "Market Risk Exposures—Commodity Price Risk" for further discussion.

President Obama signed the American Recovery and Reinvestment Act of 2009 into law on February 17, 2009. The law contains direct spending measures of approximately $500 billion and tax cuts of approximately $280 billion. The Act provides production tax credits for a ten-year period for new wind projects placed in service prior to December 31, 2012 and provides that, in lieu of the production tax credit, renewable developers may make an election to claim either a 30% investment tax credit or a grant for a 30% reimbursement of expenses associated with specified energy property. The Act also contains a one-year extension of the 50% bonus depreciation.

The content of potential climate change regulation in the future remains uncertain. While debate continues at the national level over domestic climate policy and the appropriate scope and terms of any federal legislation, many states are developing state-specific measures or participating in regional legislative initiatives to reduce GHG emissions. State and regional regulations may vary and may be more stringent and costly than federal legislative proposals currently being debated in the U.S. Congress. Key uncertainties include whether a cap-and-trade program will be implemented similar to the US EPA Acid Rain Program, and, if implemented, whether emission allowances would be provided to affected parties without cost for a period of time. In the absence of legislation, it is also possible that CO₂ will be regulated by the US EPA pursuant to authority granted under the CAA in its current form. Furthermore, the rate of decrease in GHG emissions and the cost to purchase allowances would be significant factors in determining whether environmental controls for other emissions would be economic to install. Programs to reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels as well as the cost of purchased power. The potential impact on EME will depend upon how the factors discussed above and many other considerations are resolved.

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NO_X and SO₂ emissions at the Illinois Plants. The agreement has been embodied in an Illinois rule called the CPS. All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS.

Under the CPS, Midwest Generation is required to achieve specific lower emission rates by specified dates. Midwest Generation has not decided upon a particular combination of retrofits to meet the required step down in emission rates. Midwest Generation continues to review alternatives, including interim compliance solutions. The CPS also specifies that specific control technologies are to be installed on some units by specified dates. In these cases, Midwest Generation must either install the required technology by the specified deadline or shut down the unit.

Midwest Generation is in the process of completing engineering work for the potential installation of SCR equipment on Units 5 and 6 at the Powerton Station and SNCR equipment on Unit 6 at the Joliet Station. The SCR equipment at the Powerton Station is currently estimated to cost $500 million, and the

SNCR equipment on Unit 6 at the Joliet Station is currently estimated to cost $13 million (both figures are in 2008 dollars). This technology combination represents one possible compliance plan for the NO_X emission rates. Midwest Generation is evaluating other potential solutions that are less costly to meet the NO_X emissions rate that combine the use of alternative NO_X removal technologies with certain unit shutdowns.

The engineering work at the Powerton Station also includes the potential installation of FGD equipment on Units 5 and 6, and Midwest Generation currently estimates approximately $1 billion (in 2008 dollars) of capital expenditures would be required for the FGD equipment at the Powerton Station. Midwest Generation also determined these capital expenditures could be reduced if the construction work sequence of FGD and SCR at the Powerton Station were reversed. The complexity of the Powerton Station installation and construction interferences are representative of the balance of the fleet and Midwest Generation currently estimates approximately $650/kW for any FGD installation it elects to make on other units.

A decision to make these improvements has not been made. Midwest Generation is still evaluating all technology and unit shutdown combinations, including interim and alternative compliance solutions. For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Environmental Matters and Regulations."

On October 26, 2007, the Illinois EPA filed a proposed rule with the Illinois PCB that would establish more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River. Midwest Generation's Fisk, Crawford and Will County Stations all use water from the Chicago Area Waterway System and its Joliet Station uses water from the Lower Des Plaines River for cooling purposes. The rule, if implemented, is expected to affect the manner in which those stations use water for station cooling.

The proposed rule is the subject of an administrative proceeding before the Illinois PCB and must be approved by the Illinois PCB and the Illinois Joint Committee on Administrative Rules. Following state adoption and approval, the US EPA also must approve the rule. Hearings began on January 28, 2008, and are continuing in 2009. Midwest Generation is a party in those proceedings. At this time, it is not possible to predict the timing for resolution of the proceeding, the final form of the rule, or how it would impact the operation of the affected stations; however, significant capital expenditures may be required depending on the form of the final rule. In addition, the outcome of these proceedings may affect Midwest Generation's plans for compliance with the CPS discussed above.

As a result of the financial markets and economic condition discussed above, EME intends to focus on a more selective growth strategy as described above. At December 31, 2008, EME had 962 MW of wind projects in service and three wind projects under construction with an EME pro rata share of 223 MW, with scheduled completion dates during 2009. EME's wind projects under construction are currently funded through equity. EME has contracts for the purchase of 942 MW of new turbines with scheduled payment obligations of up to $706 million in 2009 and $232 million in 2010. EME plans to use a portion of these turbines to complete a 240 MW planned wind project in Illinois, referred to as the Big Sky wind project. EME plans to use the remaining turbines to support construction of new projects, subject to meeting investment criteria and availability of financing.

EME's 2008 increase in income from continuing operations was primarily due to a $98 million, after tax, loss on early extinguishment of debt recorded in 2007, higher operating income at the Illinois Plants, new wind projects in operation in 2008, and higher energy trading income. These increases were partially offset by lower income from the Big 4 projects and Homer City facilities, loss on termination of a gas turbine supply agreement, and lower interest income.

EME's 2007 increase in income from continuing operations was primarily due to higher operating income at the Illinois Plants and Homer City facilities and higher energy trading income, partially offset by higher development and other corporate costs. EME's 2007 income from continuing operations included a $98 million, after tax, loss on early extinguishment of debt.

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.

EME uses derivative financial instruments for hedging activities and trading purposes. Derivative financial instruments are mainly utilized by EME to manage exposure from changes in electricity and fuel prices and interest rates. EME follows 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. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings. For further discussion, see "Market Risk Exposures—Accounting for Energy Contracts."

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, 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 operating revenues in the accompanying consolidated income statements in the period of change. Derivative assets 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. Derivative liabilities 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 policy 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 hedging and trading activities with a right of setoff in the event of bankruptcy or default by the counterparty. These types of transactions are reported net in the balance sheet.

EME follows SFAS No. 157 which established a framework for measuring fair value. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date (referred to as an "exit price" in SFAS No. 157). EME's assets and liabilities carried at fair value primarily consist of derivative contracts and money market funds. Derivative contracts primarily relate to power and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange traded, over-the-counter traded or structured transactions.

EME makes estimates and significant judgments in order to determine the fair value of an instrument including those related to quoted market prices, time value of money, volatility of the underlying commodities, non-performance risks and other factors. If quoted market prices are not available, internally maintained models are used to determine the fair value. Under SFAS No. 157, when actual market prices, or relevant observable inputs are not available it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid and non-liquid trading hubs. In assessing non-performance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of non-performance.

In addition, SFAS No. 157 established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest

priority to unobservable inputs (Level 3 measurements). See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Fair Value Measurements" for further information.

Level 3 includes primarily derivatives that trade infrequently (such as financial transmission rights and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant non-performance risks and long-term power agreements. For illiquid financial transmission rights, EME reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when EME concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where EME cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

EME follows 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 policy 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. The expected future undiscounted cash flow from EME's assets or group of assets is a critical accounting policy because: (1) estimates of future prices of energy and capacity in wholesale energy markets and fuel prices are susceptible to significant change, (2) uncertainties exist regarding the impact of existing and future environmental regulations, (3) the period of the forecast is over an extended period of time due to the length of the estimated remaining useful lives, and (4) the impact of an impairment on EME's consolidated financial position and results of operations would be material.

Midwest Generation has regulatory requirements in Illinois to reduce SO₂ and NO_X emissions to target rates and to install specific environmental control equipment by specific dates for each coal unit (except Unit 6 at Joliet Station) or it would be required to shut down the specified coal unit. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Environmental Matters and Regulations" for further discussion regarding the CPS. No decision has been made to make such capital improvements. The decision to make capital improvements is dependent on a number of factors affecting the economic analysis and potential impact of further environmental regulations. If EME were to decide not to install additional environmental control equipment and, instead, shut down an entire plant by the date required, the remaining estimated useful life of the plant would be shortened (thereby increasing the annual depreciation expense). The change in estimated useful life could trigger an impairment. If the

undiscounted expected cash flow measured at a plant level were less than the net book value of the asset group, an impairment would be recognized. EME includes allocated acquired emission allowances as part of the asset group under SFAS No. 144. In the case of the Powerton and Joliet Stations, EME also includes prepaid rent in the asset group. EME's unit of account is at the plant level and, accordingly, the closure of a unit at a multi-unit site would not result in an impairment of property, plant and equipment unless such condition were to affect an impairment assessment on the entire plant.

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—Contractual Obligations—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 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 recognition of 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."

In accordance with SFAS No. 5, "Accounting for Contingencies," EME records loss contingencies when it determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. These reserves are based on management judgment and estimates taking into consideration available information and are adjusted when events or circumstances cause these judgments or estimates to change. EME provides disclosure for contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred. Gain contingencies are recognized in the financial statements when they are realized. Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenue and expenses recorded on the consolidated financial statements. See "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Contingencies," and "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Environmental Matters and Regulations" for a discussion of contingencies and regulatory issues, respectively.

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. At December 31, 2008, EME had recorded an estimated liability of $95 million (of which $51 million is classified as a current liability) related to these matters.

In addition, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related 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—Indemnity Provided as Part of the Acquisition of the Illinois Plants." The estimated liability is based on studies that estimate future losses based on claims experience and other available information. In calculating future losses, various assumptions were made, 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 2044. At December 31, 2008, Midwest Generation had recorded a liability of $52 million related to this contract indemnity.

SFAS No. 109, "Accounting for Income Taxes," 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. FIN No. 48 clarified the accounting for uncertain tax positions. FIN No. 48 (adopted on January 1, 2007) requires an enterprise 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. Management continues to monitor and assess new income tax developments. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Income Taxes" 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 accrued liabilities or other long-term liabilities in the consolidated balance sheet. Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Accounting for tax obligations requires judgments, including estimating reserves for potential adverse outcomes regarding tax positions that have been taken. Management uses judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit.

For additional information regarding EME's accounting policies, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

This section discusses operating results in 2008, 2007 and 2006. EME's continuing operations primarily include the Illinois Plants and Homer City facilities, energy trading, gas-fired and wind-powered projects under contract, corporate interest expense and general and administrative expenses. EME's discontinued operations include all international operations, except the Doga project. This section also discusses the effect of new accounting pronouncements on EME's consolidated financial statements.

EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the Illinois Plants and the Homer City facilities. Equity in income from unconsolidated affiliates primarily 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 adjusted operating income (loss) as described below.

The following section and table provides a summary of results of EME's operating projects and corporate expenses for the three years ended December 31, 2008, together with discussions of the contributions by specific projects and of other significant factors affecting these results. EME has modified its internal reporting of project profitability using a new performance measure entitled adjusted operating income. Previously, EME used pre-tax income adjusted for production tax credits to measure the profitability of projects. The change in measurement to adjusted operating income was made to improve the comparison of performance excluding financing costs which may be at different entities throughout the corporate hierarchy, but do not affect the operating profitability of a project.

	Years Ended December 31,

	2008			2007			2006
	(in millions)
Illinois Plants	$	688		$	583		$	463
Homer City		202			221			150
Renewable energy projects		59			30			19
Energy trading		164			142			130
Big 4 projects		87			147			136
Sunrise		24			33			34
Westside projects		9			11			11
Doga		8			14			—
Other non-wind projects		14			14			6
Other		(31	)		(7	)		11

		1,224			1,188			960
Corporate administrative and general		(172	)		(169	)		(108	)
Corporate depreciation and amortization		(12	)		(8	)		(4	)

Adjusted Operating Income(1)	$	1,040		$	1,011		$	848

The following table reconciles adjusted operating income to operating income as reflected on EME's consolidated statements of income:

			Years Ended December 31

			2008			2007			2006
			(in millions)
Operating Revenues			$	1,778		$	1,579		$	1,399
Operating Expenses
	Fuel(1)			482			400			382
	Gain on sale of emission allowances(2)			(3	)		(18	)		(16	)
	Plant operations			434			420			369
	Plant operating leases			75			75			75
	Depreciation and amortization			106			99			101
	(Gain) on buyout of contract and (gain) loss on sale of assets			(16	)		—			4
	Administrative and general			22			22			19

	Total operating expenses			1,100			998			934

Operating Income				678			581			465

Other Income (Expense)				10			2			(2	)

Adjusted Operating Income(3)			$	688		$	583		$	463

Statistics
	Generation (in GWh):
		Energy only contracts		26,010			22,503			28,898
		Load requirements services contracts(4)		5,090			7,458			—

		Total		31,100			29,961			28,898

	Aggregate plant performance:
		Equivalent availability(5)		81.0%			75.8%			79.3%
		Capacity factor(6)		64.8%			60.9%			58.8%
		Load factor(7)		80.0%			80.4%			74.1%
		Forced outage rate(8)		8.3%			9.7%			7.9%
	Average realized price/MWh:
		Energy only contracts(9)	$	51.82		$	48.79		$	46.19
		Load requirements services contracts(10)	$	62.64		$	63.43		$	—
	Capacity revenue only (in millions)		$	111		$	27		$	24
	Average fuel costs/MWh		$	15.49		$	13.36		$	13.19

Earnings from the Illinois Plants increased $105 million in 2008 compared to 2007, and $120 million in 2007 compared to 2006. The 2008 increase in earnings was primarily attributable to higher realized gross margin, an increase in unrealized gains related to hedge contracts (described below) and a $15 million gain recorded during the first quarter of 2008 related to a buyout of a fuel contract. See "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Purchase Obligations—Fuel Supply Contracts" for further discussion. The increase in realized gross margin was due to an increase in capacity prices as a result of the PJM RPM auction. The increase in generation and slightly higher average realized energy prices was partially offset by higher coal and transportation costs. The 2008 increase in earnings was also partially offset by a $24 million charge related to power contracts due to the bankruptcy of Lehman Brothers Holdings described below.

Two factors are expected to increase operating expenses by approximately $90 million to $105 million during 2009 as compared to 2008:

The 2007 increase in earnings was primarily attributable to higher energy revenues resulting from higher average realized energy prices and slightly higher generation as compared to 2006. Partially offsetting these increases were higher planned maintenance costs, unplanned outages at the Powerton Station and a $7.5 million payment during the third quarter of 2007 related to the settlement agreement with the Illinois Attorney General. Earnings were also adversely affected by an increase in unrealized losses in 2007 related to power contracts described below.

Included in operating revenues were unrealized gains (losses) of $(6) million, $(25) million and $30 million in 2008, 2007 and 2006, respectively. In 2008, unrealized losses included $24 million from power contracts for 2009 and 2010 with Lehman Brothers Commodity Services, Inc. These contracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the contracts due to non-performance risk and subsequently terminated the contracts. The change in fair value was recorded as an unrealized loss during 2008. Unrealized gains (losses) were also attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133 and power contracts that did not qualify for hedge accounting under SFAS No. 133 (sometimes referred to as economic hedges). These energy contracts were entered into to hedge the price risk related to projected sales of power. During 2007, power prices increased, resulting in mark-to-market losses on economic hedges. See "Market Risk Exposures—Commodity Price Risk" and "Market Risk Exposures—Accounting for Energy Contracts" for more information regarding forward market prices and the write-off of the power contracts, respectively.

On December 18, 2007, Unit 6 at the Powerton Station had a duct failure resulting in a suspension of operations at this unit through February 12, 2008. Scheduled maintenance work for the spring of 2008 was accelerated to minimize the aggregate impact of the outage. The duct failure resulted in claims under Midwest Generation's property and business interruption insurance policies. During the first quarter of 2008, $6 million related to business interruption insurance coverage was recorded primarily related to these claims reflected in other income (expense), net on EME's consolidated statements of income. At December 31, 2008, Midwest Generation had a $4 million receivable recorded related to these claims.

		Years Ended December 31,

		2008		2007		2006
		(in millions)
Operating Revenues		$	717	$	764	$	642
Operating Expenses
	Fuel(1)		270		306		283
	Gain on sale of emission allowances(2)		—		—		(7	)
	Plant operations		126		119		106
	Plant operating leases		102		102		102
	Depreciation and amortization		16		14		16
	Administrative and general		4		4		5

	Total operating expenses		518		545		505

Operating Income			199		219		137

Other Income			3		2		13

Adjusted Operating Income(3)		$	202	$	221	$	150

Statistics
	Generation (in GWh)		11,334		13,649		12,286
	Equivalent availability(4)		80.7%		89.4%		81.9%
	Capacity factor(5)		68.3%		82.5%		74.3%
	Load factor(6)		84.6%		92.4%		90.7%
	Forced outage rate(7)		9.8%		4.1%		13.5%
	Average realized energy price/MWh(8)	$	56.24	$	54.40	$	48.02
	Capacity revenue only (in millions)	$	46	$	30	$	16
	Average fuel costs/MWh	$	23.35	$	22.45	$	23.05

Earnings from Homer City decreased $19 million in 2008 compared to 2007 and increased $71 million in 2007 compared to 2006. The 2008 decrease in earnings was primarily attributable to lower realized gross margin and higher plant maintenance expenses, partially offset by an increase in unrealized gains related to hedge contracts (described below). The decline in realized gross margin was primarily due to lower generation from higher forced outages, lower off-peak dispatch and extended planned overhauls in 2008, partially offset by an increase in capacity revenues and the sale of excess coal inventory. Included in fuel costs were $19 million, $31 million and $35 million in 2008, 2007 and 2006, 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 2007 increase in earnings was primarily attributable to an increase in energy revenues from higher generation and average realized energy prices, and an increase in capacity revenues resulting from the PJM RPM auction. Partially offsetting these increases were higher maintenance costs in 2007 related to the planned outage at Unit 2 of the Homer City facilities and lower other income in 2007 for the estimated insurance recovery related to the Unit 3 outage of approximately $3 million recorded during the third quarter of 2007, compared to approximately $11 million recorded during the second quarter of 2006, reflected in other income (expense), net on EME's consolidated statements of income. Earnings for 2007 were also adversely affected due to the timing of unrealized gains and losses related to hedge contracts discussed below.

Included in operating revenues were unrealized gains (losses) from hedge activities of $21 million, $(10) million and $35 million in 2008, 2007 and 2006, respectively. Unrealized gains (losses) 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. The ineffective portion of hedge contracts at Homer City was primarily attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). See "Market Risk Exposures—Commodity Price Risk" and "Market Risk Exposures—Accounting for Energy Contracts" for more information regarding forward market prices and unrealized gains (losses), respectively.

The average realized energy price received by Homer City in 2008, 2007 and 2006 was $56.24/MWh, $54.40/MWh and $48.02/MWh, respectively, compared to the average real-time market price at the Homer City busbar for the same periods of $57.72/MWh, $51.03/MWh and $45.15/MWh, respectively. The average realized energy price for the twelve months ended December 31, 2008 was below the 24-hour PJM average market price at the Homer City busbar primarily due to effective hedge prices being below market prices for the same period. Homer City's average realized energy price varies from the average real-time market price due to: (1) hedge contracts having been entered into in prior periods, (2) differences between market prices during periods of actual generation (generally weighted to on-peak periods) and the 24-hour average real-time market prices, and (3) changes in the differential in market prices at the PJM West Hub 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" and "Market Risk Exposures—Accounting for Energy Contracts."

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the Illinois Plants and the Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinois Plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. See "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants" and "—Energy Price Risk Affecting Sales from the Homer City Facilities" for further discussion regarding market prices.

The following table presents additional data for EME's renewable energy projects:

			Years Ended December 31,

			2008		2007		2006
			(in millions)
Operating Revenues			$	108	$	51	$	30
Production Tax Credits				44		29		16

				152		80		46

Operating Expenses
		Plant operations		35		18		12
		Depreciation and amortization		59		34		20
		Administrative and general		2		1		—

		Total operating expenses		96		53		32

Other Income				3		3		5

Adjusted Operating Income(1)			$	59	$	30	$	19

Statistics
	Generation (in GWh)			2,286		1,533		897
	Aggregate plant performance:
		Equivalent availability		80.4%		85.5%		96.1%
		Capacity factor		33.1%		37.8%		34.1%

EME has significantly expanded its renewable energy project portfolio during the past three years. EME's share of installed capacity of new wind projects that commenced operations during 2008 and 2007 was 396 MW and 292 MW, respectively. New projects that commenced operations were the primary drivers for increases in the revenues and operating costs and adjusted operating income.

EME's operating wind projects include 189 turbines manufactured by Suzlon Wind Energy Corporation (Suzlon). Rotor blade cracks were identified on certain of the Suzlon Model S88 wind turbines using V-2 blades, and Suzlon has advised EME that such cracks have also appeared on turbines with another Suzlon customer. Suzlon, with review and oversight from EME's technical experts, has completed its analysis and blade testing to determine the root cause of the blade crack issues and a remediation plan is being implemented. To address the commercial impact of these issues on EME and its projects, during the second quarter of 2008, EME signed an agreement with Suzlon providing EME with enhanced warranty and credit protections with respect to the Suzlon turbine issues including the rotor blade crack issues. The availability and capacity factors were adversely affected due to performance issues with the Suzlon turbines. However, under the terms of the turbine supply agreements, Suzlon has agreed to provide liquidated damages for unavailability of turbines. Revenues recognized for liquidated damages were $28 million in 2008 (of which $4 million related to 2007 generation).

In addition to the Suzlon turbines, EME has purchased 71 turbines from Clipper Turbine Works, Inc. (Clipper) of which 20 turbines are in service at the Jeffers wind project and 40 turbines are planned for the High Lonesome wind project currently under construction. EME recently learned that problems have been discovered in the blades on certain Clipper wind turbines. Root cause analysis to date has determined the blade problems resulted from a manufacturing defect. During the fourth quarter of 2008, EME signed an agreement with Clipper addressing procedures for remediation, enhanced warranties, and other protections with respect to the blades planned for the High Lonesome wind project. EME and Clipper are currently discussing a similar agreement with respect to the blades in service at the Jeffers project. EME expects to continue to work with Clipper to review the root cause analysis of the blade problems and necessary corrective actions, and to address commercial matters that result from the impact of these issues on its projects.

EME seeks to generate profit by utilizing 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 congestion primarily in the eastern power grid using products available over the counter, through exchanges, and from ISOs. Earnings from energy trading activities were $164 million, $142 million and $130 million in 2008, 2007 and 2006, respectively. The 2008 increase in earnings from energy trading activities was primarily attributable to increased congestion and market volatility in key markets and gains from the Maryland contracts described below. The 2007 increase in earnings from energy trading activities was primarily attributable to increased congestion and market volatility in key markets and higher earnings from energy trading in the over-the-counter markets.

In April 2008, EMMT entered into three load services requirements contracts in Maryland with local utilities. Under the terms of the load services requirements contracts, EMMT is obligated to supply a portion of each utility's load at fixed prices that vary based on periods specified in the contracts. EMMT is obligated to pay for the cost of supply at each utility's load zones including, energy, capacity, ancillary services and renewable energy credits. The estimated load for the period of January 1, 2009 through September 30, 2010 is approximately 3.9 million MWh. EMMT has entered into futures contracts to substantially hedge the energy price risk related to these contracts. The above contracts are recorded as derivatives with the change in fair value reflected in trading income above.

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 were used, collectively, to secure financing by Edison Mission Energy Funding Corp., a special purpose entity. The Edison Mission Energy Funding Corp. financing was paid in full in September 2008. Due to similar economic characteristics, EME evaluates these projects collectively and refers to them as the Big 4 projects.

Earnings from the Big 4 projects decreased $60 million in 2008 compared to 2007, and increased $11 million in 2007 compared to 2006. The 2008 decrease in earnings was primarily due to $60 million in lower earnings from the Sycamore and Watson projects as a result of lower pricing in 2008 than previously applied under a long-term power sales agreement that expired. For further discussion regarding power sales from the Sycamore and Watson projects and a description of the dispute between SCE and Watson, see "Item 1. Business—Overview of Facilities—Contracted Power Plants-Domestic—Natural Gas—Big 4 Projects."

The 2007 change in earnings was primarily due to payments received in settlement of claims related to the natural gas purchase contracts during the second quarter of 2007 and outages at the Sycamore Cogeneration plant in 2006. Partially offsetting these increases were lower volumes sold in 2007 for the Kern River project.

The power sales agreement of the Midway-Sunset project is scheduled to expire in May 2009. Thereafter, Midway-Sunset expects to continue selling electricity either pursuant to a new power sales agreement or to SCE under the terms and conditions contained in its prior long-term power sales agreement, with revised pricing terms as mandated by the California Public Utilities Commission. The revised pricing terms are lower than the prices in the expiring power sales agreement. Furthermore, earnings for the Watson and Sycamore projects are expected to decrease in 2009 from 2008, due primarily to lower projected energy prices and volumes. Additionally, projected steam purchased from the hosts for the Sycamore and Midway-Sunset projects are expected to be lower in 2009. As a result of these factors, pre-tax earnings from the Big 4 projects are expected to decrease by approximately $45 million to $55 million during 2009.

Earnings from the Sunrise project decreased $9 million in 2008 from 2007 and $1 million in 2007 from 2006. The 2008 decrease was primarily due to lower availability incentive payments in 2008 and higher maintenance expenses due to unplanned outages in 2008. The 2007 decrease was primarily due to lower availability incentive payments partially offset by lower interest expense in 2007.

Earnings from the Doga project decreased $6 million in 2008 compared to 2007 and increased $14 million in 2007 compared to 2006. Effective March 31, 2007, EME accounted for its ownership in the Doga project on the cost method (earnings are recognized when cash is distributed from the project). Earnings from Doga were higher in 2007 when EME's investment was fully recovered and earnings were recognized based on distributions received from the Doga project. Earnings from Doga during 2006 were adversely impacted by a change in Turkish corporate tax rates which reduced deferred tax assets (related to levelization of income from the power purchase agreement for financial reporting purposes).

Other non-wind projects increased $8 million in 2007 from 2006. The 2007 increase was primarily attributable to the improvement in the performance of EME's gas transportation agreement resulting from increased gas supply in the Rocky Mountain region which increased the market price of gas transportation into California.

Other decreased $24 million in 2008 from 2007 and $18 million in 2007 from 2006. The 2008 decrease primarily resulted from a charge of $23 million related to the termination of a turbine supply agreement in connection with the Walnut Creek project. The 2007 decrease is partially attributable to a write-down of capitalized costs related to U.S. Wind Force. These amounts are reflected in "Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits" on EME's consolidated statements of income. In addition, in 2006, EME recorded an $8 million gain related to receipt of shares from Mirant Corporation from a settlement of a claim recorded during the first quarter of 2006 reflected in other income (expense), net on EME's consolidated statements of income.

Corporate administrative and general expenses increased $3 million in 2008 from 2007 and $61 million in 2007 from 2006. The 2007 increase was primarily due to higher development costs incurred in 2007 (mostly related to wind projects), higher corporate expenses and a loss accrual related to legal proceedings recorded in the third quarter of 2007.

Interest income decreased $59 million in 2008 from 2007 and $12 million in 2007 from 2006. The 2008 decrease was primarily attributable to lower interest rates in 2008 compared to 2007 and lower average cash equivalents and short-term investment balances. The 2007 decrease was primarily attributable to lower average cash balances in 2007 compared to 2006.

EME's interest expense to third parties, before capitalized interest, increased $14 million in 2008 from 2007 and $10 million in 2007 from 2006. The increases primarily resulted from EME's refinancing activities in May 2007. Capitalized interest increased $8 million in 2008 compared to 2007 and $16 million in 2007 compared to 2006. The increases were primarily due to wind projects under construction.

Loss on early extinguishment of debt was $160 million in 2007 related to the early repayment of EME's 7.73% senior notes due June 15, 2009 and Midwest Generation's 8.75% second priority senior secured notes due May 1, 2034.

Loss on early extinguishment of debt was $146 million in 2006 related to the early repayment of all EME's 10% senior notes due August 15, 2008 and 9.875% senior notes due April 15, 2011.

EME's income tax provision from continuing operations was $243 million in 2008, $219 million in 2007 and $189 million in 2006. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." EME recognized $44 million, $29 million and $16 million of production tax credits related to wind projects for the years ended December 31, 2008, 2007 and 2006, respectively, and $5 million, $10 million and $14 million for each period related

to estimated state income tax benefits allocated from Edison International. For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Income Taxes."

Income (loss) from discontinued operations, net of tax, was $1 million in 2008, $(2) million in 2007 and $98 million in 2006. The 2008 increase was due to adjustments for foreign exchange gains partially offset by interest expense associated with contract indemnities related to EME's sale of international projects in December 2004.

The 2007 decrease was largely attributable to distributions received from the Lakeland project, discussed below.

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 the project's 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) in 2005. EME was entitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claims were settled, EME received payments of £0.4 million (approximately $1 million) in 2008, £5 million (approximately $10 million) in 2007, and £72 million (approximately $125 million) in 2006. The after-tax income attributable to the Lakeland project was $1 million, $6 million and $85 million for 2008, 2007 and 2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounted for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

Specified EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to SCE and others under the terms of long-term power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $686 million, $747 million and $756 million in 2008, 2007 and 2006, respectively.

New accounting pronouncements are discussed in Note 1—Summary of Significant Accounting Policies—New Accounting Pronouncements under "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements."

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

At December 31, 2008, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.8 billion, EME had a total of $59 million of available borrowing capacity under its $600 million corporate credit facility, and Midwest Generation had a total of $22 million of available borrowing capacity under its $500 million working capital facility. EME's consolidated debt at December 31, 2008 was $4.7 billion. In addition, EME's subsidiaries had $3.6 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 26 years.

The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2008:

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Commercial Paper Inc., a lender in EME's credit agreement representing a commitment of $36 million, in September 2008 declined requests for funding under that agreement and in October 2008, filed for bankruptcy protection. Another subsidiary of Lehman Brothers Holdings, Lehman Brothers Commercial Bank, Inc., is one of the lenders in the Midwest Generation working capital facility. This subsidiary fully funded $42 million of Midwest Generation's borrowing requests, which remains outstanding. At December 31, 2008, Lehman Brothers

Commercial Bank's share of the amount available to draw under the Midwest Generation working capital facility was $2 million.

Disruptions in the capital markets affected in 2008, and may continue to affect, EME's ability to finance already-developed wind projects and future commitments and projects, including significant outstanding capital commitments for wind turbines. Access to the capital markets has become subject to increased uncertainty due to the financial market and economic conditions discussed in "Management's Overview; Critical Accounting Policies and Estimates—Management's Overview." Accordingly, EME's liquidity is currently comprised of cash on hand and cash flow generated from operations. Pending recovery of the capital markets, EME intends to preserve capital by focusing on a selective growth strategy (primarily completion of projects under construction, including the Big Sky wind project in Illinois, and development of projects deploying current turbine commitments), and using its cash and future cash flow to meet its existing contractual commitments. Moreover, disruption in the financial markets appears to have reduced trading activity in power markets which may affect the level and duration of future hedging activity and potentially increase the volatility of earnings. Long-term disruption in the capital markets could adversely affect EME's business plans and financial position.

EME has undertaken a number of activities in 2008 with respect to wind projects, including the following:

In addition, EME submitted bids in competitive solicitations to supply power from solar projects under development in the southwestern United States. Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission interconnection, site control, and construction costs estimates, and to negotiate power sales agreements. To support development activities, EME entered into an agreement with First Solar Electric, LLC to provide design, engineering, procurement, and construction services for solar projects for identified customers, subject to the satisfaction of certain contingencies and entering into definitive agreements for such services for each project.

At December 31, 2008, the estimated capital expenditures through 2011 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kv switchgear and main power transformer replacement.

As discussed above, Midwest Generation is subject to various commitments with respect to environmental compliance. Midwest Generation is in the process of completing engineering work for the potential installation of SCR and FGD equipment on Units 5 and 6 at the Powerton Station and SNCR equipment on Unit 6 at the Joliet Station. If a decision was made to proceed with these improvements the estimated capital costs (in 2008 dollars) would be approximately:

Midwest Generation has determined that these capital expenditures could be reduced if the construction work sequence of FGD and SCR at the Powerton Station were reversed. The complexity of the Powerton Station installation and construction interferences are representative of the balance of the fleet and Midwest Generation currently estimates approximately $650/kW for any FGD installation it elects to make on other units.

A decision to make these improvements has not been made. Midwest Generation is still reviewing all technology and unit shutdown combinations, including interim and alternative compliance solutions. For further discussion of environmental regulations and current status of environmental improvements in Illinois, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Environmental Matters and Regulations."

At December 31, 2008, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 942 MW. The turbine commitments generally represent approximately two-thirds of the total capital costs of EME's wind projects. As of December 31, 2008, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits and agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed, or that EME will be able to successfully develop projects utilizing all of its turbine commitments. EME may also postpone or cancel wind turbine commitments, subject to the provisions of the relevant contracts.

The Big Sky wind project is a 240 MW planned wind project in Illinois. EME has commenced pre-construction activities for equipment purchases, site development and interconnection activities ($99 million capitalized at December 31, 2008). Release of the project for full construction is pending a decision on selection of turbines. The costs to complete the Big Sky wind project, including construction and turbine transportation and installation, are approximately $165 million. This estimate excludes the turbine costs set forth as turbine commitments in the table above and costs incurred to date. Upon completion, the project plans to sell electricity into the PJM market as a merchant generator or to local utilities under power sales contracts.

Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a ten-year power sales contract starting in 2013 for the output of the Walnut Creek project. In December 2008, EME and Walnut Creek Energy cancelled the turbine order for the Walnut Creek project pending resolution of the legal challenges discussed below and recorded a pre-tax charge of $23 million ($14 million, after tax). EME plans to purchase turbines for the project subject to resolution of uncertainty regarding the availability of required emissions credits.

In July 2008, the Los Angeles Superior Court found that actions taken by the SCAQMD, in promulgating rules that had made available a "Priority Reserve" of emissions credits for new power generation projects, did not satisfy California environmental laws. In November 2008, the Los Angeles Superior Court enjoined the SCAQMD from issuing Priority Reserve emission credits to any facility, including new power projects, until a satisfactory environmental analysis is completed. Though SCAQMD has filed a notice of intent to appeal that decision, it has separately stated that it is not seeking to reinstate the rule that had made Priority Reserve emission credits available to new power generation projects. Separately, in August 2008, substantially the same plaintiffs in the Superior Court action sued the SCAQMD in federal court alleging that the emission credits contained in SCAQMD's Priority Reserve are invalid and seeking to enjoin SCAQMD from transferring them to any parties. Walnut Creek Energy has intervened in the federal lawsuit. EME cannot predict the outcome of these proceedings.

In the air basins regulated by SCAQMD, the need for particulate matter (PM10) and SO₂ emission credits exceeds available supply, and it is difficult to create new credits. Walnut Creek will be unable to begin construction until the legal challenges to the Priority Reserve emission credits have been favorably resolved or another source of credits for the project has been identified. The capital costs to construct this project, excluding interest, are estimated in the range of $500 million to $600 million.

The 2008 increase in cash provided by operating activities from continuing operations was primarily attributable to $225 million in margin deposits received from counterparties at December 31, 2008, partially offset by the purchase of annual NO_X emission allowances in 2008 by Midwest Generation.

The 2007 decrease in cash provided by operating activities from continuing operations was primarily attributable to a decrease of $69 million in required margin and collateral deposits in 2007 for EME's hedging and trading activities, compared to a decrease of $198 million in 2006. This change resulted from an increase in forward market prices in 2007 from 2006. The decrease was also due to timing of cash receipts and disbursements related to working capital items. Partially offsetting these decreases was higher pre-tax income from continuing operations in 2007 compared to 2006.

Cash provided by operating activities from discontinued operations decreased in 2007 from 2006 reflecting higher distributions received in 2006 compared to 2007 from the Lakeland power project. See "Results of Operations—Results of Discontinued Operations—Lakeland Project" for more information regarding these distributions.

The 2008 increase in cash provided by financing activities from continuing operations was primarily attributable to an increase in borrowings in 2008 under EME's corporate credit facility and Midwest Generation's working capital facility. In addition, EME received $12 million from the minority shareholders in the Elkhorn Ridge wind project.

The 2007 decrease in cash used in financing activities from continuing operations was primarily attributable to net proceeds of $2.7 billion received from EME's issuance of senior notes in 2007, which were mostly used to repay $587 million of EME's outstanding senior notes, $999.8 million of Midwest Generation's second priority senior secured notes, $327.8 million of Midwest Generation's senior secured term loan facility. In addition, EME received a cash contribution of $36 million in 2007 from MEHC. Partially offsetting the decrease were dividend payments made to MEHC of $925 million in 2007 compared to $51 million in 2006. In 2006, net proceeds of $1 billion were received from EME's issuance of senior notes, which were mostly used to repay $1 billion of EME's outstanding senior notes. Tender premiums and related fees paid associated with the foregoing financings were $137 million and $139 million in 2007 and 2006, respectively.

The change in short-term investments is reflected as investing activities in the cash flow statement. Investments with maturity dates less than 90 days are generally considered cash equivalents and are classified as part of cash and cash equivalents in the consolidated balance sheet. The reduction of short-term investments during 2008 and 2007 of $77 million and $477 million, respectively, is included as a source of cash from investing activities, whereby the increase in short-term investments during 2006 of $375 million is considered a use of cash from investing activity. Excluding the impact of changes in short-term investments, cash used in investing activities is primarily related to capital expenditures and investments in other assets (primarily turbine deposits and pre-construction costs). The amount of capital expenditures and investment in other assets were $889 million in 2008, $838 million in 2007 and $411 million in 2006. The increase in the level of expenditures is primarily due to expansion of investments for renewable energy projects. Included in investments in other assets were turbine deposits for wind projects prior to commencement of construction of $213 million in 2008, $271 million in 2007 and $130 million in 2006.

Credit ratings for EME, Midwest Generation and EMMT, at December 31, 2008, were as follows:

On December 23, 2008, S&P assigned a negative outlook to its corporate ratings for EME, Midwest Generation, and EMMT. 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 being required to make equity contributions or provide additional financial support to its subsidiaries, including 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 S&P 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. During 2008, EME sold 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. In order to continue to sell forward the output of the Homer City facilities through EMMT, either: (1) a consent from the sale-leaseback owner participant must be obtained; 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 participants that allows EME Homer City to enter into such sales, under specified conditions, through March 1, 2014. 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."

In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, because the credit ratings of EMMT and EME are below investment grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. At December 31, 2008, EMMT had deposited $43 million in cash with clearing brokers in support of futures contracts and had deposited $45 million in cash with counterparties in support of

forward energy and congestion contracts. In addition, EME had received cash collateral of $225 million at December 31, 2008, to support credit risk of counterparties under margin agreements.

Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2008, if wholesale energy prices or the amount hedged changes. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of December 31, 2008 could increase by approximately $140 million over the remaining life of the contracts using a 95% confidence level. Certain EMMT hedge contracts do not require margining, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings." Furthermore, the hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions would result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT also has hedge contracts that do not require margining, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of hedge contracts with credit-risk related contingent features was a net asset at December 31, 2008 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or posting additional collateral under the contingent features described above.

Midwest Generation has cash on hand to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois Plants. At December 31, 2008, Midwest Generation had available $22 million of borrowing capacity under its $500 million working capital facility. In addition, EME has cash on hand and $59 million of borrowing capacity available under its $600 million working capital facility to provide credit support to subsidiaries. See "—EME's Liquidity as a Holding Company" for further discussion.

At December 31, 2008, EME had corporate cash and cash equivalents and short-term investments of $1.1 billion to meet liquidity needs. Since EME, as a holding company, does not directly own any revenue producing generation facilities, it depends for the most part on cash distributions and tax payments from its projects to pay debt service, tax payments, contractual obligations and general and administrative expenses. 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. 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."

The following table summarizes the payments by Midwest Generation as equity distributions through Edison Mission Midwest Holdings and payments made pursuant to tax-allocation agreements:

Prior to 2008, Midwest Generation did not make significant payments under its tax-allocation agreements due to losses principally related to the 2004 termination of the Collins Station lease and subsequent decommissioning of the plant. Beginning in 2008, Midwest Generation's federal and state tax payments were made in accordance with the tax-allocation agreements.

The following table summarizes the payments by EME Homer City under its subordinated revolving loan with Edison Mission Finance Co., a subsidiary of EME, that constitute permitted distributions pursuant to the terms of the sale-leaseback transaction and payments made pursuant to tax-allocation agreements:

The following table summarizes the distributions, repayment of loans and return of capital from EME's unconsolidated affiliates:

The following table summarizes the debt service and contractual obligations of EME at December 31, 2008:

See "—Contractual Obligations, Commitments and Contingencies—Contractual Obligations" and "—Off-Balance Sheet Transactions—EME's Obligations to Midwest Generation" for further details of debt service and contractual obligations.

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 taxable income in order to be able to utilize EME's consolidated 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 made net tax-allocation payments to Edison International of $95 million, $112 million and $151 million in 2008, 2007 and 2006, respectively.

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.

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at December 31, 2008 or for the 12 months ended December 31, 2008:

Midwest Generation is bound by the covenants in its credit agreement and 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, enter into swap agreements, or engage in transactions for any speculative purpose. In order for Midwest Generation to make a distribution, it must be in compliance with the covenants specified under its credit agreement, including maintaining a debt to capitalization ratio of no greater than 0.60 to 1.

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.

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.

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate debt-to-corporate capital ratio as such terms are defined in the credit facility. The key ratios at December 31, 2008 or for the 12 months ended December 31, 2008 are as follows:

EME is restricted from the sale or disposition of assets, which includes the making of a distribution, if the aggregate net book value of all such sales during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding such sale. At December 31, 2008, the maximum sale or disposition of EME assets is approximately $800 million. This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained by EME as cash or cash equivalents or are used by EME to repay senior debt of EME or debt of its subsidiaries.

The following table summarizes EME's significant consolidated contractual obligations as of December 31, 2008:

				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)		$	7,517	$	328	$	631	$	1,925	$	4,633
Operating lease obligations			3,762		361		682		652		2,067
Purchase obligations:
	Capital improvements		150		150		—		—		—
	Turbine commitments		938		706		232		—		—
	Fuel supply contracts		638		460		174		4		—
	Gas transportation agreements		75		8		16		16		35
	Coal transportation		396		236		160		—		—
	Other contractual obligations		286		59		145		82		—
Employee benefit plan contribution(2)			11		11		—		—		—

Total Contractual Obligations(3)		$	13,773	$	2,319	$	2,040	$	2,679	$	6,735

At December 31, 2008, 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 Units 7 and 8 of the Joliet coal-fired stations located in 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 $336 million in 2009, $325 million in 2010, $311 million in 2011, $311 million in 2012, $300 million in 2013, and the minimum lease payments due after 2013 are $2.0 billion. For further discussion, see "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions."

At December 31, 2008, EME's subsidiaries had firm commitments in 2009 for capital and construction expenditures. The majority of these expenditures primarily relate to the construction of wind

projects and environmental improvements at the Illinois Plants. These expenditures are planned to be financed by cash on hand and cash generated from operations.

EME had entered into various turbine supply agreements with vendors to support its wind development efforts. At December 31, 2008, EME had secured 484 wind turbines (942 MW) for use in future projects for an aggregate purchase price of $1.2 billion. One of EME's turbine suppliers has requested an escalation adjustment to its pricing for 2008 and 2009 turbines pursuant to its turbine supply agreement. EME is evaluating the request, and discussions with the supplier are ongoing. Under certain of these agreements, EME may terminate the purchase of individual turbines, or groups of turbines, for convenience. Upon any such termination, EME may be obligated to pay termination charges to the vendor.

For a discussion on wind turbine performance issues, see "Results of Operations—Earnings from Consolidated Operations—Renewable Energy Projects" and "Market Risk Exposures—Credit Risk."

At December 31, 2008, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers. The minimum commitments are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses. In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009.

At December 31, 2008, 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 nine years.

As of December 31, 2008, standby letters of credit aggregated $133 million and were scheduled to expire in 2009.

EME and certain of 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, guarantees of debt and indemnifications.

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. 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 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 takes 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. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV discussed below under "—Contingencies—Midwest Generation New Source Review Notice of Violation" and potential litigation by private groups related to the NOV. Except as discussed below, EME has not recorded a liability related to this indemnity.

Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2010. There were approximately 222 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2008. Midwest Generation had recorded a $52 million liability at December 31, 2008 related to this matter.

Midwest Generation recorded an undiscounted liability for its indemnity for future asbestos claims through 2045. During the fourth quarter of 2007, the liability was reduced by $9 million based on updated estimated losses. In calculating future losses, various assumptions were made, 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 no asbestos claims will be filed after 2044.

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.

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. Payments would be triggered under this indemnity by a valid claim from the sellers. 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. See "—Contingencies—EME Homer City New Source Review Notice of Violation" for discussion of the NOV received by EME Homer City and associated indemnity claims. EME has not recorded a liability related to this indemnity.

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. 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, 2008, EME had recorded a liability of $95 million (of which $51 million is classified as a current liability) 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. At December 31, 2008, EME had recorded a liability of $13 million related to these matters.

As of December 31, 2008, EME has a 50% interest in the March Point project. 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. The obligations under this indemnification agreement as of December 31, 2008, if payment were required, would be $56 million, which is EME's maximum exposure to loss as EME fully impaired its equity investment in the project in 2005. EME has not recorded a liability related to the indemnity.

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to

bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

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.

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 on 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.

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 PURPA. See "Item 1. Business—Regulatory Matters—U.S. Federal Energy Regulation." Prior to the passage of the EPAct 2005, these regulations limited EME's ownership interest in qualifying facilities to no more than 50% due to EME's affiliation with SCE, 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 over the operating, funding or construction activities of the project entity. In certain projects, long-term debt to finance the assets constructed was secured. 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, 2008, entities which EME has accounted for under the equity method had indebtedness of $294 million, of which $128 million is proportionate to EME's ownership interest in these projects.

EME has entered into sale-leaseback transactions related to the Powerton Station and Units 7 and 8 of the Joliet Station in Illinois and the Homer City facilities in Pennsylvania. For further discussion, see "Management's Overview; Critical Accounting Policies and Estimates—Critical Accounting Policies and Estimates—Off-Balance Sheet Financing" and "—Contractual Obligations, Commitments and Contingencies—Contractual Obligations—Operating Lease Obligations."

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 of $46 million, $54 million and $61 million in 2008, 2007 and 2006, 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:

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 on EME's consolidated balance sheet. In accordance with GAAP, EME records rent expense on a levelized basis over the terms of the respective leases. The following table summarizes the lease payments and rent expense for the three years ended December 31, 2008.

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, 2008 and 2007, prepaid rent on these leases was $878 million and $716 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."

Proceeds, in the aggregate amount of approximately $1.4 billion, were received by Midwest Generation from the sale of the Powerton and Joliet plants, described above under "—Sale-Leaseback Transactions." These proceeds 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 owed by Midwest

Generation, the intercompany obligation does not appear on EME's consolidated balance sheet. The following table summarizes principal payments due under this intercompany loan:

EME funds the interest and principal payments due under the intercompany loan from distributions from EME's subsidiaries, including Midwest Generation and cash on hand. 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.

See the discussion on environmental matters and regulations in Note 12—Commitments and Contingencies under "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements."

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:

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.

EME uses "gross margin at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions at the Illinois Plants, the Homer City facilities, and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures 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, and gross margin at risk measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and counterparty credit exposure limits.

To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its electricity sales, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:

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 the types of hedge transactions set forth above 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 and Midwest Generation'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 addition, Midwest Generation may grant liens on its property in support of hedging transactions associated with the Illinois Plants. See "—Credit Risk" below.

In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME.

All the energy and capacity from the Illinois Plants is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. As discussed further below, power generated at the Illinois Plants is generally sold into the PJM market.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois Plants are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including the Cinergy Hub in the MISO. These trading hubs have been the most liquid locations for hedging purposes. See "—Basis Risk" below for further discussion.

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

The following table depicts the average historical market prices for energy per megawatt-hour during 2008, 2007 and 2006:

	24-Hour Northern Illinois Hub Historical Energy Prices(1)

	2008		2007		2006
January	$	47.09	$	35.75	$	42.27
February		54.46		56.64		42.66
March		58.58		42.04		42.50
April		53.87		48.91		43.16
May		44.49		44.49		39.96
June		56.06		39.76		34.80
July		63.79		43.40		51.82
August		52.66		57.97		54.76
September		43.08		39.68		31.87
October		35.31		50.14		37.80
November		38.34		43.25		41.90
December		40.43		44.36		33.57

Yearly Average	$	49.01	$	45.53	$	41.42

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.

The following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar year 2009 and calendar year 2010 "strips," which are defined as energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub during 2008:

EMMT engages in hedging activities for the Illinois Plants to hedge the risk of future change in the price of electricity. Hedging activities for energy only contracts are typically weighted toward on-peak periods. The following table summarizes Midwest Generation's hedge position at December 31, 2008:

The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City's primary trading hub) during the past three years:

	Historical Energy Prices(1) 24-Hour PJM

	Homer City Busbar						PJM West Hub
	2008		2007		2006		2008		2007		2006
January	$	54.32	$	40.30	$	48.67	$	66.80	$	44.63	$	54.57
February		61.74		64.27		49.54		68.29		73.93		56.39
March		65.37		55.00		53.26		70.48		61.02		58.30
April		61.99		52.42		48.50		69.12		58.74		49.92
May		49.37		48.12		44.71		59.84		53.89		48.55
June		78.72		45.88		38.78		98.50		60.19		45.78
July		72.39		48.23		53.68		91.80		58.89		63.47
August		60.16		55.44		58.60		73.91		71.00		76.57
September		52.33		48.90		33.26		66.04		60.14		34.40
October		44.46		53.89		37.42		52.88		61.11		39.65
November		44.99		47.27		40.13		54.50		55.25		44.83
December		46.74		52.58		35.29		50.62		59.67		40.53

Yearly Average	$	57.72	$	51.03	$	45.15	$	68.56	$	59.87	$	51.08

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.

EMMT engages in hedging activities for the Homer City facilities to hedge the risk of future change in the price of electricity. Hedging activities are typically weighted toward on-peak periods. The following table summarizes EME Homer City's hedge position at December 31, 2008:

The average price/MWh for EME Homer City's hedge position is based on the 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.

The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at December 31, 2008:

		Fixed Price Capacity Sales

		Through RPM Auction, Net					Non-unit Specific Capacity Sales				Variable Capacity Sales
		MW		Price per MW-day			MW		Price per MW-day		MW		Price per MW-day
January 1, 2009 to May 31, 2009
	Midwest Generation		2,957	$	122.41	(1)		880	$	64.35		—		—
	EME Homer City		820		111.92			—		—		905	$	56.56	(2)
June 1, 2009 to May 31, 2010
	Midwest Generation		4,582		102.04			723		72.84		—		—
	EME Homer City		1,670		191.32			—		—		—		—
June 1, 2010 to May 31, 2011
	Midwest Generation		4,929		174.29			—		—		—		—
	EME Homer City		1,813		174.29			—		—		—		—
June 1, 2011 to May 31, 2012
	Midwest Generation		4,582		110.00			—		—		—		—
	EME Homer City		1,771		110.00			—		—		—		—

Revenues from the sale of capacity from Midwest Generation and EME Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM's RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, and the CONE.

Midwest Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In addition, the load service requirements contracts entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a "bundled product"). Under PJM's business rules, Midwest Generation sells all of its available capacity (defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This means that the locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents on a net basis in the table above.

Prior to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery period of June 1, 2008 through May 31, 2009. EME Homer City is not receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City is receiving for these capacity sales is a function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions.

Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, 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 at the PJM West Hub in the case of the Homer City facilities and for settlement points at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Illinois Plants. EME's hedging 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:

Under PJM's market design, locational marginal pricing, which establishes market 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. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal transmission losses in addition to the component included for congestion. 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 as "basis risk." During 2008, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 16%, compared to 15% during 2007 and 12% during 2006. The monthly average difference during 2008 ranged from 7% to 21%. During 2008, transmission congestion in PJM has resulted in prices at the individual busbars of the Illinois Plants being lower than those at the Northern Illinois Hub by an average of 2%.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub, the Northern Illinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for EME Homer City. A financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME's hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

The Illinois Plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases

are made under a variety of supply agreements extending through 2012. The following table summarizes the amount of coal under contract at December 31, 2008 for the next four years:

EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City facilities, increased substantially during 2008 and increased steadily during 2007 from 2006. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) ranged from $61.75 per ton to $150 per ton during 2008 and decreased to a price of $76 per ton at January 9, 2009, as reported by the EIA. The 2008 increase in NAPP coal prices was primarily attributable to increased international and Atlantic basin coal demand resulting from a variety of factors in several countries consuming this coal. The current global economic conditions have tempered this demand and prices moderated as 2008 came to a close. In 2007, the price of NAPP coal fluctuated between $44.00 per ton to $55.25 per ton, which was the price per ton at December 21, 2007, as reported by the EIA. In 2006, the price of NAPP coal fluctuated between $37.50 per ton and $45.00 per ton, with a price of $43.00 per ton at December 15, 2006, as reported by the EIA. The 2007 increase in the NAPP coal price was in line with normal market price volatility.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Illinois Plants increased during 2008 from 2007 year-end prices and increased during 2007 from 2006 year-end prices. The 2008 and 2007 fluctuations in PRB coal prices were in line with normal market price volatility. The price of PRB coal fluctuated between $11 per ton to $14.50 per ton during 2008, with a price of $13 per ton at January 9, 2009, as reported by the EIA. In 2007, the price of PRB coal ranged from $8.35 per ton to $11.50 per ton, which was the price per ton at December 21, 2007. In 2006, the price of PRB coal ranged from $20.66 per ton in January 2006 to $9.90 per ton at December 15, 2006, as reported by the EIA.

EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are more than 50% of the delivered cost of PRB coal to the Illinois Plants).

Based on EME's anticipated coal requirements in 2009 in excess of the amount under contract, EME expects that a 10% change in the price of coal at December 31, 2008 would increase or decrease pre-tax income in 2009 by approximately $1 million.

EME is subject to price risk for purchases of emission allowances required for actual emissions greater than allowances held. The market price for emission allowances may vary significantly. For example, the average purchase price of SO₂ allowances was $315 per ton in 2008, $512 per ton in 2007 and $664 per ton in 2006. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances was $210 per ton at December 31, 2008. EME does not anticipate any requirements to purchase SO₂ emission allowances for 2009.

Based on EME's anticipated annual and seasonal NO_X requirements for 2009 beyond those allowances already purchased, EME expects that a 10% change in the price of annual and seasonal NO_X emission allowances at December 31, 2008 would increase or decrease pre-tax income in 2009 by approximately $4 million.

See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions.

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, see "Management's Overview; Critical Accounting Policies and Estimates—Critical Accounting Policies and Estimates—Derivative Financial Instruments and Hedging Activities."

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on

settlement of transactions), EME records unrealized gains or losses. Unrealized SFAS No. 133 gains or losses result from:

EME classifies unrealized gains and losses from energy contracts as part of operating revenues. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the three-year period ended December 31, 2008:

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. EME had power contracts with Lehman Brothers Commodity Services, Inc., a subsidiary of Lehman Brothers Holdings, for Midwest Generation for 2009 and 2010. Lehman Brothers Commodity Services also filed for bankruptcy protection on October 3, 2008. The obligations of Lehman Brothers Commodity Services under the power contracts are guaranteed by Lehman Brothers Holdings. These contracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the power contracts effective September 12, 2008 when it determined that it was no longer probable that performance would occur. The amount recorded in accumulated comprehensive income (loss) related to the effective portion of the hedges was $24 million pre-tax on that date. Since the power contracts are no longer being accounted for as cash flow hedges under SFAS No. 133 and subsequently were terminated, the subsequent change in fair value was recorded as an unrealized loss in 2008. Under SFAS No. 133, the pre-tax amount recorded in accumulated other comprehensive income (loss) will be reclassified to

operating revenues based on the original forecasted transactions in 2009 ($15 million) and 2010 ($9 million), unless it becomes probable that the forecasted transactions will no longer occur.

At December 31, 2008, excluding the unrealized losses described above related to Lehman Brothers Commodity Services, unrealized gains of $1 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($2 million in unrealized losses for 2009 and $3 million in unrealized gains for 2010).

EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Fair Value Measurements," for further discussion of EME's adoption of SFAS No. 157.

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 assessing the fair value of EME's non-trading derivative financial instruments, EME uses quoted market prices and forward market prices adjusted for credit risk. 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. The increase in fair value of electricity contracts at December 31, 2008 as compared to December 31, 2007 is attributable to a decline in the average market prices for power as compared to contracted prices at December 31, 2008, which is the valuation date. A 10% change in the market price at December 31, 2008 would increase or decrease the fair value of outstanding derivative commodity price contracts by approximately $59 million. The following table summarizes the maturities and the related fair value of EME's commodity derivative assets and liabilities as of December 31, 2008:

Prices provided by external sources in the preceding table include derivatives whose fair value is based on forward market prices in active markets adjusted for non-performance risks which would be considered Level 2 derivative positions when there are no unobservable inputs that are significant to the valuation. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York

Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.

The fair value of the commodity financial instruments related to energy trading activities as of December 31, 2008 and 2007 are set forth below:

The change in the fair value of trading contracts for the year ended December 31, 2008 was as follows:

A 10% change in the market price at December 31, 2008 would increase or decrease the fair value of trading contracts by approximately $2 million. The impact of changes to the various inputs used to determine the fair value of Level 3 derivatives is not currently material to EME's results of operations as such changes are offset by similar changes in derivatives classified within Level 3 as well as other categories.

The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of December 31, 2008):

In the table above, prices actively quoted include exchange traded derivatives. Prices provided by external sources include non-exchange traded derivatives which are priced based on forward market prices adjusted for non-performance risks which would be considered Level 2 derivative positions when there are no unobservable inputs that are significant to the valuation. Fair values for Level 2 derivative positions are determined using the same methodology previously described for non-trading derivative financial instruments. Fair value for Level 3 derivative positions is determined using prices based on models and other valuation methods and include load requirements services contracts, illiquid financial transmission rights, over-the-counter derivatives at illiquid locations and long-term power agreements. For long-term power agreements, EME's subsidiary records these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or

default by the counterparty. At December 31, 2008, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

The credit risk exposure set forth in the above table is comprised of $203 million of net accounts receivable and payables and $481 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties.

Included in the table above are exposures to financial institutions with credit ratings of A- or above. Due to recent developments in the financial markets, the credit ratings may not be reflective of the related credit risks. See "Management's Overview; Critical Accounting Policies and Estimates—Management's Overview—Financial Markets and Economic Conditions" for further discussion. The total net exposure to financial institutions at December 31, 2008 was $151 million. This total net exposure excludes positions with Lehman Brothers Holdings and its subsidiaries. Five financial institutions comprise 29% of the net exposure above with the largest single net exposure with a financial institution representing 11%. In addition to the amounts set forth in the above table, EME's subsidiaries have posted an $88 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. Margining posted to support these activities also exposes EME to credit risk of the related entities.

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

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 and energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 50% of EME's consolidated operating revenues for the year ended December 31, 2008. Moody's rates PJM's debt Aa3. PJM, an ISO 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 are shared by all other members based upon a predetermined formula. At December 31, 2008, EME's account receivable due from PJM was $61 million.

EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 12% of EME's consolidated operating revenues for the year ended December 31, 2008. Commonwealth Edison's senior unsecured debt ratings are BBB- by S&P and Baa3 by Moody's. At December 31, 2008, EME's account receivable due from Commonwealth Edison was $23 million.

For the year ended December 31, 2008, a third customer, Constellation Energy Commodities Group, Inc., accounted for 10% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from EME's merchant plants and largely consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB by S&P and Baa3 by Moody's. At December 31, 2008, EME's account receivable due from Constellation was $22 million.

The terms of EME's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EME's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to a turbine supplier may have a material impact on EME's wind projects.

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power 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, a 100-basis-point change in interest rates at December 31, 2008 would increase or decrease EME's 2009 annual income before taxes by approximately $9 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 consolidated long-term obligations (including current portion) was $4.0 billion at December 31, 2008, compared to the carrying value of $4.7 billion. A 10% increase in market interest rates at December 31, 2008 would result in a decrease in the fair value of total long-term obligations by approximately $182 million. A 10% decrease in market interest rates at December 31, 2008 would result in an increase in the fair value of total long-term obligations by approximately $200 million.

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."

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

EME's management, under the supervision and 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 that 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.

EME's management is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Exchange Act Rule 13a-15(f), for EME. Under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, EME's management conducted an evaluation of the effectiveness of EME's internal controls over financial reporting based on the framework set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, EME's management concluded that EME's internal control over financial reporting were effective as of December 31, 2008.

There were changes as described below in EME's internal controls over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal controls over financial reporting.

Effective July 1, 2008, the human resources module was implemented as part of the Edison International enterprise-wide project. The implementation of this module and the related workflow capabilities resulted in a material change to EME's financial reporting controls and procedures.

Therefore, EME has modified the design and documentation of the internal control process and procedures relating to the new timekeeping system to replace and supplement existing internal controls over financial reporting, as appropriate. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in EME's internal controls over financial reporting.

This annual report does not include an attestation report of EME's independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by EME's independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit EME to provide only management's report in this annual report.

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

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 Notes 1, 2, 10 and 11 to the consolidated financial statements, the Company changed the manner in which it accounts for stock-based compensation as of January 1, 2006, defined benefit pension and other postretirement plans as of December 31, 2006, uncertain tax positions as of January 1, 2007, and margin and cash collateral deposits related to derivative positions and fair value measurement and disclosure accounting principles as of January 1, 2008.

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

			Years Ended December 31,

			2008			2007			2006
Operating Revenues			$	2,811		$	2,580		$	2,239
Operating Expenses
	Fuel			747			684			645
	Plant operations			621			584			511
	Plant operating leases			176			176			176
	Depreciation and amortization			194			162			144
	Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits, net (Notes 6 and 12)			14			6			—
	Administrative and general			207			204			140

		Total operating expenses		1,959			1,816			1,616

	Operating income			852			764			623

Other Income (Expense)
	Equity in income from unconsolidated affiliates			122			200			186
	Dividend income			10			12			2
	Interest income			26			85			97
	Interest expense			(279	)		(273	)		(279	)
	Loss on early extinguishment of debt			—			(160	)		(146	)
	Other income (expense), net			12			6			21

		Total other income (expense)		(109	)		(130	)		(119	)

	Income from continuing operations before income taxes and minority interest			743			634			504
	Provision for income taxes			243			219			189
	Minority interest			—			1			1

Income From Continuing Operations				500			416			316
Income (loss) from operations of discontinued subsidiaries, net of tax (Note 5)				1			(2	)		98

Net Income			$	501		$	414		$	414

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

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

			December 31,

			2008		2007
Assets
Current Assets
	Cash and cash equivalents		$	1,807	$	994
	Short-term investments			4		81
	Accounts receivable—trade			241		224
	Receivables from affiliates			18		35
	Inventory			189		149
	Derivative assets			170		56
	Margin and collateral deposits			88		85
	Deferred taxes			—		21
	Prepaid expenses and other			144		89

		Total current assets		2,661		1,734

Investments in Unconsolidated Affiliates				362		387

Property, Plant and Equipment				5,643		4,942
	Less accumulated depreciation and amortization			1,241		1,053

		Net property, plant and equipment		4,402		3,889

Other Assets
	Deferred financing costs			36		41
	Long-term derivative assets			170		91
	Restricted cash			43		48
	Rent payments in excess of levelized rent expense under plant operating leases			878		716
	Other long-term assets			528		366

		Total other assets		1,655		1,262

Total Assets			$	9,080	$	7,272

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

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

			December 31,

			2008		2007
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	95	$	73
	Payables to affiliates			18		17
	Accrued liabilities			380		289
	Derivative liabilities			22		28
	Interest payable			30		30
	Deferred taxes			66		—
	Current maturities of long-term obligations			24		17

		Total current liabilities		635		454

Long-term obligations net of current maturities				4,638		3,806
Deferred taxes and tax credits				541		351
Deferred revenues				63		65
Long-term derivative liabilities				5		88
Other long-term liabilities				434		543

Total Liabilities				6,316		5,307

Minority Interest				80		42

Commitments and Contingencies (Notes 3, 9 and 12)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of December 31, 2008 and 2007			64		64
	Additional paid-in capital			1,335		1,326
	Retained earnings			1,085		596
	Accumulated other comprehensive income (loss)			200		(63	)

Total Shareholder's Equity				2,684		1,923

Total Liabilities and Shareholder's Equity			$	9,080	$	7,272

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

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

		Common Stock		Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Shareholder's Equity

Balance at December 31, 2005		$	64	$	2,228		$	(171	)	$	(211	)	$	1,910
	Net income							414						414
	Other comprehensive income										318			318
	Adjustment to initially apply SFAS No. 158, net of tax										(6	)		(6	)
	Non-cash equity contribution				8									8
	Cash dividends to parent				(50	)								(50	)
	Payments to Edison International for stock option price appreciation on options exercised, net of tax				(10	)								(10	)
	Other stock transactions, net				(2	)								(2	)

Balance at December 31, 2006			64		2,174			243			101			2,582
	Net income							414						414
	Impact upon adoption of FIN No. 48							(1	)					(1	)
	Other comprehensive loss										(164	)		(164	)
	Cash contribution from parent				36									36
	Cash dividends to parent				(899	)		(26	)					(925	)
	Payments to Edison International for stock purchases related to stock-based compensation							(34	)					(34	)
	Excess tax benefits related to stock-option exercises				11									11
	Other stock transactions, net				4									4

Balance at December 31, 2007			64		1,326			596			(63	)		1,923
	Net income							501						501
	Other comprehensive income										263			263
	Payments to Edison International for stock purchases related to stock-based compensation							(12	)					(12	)
	Excess tax benefits related to stock-option exercises				6									6
	Other stock transactions, net				3									3

Balance at December 31, 2008		$	64	$	1,335		$	1,085		$	200		$	2,684

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

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

			Years Ended December 31,

			2008			2007			2006
Net Income			$	501		$	414		$	414
Other comprehensive income (loss), net of tax:
	Pension and postretirement benefits other than pensions:
		Prior service adjustment, net of tax		3			(1	)		—
		Net gain (loss) adjustment, net of tax expense (benefit) of $(26) and $4 for 2008 and 2007, respectively		(41	)		7			—
		Amortization of net loss and prior service adjustment included in expense, net of tax		1			1			—
	Minimum pension liability adjustment, net of income tax effect			—			—			(3	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $138, $(160) and $211 for 2008, 2007 and 2006, respectively		211			(235	)		309
		Reclassification adjustments included in net income, net of income tax benefit of $58, $45 and $9 for 2008, 2007 and 2006, respectively		89			64			12

Other comprehensive income (loss)				263			(164	)		318

Comprehensive Income			$	764		$	250		$	732

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

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

			Years Ended December 31,

			2008			2007			2006
Cash Flows From Operating Activities
	Net income		$	501		$	414		$	414
	Less: (Income) loss from discontinued operations			(1	)		2			(98	)

	Income from continuing operations, net			500			416			316
	Adjustments to reconcile income to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(121	)		(199	)		(183	)
		Distributions from unconsolidated affiliates		108			137			170
		Depreciation and amortization		202			172			158
		Minority interest		—			(1	)		—
		Deferred taxes and tax credits		104			41			100
		Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits		14			1			—
		Loss on early extinguishment of debt		—			160			146
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		(3	)		69			198
		Decrease (increase) in accounts receivables		(1	)		(29	)		125
		Decrease (increase) in inventory		(40	)		9			(38	)
		Decrease (increase) in prepaid expenses and other		(9	)		6			(26	)
		Increase in rent payments in excess of levelized rent expense		(162	)		(160	)		(161	)
		Increase (decrease) in accounts payable and other current liabilities		(7	)		6			(15	)
		Increase (decrease) in interest payable		—			2			(23	)
		Decrease (increase) in derivative assets and liabilities		215			(106	)		370
		Other operating—assets		(53	)		(18	)		(1	)
		Other operating—liabilities		(19	)		13			(5	)

	Operating cash flow from continuing operations			728			519			1,131
	Operating cash flow from discontinued operations			1			(2	)		94

		Net cash provided by operating activities		729			517			1,225

Cash Flows From Financing Activities
	Borrowings on long-term debt			1,130			2,930			1,450
	Payments on long-term debt agreements			(292	)		(2,276	)		(1,683	)
	Cash contribution from minority shareholders			12			—			—
	Cash contribution from parent			—			36			—
	Cash dividends to parent			—			(925	)		(51	)
	Payments to affiliates related to stock-based awards			(8	)		(34	)		(27	)
	Excess tax benefits related to stock-based awards			3			14			7
	Premium paid on extinguishment of debt and financing costs			(1	)		(162	)		(157	)

		Net cash provided by (used in) financing activities		844			(417	)		(461	)

Cash Flows From Investing Activities
	Capital expenditures			(552	)		(540	)		(310	)
	Proceeds from return of capital and loan repayments and sale of assets			39			32			41
	Proceeds from sale of membership interest			28			—			—
	Purchase of interest of acquired companies			(19	)		(33	)		(18	)
	Proceeds from sale of interest in projects			—			—			43
	Purchase of short-term investments			(19	)		(20	)		(512	)
	Maturities of short-term investments			96			497			137
	Decrease in restricted cash			4			43			14
	Investments in other assets			(337	)		(298	)		(101	)

		Net cash used in investing activities		(760	)		(319	)		(706	)

Net increase (decrease) in cash and cash equivalents				813			(219	)		58
Cash and cash equivalents at beginning of period				994			1,213			1,155

Cash and cash equivalents at end of period			$	1,807		$	994		$	1,213

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

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EME is a wholly owned subsidiary of 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 SCE. Through its subsidiaries, EME is an independent power producer engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also conducts hedging and energy trading activities in power markets open to competition.

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 6—Acquisitions and Variable Interest Entities—Variable Interest Entities, 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.

Certain prior year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

The preparation of financial statements in conformity with GAAP 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.

Cash, cash equivalents and short-term investments as of December 31, 2008 and 2007 consisted of the following:

		December 31, 2008		December 31, 2007

		(in millions)
Cash		$	31	$	121

Money market funds		$	1,581	$	369
U.S. Treasury securities			—		47
U.S. government agency securities			164		—
Commercial paper			30		316
Time deposits (certificates of deposit)			1		141

	Total cash equivalents	$	1,776	$	873

Commercial paper		$	1	$	32
Certificates of deposit			—		41
U.S. Treasury securities			—		7
Corporate bonds			—		1
Money market funds			3		—

	Total short-term investments	$	4	$	81

	Total cash, cash equivalents and short-term investments	$	1,811	$	1,075

Cash equivalents, with the exception of money market funds, were stated at amortized cost plus accrued interest. The carrying value of cash equivalents approximates fair value due to maturities of less than three months. For further discussion of money market funds, see Note 2—Fair Value Measurements. For a discussion of restricted cash, see "—Restricted Cash."

At December 31, 2008 and 2007, EME had classified all marketable debt securities as held-to-maturity under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The securities were carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material. Held-to-maturity securities all mature within one year.

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 at December 31, 2008 and 2007 amounted to $20 million and $14 million, respectively. Amortization of deferred financing costs charged to operations was $1 million, $3 million and $5 million in 2008, 2007 and 2006, respectively.

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, 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 derivative assets or liabilities. In the absence of quoted market prices, financial instruments are valued at fair value determined, considering time value, volatility of the underlying commodity, and other factors as determined by EME. Resulting gains and losses are recognized in operating revenues in the accompanying consolidated income statements in the period of change in accordance with EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Derivative assets include the fair value of open financial positions related to trading activities and the present value of net amounts receivable from structured transactions. Derivative liabilities include the fair value of open financial positions related to trading activities. The results of derivative activities are recorded as part of cash flows from operating activities in the accompanying consolidated statements of cash flows.

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.

EME evaluates the impairment of its investments in projects and other long-lived assets based on a review of estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying amount of such investments or assets may not be recoverable. If the carrying amount for an equity method investment exceeds fair value, an impairment loss is recorded if the decline is other than temporary in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." If the carrying amount of a long-lived asset exceeds the amount of the expected future cash flows, undiscounted and without interest charges, then an impairment loss is recognized in accordance with SFAS No. 144.

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 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 while production tax credits are recognized when earned. EME's investments in wind-powered electric generation projects qualify for federal production tax credits under Section 45 of the Internal Revenue Code. Such credits are allowable for production during the 10-year period after a qualifying wind energy facility is placed into service. Certain of EME's wind projects also qualify for state tax credits which are accounted for similarly as federal production tax credits.

Interest expense and penalties associated with income taxes are reflected in provision for income taxes on EME's consolidated statements of income. Income tax accounting policies are discussed further in Note 10—Income Taxes.

EME accounts for acquired intangible assets in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets." Under SFAS No. 142, acquired intangible assets with indefinite lives are not amortized; rather they are tested for impairment. Intangible assets are periodically reviewed when impairment indicators are present to assess recoverability from future operations using undiscounted future cash flows. For project development rights, the assets are subject to ongoing impairment analysis, such that if a project is no longer expected, the capitalized costs are written off.

Current intangible assets reflected in prepaid expenses and other on EME's consolidated balance sheet, consist of emission allowances purchased by EME and amounted to $88 million and $45 million at December 31, 2008 and 2007, respectively.

Noncurrent intangible assets reflected in other long-term assets on EME's consolidated balance sheets consist of the following:

Amortized intangible assets were amortized using the straight-line method over five years. Total amortization expense for intangible assets subject to amortization was approximately $1 million for the

year ended December 31, 2007. See Note 6—Acquisitions and Variable Interest Entities—Variable Interest Entities, for further discussion.

In 2008 and 2007, project development rights relate to the consolidation of a development stage enterprise. See Note 6—Acquisitions and Variable Interest Entities—Variable Interest Entities, for further discussion. In 2007, EME acquired six projects in Texas and Oklahoma, five of which are in various stages of development with target completion dates of 2009 and beyond. In 2008, the Buffalo Bear project achieved commercial operation. The initial purchase price paid was recorded as project development rights. In 2007, EME also recorded option rights pursuant to EME's joint development agreement entered into in December 2007 to develop jointly a portfolio of projects located in Arizona, Nevada and New Mexico. EME paid $24 million to acquire a 1% interest in twelve designated projects and the option to purchase the remaining 99%. The projects are in development with target completion dates of 2009 and beyond. EME is required to fund ongoing development expenses for each project.

In 2008 and 2007, EME purchased emission allowances at its Illinois Plants and Homer City facilities. In 2008, EME also purchased emission allowances related to thermal projects under development.

Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2008 and December 31, 2007 consisted of the following:

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. See "—New Accounting Pronouncements—Accounting Principles Adopted—FASB Staff Position FIN No. 39-1" for a discussion of EME's adoption of FIN No. 39-1. In accordance with FIN No. 39-1, EME presents a portion of its margin and cash collateral deposits net with its derivative positions on EME's consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $51 million and $36 million at December 31, 2008 and 2007, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $225 million at December 31, 2008.

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. EME adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on EME's consolidated balance sheets, but had no impact on EME's consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in net assets (margin and collateral deposits) of $36 million. The consolidated statement of cash flows for the years ended December 31, 2007 and 2006 have been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flow from continuing operations.

In February 2007, the FASB issued SFAS No. 159, "Fair Value Option for Financial Assets and Liabilities, Including an Amendment of FASB Statement No. 115," which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. EME adopted this pronouncement effective January 1, 2008. The adoption of this standard had no impact because EME did not make an optional election to report additional financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. EME adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustment to its consolidated financial statements. The accounting requirements for employers' pension and other postretirement benefit plans were effective at the end of 2008, which was the next measurement date for these benefit plans. EME will adopt this standard for nonrecurring nonfinancial assets and liabilities measured at fair value during the first quarter of 2009. Since this standard is applied prospectively, AROs existing before the adoption of the standard will not be adjusted for nonperformance risk. During 2008, EME did not apply SFAS No. 157 to new AROs related to its wind facilities constructed during the year. For further discussion, see Note 2—Fair Value Measurements.

In October 2008, the FASB issued FSP SFAS No. 157-3, "Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active." This position clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. It also reaffirms the notion of fair value as an exit price as of the measurement date. This position was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption had no impact on EME's consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally Accepted Accounting Principles," which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements for nongovernmental entities that are presented in conformity with GAAP. This statement transfers the GAAP hierarchy from the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, "The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles" to the FASB. SFAS No. 162 was effective on November 15, 2008. The adoption of this standard did not have an impact on EME's consolidated results of operations, financial position or cash flows.

In December 2008, the FASB issued FSP SFAS 140-4 and FIN No. 46(R)-8, "Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities." For asset transfers, the additional disclosure requirements primarily focus on the transferor's continuing involvement with transferred financial assets and the related risks retained. For variable interest entities, this position requires public enterprises to provide additional disclosures about their involvement with variable interest entities including the method for determining whether an enterprise is the primary beneficiary, including the significant judgments and assumptions made and the details of any financial or other support provided to a variable interest entity. This position was effective for reporting periods ending after December 15, 2008. The adoption did not have an impact on EME's consolidated financial position, results of operations or cash flows. See Note 6—Acquisitions and Variable Interest Entities, for disclosures pertaining to variable interest entities.

In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. Early adoption is not permitted.

In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements," which requires an entity to present minority interest that reflects the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity's equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. EME will adopt SFAS No. 160 in the first quarter of 2009. In accordance with this standard, EME will reclassify minority interest to a component of shareholder's equity (at December 31, 2008 this amount was $80 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 was effective for fiscal years beginning after November 15, 2008, with early adoption permitted. EME will adopt SFAS No. 161 in the first quarter of 2009. Since SFAS No. 161 impacts disclosures only, the adoption of this standard will not have an impact on EME's consolidated results of operations, financial position or cash flows.

In April 2008, the FASB issued FSP SFAS No. 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, "Goodwill and Other Intangible Assets." The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other GAAP. EME will adopt FSP SFAS No. 142-3 in the first quarter of 2009. The adoption of this position will not have an impact on EME's consolidated results of operations, financial position or cash flows.

In December 2008, the FASB issued FSP SFAS No. 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets." This position requires additional plan asset disclosures about the major categories of assets, the inputs and valuation techniques used to measure fair value, the level within the fair value hierarchy, the effect of using significant unobservable inputs (Level 3) and significant concentrations of risk. This position is effective for years ending after December 15, 2009 and therefore, EME will adopt FSP SFAS No. 132(R)-1 at year-end 2009. FSP SFAS No. 132(R)-1 will impact disclosures only and will not have an impact on EME's consolidated results of operations, financial position or cash flows.

In November 2008, the FASB ratified the consensus in EITF Issue No. 08-6, "Equity Method Investment Accounting Considerations." This issue clarifies the accounting for certain transactions and impairment considerations involving equity method investments. This issue is effective prospectively beginning on January 1, 2009. EME expects that the adoption of this issue will not have an impact on its consolidated financial statements.

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

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.

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 shorter of the lease term or estimated useful life for leasehold improvements.

As part of the acquisition of the Illinois Plants and the Homer City facilities, EME acquired emission allowances under the US EPA'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 on a straight-line basis.

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 property, plant and equipment.

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

Minimum lease payments under operating leases are levelized (total minimum lease payments divided by the number of years of the lease) and recorded as rent expense over the terms of the leases. Lease payments in excess of the minimum are recorded as rent expense in the year incurred. Operating leases primarily consist of long-term leases for the Powerton, Joliet and Homer City power plants. See Note 12—Commitments and Contingencies—Lease Commitments, for additional information on these sale-leaseback transactions.

Certain cash balances are restricted primarily to pay amounts required for lease payments and to provide collateral. The total restricted cash included on EME's consolidated balance sheet was $43 million at December 31, 2008 and $48 million at December 31, 2007. Included in restricted cash was $30 million at each of December 31, 2008 and 2007 related to lease payments and collateral reserves of $13 million and $18 million at December 31, 2008 and 2007, respectively.

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 in operating revenues in the accompanying consolidated income statements. 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 SFAS No. 133 and does not qualify for the normal sales and purchases exception.

In addition, revenues under certain long-term power sales contracts subject to Emerging Issues Task Force No. 91-6, "Revenue Recognition of Long-term Power Sales Contracts," are recognized based on the output delivered at the lower of the amount billable or the average rate over the contract term. The excess of the amounts billed over the portion recorded as revenue is reflected in deferred revenues in the consolidated balance sheet.

Edison International's stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units have been granted to EME employees under Edison International's long-term incentive compensation programs. Edison International usually does not issue new common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of option exercises, performance shares, and restricted stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Deferred stock units granted to management are settled in cash, not stock and represent a liability. Restricted stock units are settled in common stock; however, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

On April 26, 2007, Edison International's shareholders approved a new incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. No additional awards were granted under Edison International's prior stock-based compensation plans on or after April 26, 2007, and all future issuances will be made under the new plan. The maximum number of shares of Edison International's common stock that may be issued or transferred pursuant to awards under the new incentive plan is 8.5 million shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued. As of December 31, 2008, Edison International had approximately 5.8 million shares remaining for future issuance under its stock-based compensation plan. For further discussion, see Note 11—Compensation and Benefit Plans—Stock-Based Compensation.

SFAS No. 123(R) requires companies to use the fair value accounting method for stock-based compensation. EME implemented SFAS No. 123(R) in the first quarter of 2006 and applied the modified prospective transition method. Under the modified prospective method, SFAS No. 123(R) was applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not restated under this method. The accounting standard resulted in the recognition of expense for all stock-based compensation awards. In addition, EME elected to calculate the pool of windfall tax benefits as of the adoption of SFAS No. 123(R) based on the method (also known as the short-cut method) proposed in FSP FAS 123(R)-3, "Transition Election to Accounting for the Tax Effects of Share-Based Payment Awards." Prior to adoption of SFAS No. 123(R), EME presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under other operating—liabilities in the consolidated statements of cash flows. SFAS No. 123(R) requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $3 million, $14 million and $7 million of excess tax benefits are classified as financing cash flows in 2008, 2007 and 2006, respectively. Due to the adoption of SFAS No. 123(R), EME recorded a cumulative effect adjustment that increased net income by approximately $0.4 million, net of tax, in the first quarter of 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

Effective January 1, 2006, EME implemented SFAS No. 123(R) that requires companies to use the fair value accounting method for stock-based compensation resulting in the recognition of expense for all stock-based compensation awards. EME recognizes stock-based compensation expense on a straight-line basis over the requisite service period. EME recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, EME recognized stock-based compensation expense over the explicit requisite service period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal requisite service period for the award, stock-based compensation is recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement. If EME recognized stock-based compensation expense for awards granted prior to January 1, 2006, over a period to the date the participant first became eligible for retirement, stock-based compensation would have decreased $0.4 million and $1 million for 2007 and 2006, respectively.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price" in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity's nonperformance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under SFAS No. 157 are:

EME's assets and liabilities carried at fair value primarily consist of derivative contracts and money market funds. Derivative contracts primarily relate to power and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange traded or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. The majority of derivative contracts used for hedging purposes are based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub and AEP/Dayton) adjusted for non-performance risks. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades. The majority of the fair value of EME's derivative contracts determined in this manner are classified as Level 2.

Derivatives that trade infrequently (such as financial transmission rights and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant non-performance risks, as discussed below, and long-term power agreements are classified as Level 3. For illiquid financial transmission rights, EME reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when EME concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where EME cannot verify fair value with observable market transactions, it is

possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

In assessing non-performance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of non-performance. In light of recent market events, EME utilized market prices for credit default swaps in reducing the fair value of derivative assets by $6 million at December 31, 2008.

Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices (unadjusted) in active markets. In 2008, EME had invested $20 million in the Reserve Primary Fund (a money market fund). The Reserve incurred a loss related to debt securities of Lehman Brothers Holdings and had announced liquidation of the Reserve. EME reduced the fair value of the investment by $1 million and transferred the remaining balance into Level 3 during the third quarter of 2008 as observable market prices were not available. During the fourth quarter of 2008, EME received $16 million in settlements resulting in the ending balance of $3 million at December 31, 2008 classified in Level 3.

The following table sets forth EME's financial assets and liabilities that were accounted for at fair value as of December 31, 2008 by level within the fair value hierarchy:

The following table sets forth a summary of changes in the fair value of EME's Level 3 derivative contracts, net for the period ended December 31, 2008:

The increase in the fair value of Level 3 derivative contracts during 2008 is primarily due to load requirements services contracts. The energy price risk related to these contracts was substantially hedged, but such hedge contracts are classified as Level 2 and, therefore, not reflected as an offsetting position in the above table.

The carrying amount of cash and cash equivalents, trade accounts receivables and payables contained on 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 assessing the fair value of EME's long-term obligations, EME primarily uses quoted market prices.

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.

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. EME uses "gross margin at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions of the Illinois Plants, the Homer City facilities, and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures 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, and gross margin at risk measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers 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.

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.

arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME's counterparties.

EME's merchant plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 50%, 51% and 58% of EME's consolidated operating revenues for the years ended December 31, 2008, 2007 and 2006, respectively. Moody's rates PJM's debt Aa3. PJM, an ISO 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 are shared by all other members based upon a predetermined formula. At December 31, 2008 and 2007, EME's account receivable due from PJM was $61 million and $82 million, respectively.

EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 12% and 19% of EME's consolidated operating revenues for the years ended December 31, 2008 and 2007, respectively. Commonwealth Edison's senior unsecured debt ratings are BBB- by S&P and Baa3 by Moody's. At December 31, 2008 and 2007, EME's account receivable due from Commonwealth Edison was $23 million and $20 million, respectively.

For the year ended December 31, 2008, a third customer, Constellation Energy Commodities Group, Inc. accounted for 10% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from EME's merchant plants and largely consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB by S&P and Baa3 by Moody's. At December 31, 2008, EME's account receivable due from Constellation was $22 million.

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:

EME generally engages in energy trading activities in markets where its power plants are located. EME trades power, fuel and transmission using products available over the counter, through exchanges and from ISOs. 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, 2008 and December 31, 2007, are set forth below:

EME recorded net gains of approximately $171 million, $149 million and $137 million in 2008, 2007 and 2006, respectively, arising from energy trading activities reflected in operating revenues on EME's consolidated income statement (including earnings from restructuring non-utility generator contracts). In accordance with Emerging Issues Task Force No. 02-03, "Issues Involved in Accounting for Derivative Contract's Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," EME netted 4.1 million MWh of sales and purchases of physically settled, gross purchases and sales during both 2008 and 2007 and 4.3 million MWh during 2006.

Unrealized gains on cash flow hedges, net of tax, at December 31, 2008, included unrealized gains on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. As EME's hedged positions for continuing operations are realized, $149 million, after tax, of the net unrealized gains on cash flow hedges at December 31, 2008 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase 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, 2011.

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 $7 million, $(41) million and $(6) million in 2008, 2007 and 2006, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in operating revenues on EME's consolidated income statements.

the effective portion of the hedges was $24 million pre-tax ($15 million, after tax) on that date. Since the power contracts are no longer being accounted for as cash flow hedges under SFAS No. 133 and subsequently were terminated, the subsequent change in fair value was recorded as an unrealized loss in 2008 included in operating revenues on EME's consolidated statement of income. Under SFAS No. 133, the pre-tax amount recorded in accumulated other comprehensive income (loss) will be reclassified to operating revenues based on the original forecasted transactions in 2009 ($15 million) and 2010 ($9 million), unless it becomes probable that the forecasted transactions will no longer occur.

EME has established claims in the amount of $48 million related to the contracts terminated with Lehman Brothers Holdings and its subsidiary as described above through the termination provisions of its master netting agreements with a Lehman Brothers Holdings subsidiary. Such claims have been fully reserved and are included net in prepaid expenses and other on EME's consolidated balance sheet.

On March 7, 2006, EME completed the sale of a 25% ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceeds from the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million during the first quarter of 2006.

During the fourth quarter of 2006, EME recorded a tax benefit adjustment of $22 million, which resulted from resolution of a tax uncertainty pertaining to the ownership interest in a foreign project. EME's payment of $34 million during the second quarter of 2006 related to an indemnity to IPM for matters arising out of the exercise by one of its project partners of a right of first refusal resulted in a $3 million additional loss recorded in 2006.

On April 1, 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. The acquisition was accounted for as a transaction between entities under common control. As such, the assets and liabilities of the projects acquired were recorded at historical cost on the acquisition date for a net book value of approximately $76 million. The principal components of the net book value of assets and liabilities at April 1, 2006 are current assets ($8 million), property, plant and equipment, net ($156 million), other non-current assets ($42 million), deferred income ($56 million) and deferred income taxes ($59 million). EME's historical financial statements have been adjusted for all periods presented to reflect the acquisition as though EME had ownership of such projects, including a distribution paid by Edison Capital to its parent in 2005. Summarized results of the projects acquired for periods presented prior to the acquisition date of April 1, 2006 are as follows:

On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. to acquire a 99.9% interest in Wildorado Wind, L.P., which owns a 161 MW wind farm located in the panhandle of northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights, title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the project retained by Cielo. The total purchase price was $29 million. This project started construction in April 2006 and commenced commercial operation during April 2007. The acquisition was accounted for utilizing the purchase method. The fair value of the Wildorado wind project was equal to the purchase price and as a result, the total purchase price was allocated to property, plant and equipment on EME's consolidated balance sheet.

In December 2003, the FASB issued Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities," (FIN 46(R)). 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 criterion, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. EME uses variable interest entities to conduct its business as described below.

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 debt or lease obligations by its subsidiaries and affiliates owning the operating facilities. These project level debt or lease obligations are generally structured as non-recourse to EME, with several exceptions, including EME's guarantee of the Powerton and Joliet leases as part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Illinois Plants. As a result, these project level debt or lease obligations have structural priority with respect to revenues, cash flows and assets of the project companies over debt obligations incurred by EME as a holding company. Distributions to EME from projects are generally only available after all current debt service or lease 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. 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.

EME has purchased a majority interest in a number of wind projects under joint development agreements with third-party developers. At December 31, 2008, EME had majority interests in 15 wind projects with a total generating capacity of 630 MW that had minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. Minority interest holders have key rights over matters such as budgets, incurrence of debt, and sale of the project, and in certain cases, receive a higher allocation of income and losses after a minimum return is earned by EME. In determining that EME was the primary beneficiary, a key factor was the conclusion that the power sales agreements did not constitute a variable interest since the agreements have a fixed unit price and do not absorb expected losses. As a result, the determination of EME as the primary beneficiary was based on the allocation of income and losses with EME expected to earn a majority of the expected gains or absorb the majority of the expected losses based on its ownership interest.

The following table presents summarized financial information of the wind projects that had minority interests held by others consolidated by EME at December 31, 2008:

Assets serving as collateral for the debt obligations had a carrying value of $85 million at December 31, 2008 and primarily consist of property, plant and equipment. The consolidated statement of income and cash flow includes $4 million of pre-tax income and $30 million of operating cash flow related to variable interest entities that are consolidated.

U.S. Wind Force is a development stage enterprise formed to develop wind projects in West Virginia, Pennsylvania and Maryland. In December 2006, a subsidiary of EME entered into a loan agreement with U.S. Wind Force to fund the redemption of a membership interest held by another party, repayment of loans, distributions to equity holders and future development of wind projects. In accordance with FIN 46(R), EME determined that it is the primary beneficiary because it bears more than 50% of expected losses and, accordingly, EME consolidated U.S. Wind Force beginning December 15, 2006. At December 31, 2008 and 2007, the assets consolidated included $3 million and $10 million of intangible assets, respectively, primarily related to project development rights. As project development is completed, the project development rights will be considered part of property, plant and equipment and depreciated over the estimated useful lives of the respective projects.

During 2008 and 2007, EME recorded a write down of $7 million and $6 million, respectively, of capitalized costs related to U.S. Wind Force reflected in "Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits" on EME's consolidated statements of income.

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 PURPA. Prior to the passage of the EPAct 2005, these regulations limited EME's ownership interest in qualifying facilities to no more than 50% due to EME's affiliation with SCE, 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 in which EME exercises significant influence but cannot exercise unilateral control over the operating, funding or construction activities of the project entity. Two of these projects have 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, 2008, entities which EME has accounted for under the equity method had indebtedness of $294 million, of which $128 million is proportionate to EME's ownership interest in these projects.

As of December 31, 2008, EME has five significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. These projects are 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 concluded that the power purchase agreements for these projects represented variable interests in the related projects and, therefore, it was not the primary beneficiary of 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 $326 million as of December 31, 2008 and is classified as investments in unconsolidated affiliates on EME's consolidated balance sheet.

As of December 31, 2008, EME has an 80% interest in the Doga project located in Turkey. EME concluded that the power sales agreement which transfers ownership interest in the natural gas-fired plant to the government-owned off-taker constituted a variable interest and, consequently, EME was not the primary beneficiary. See Note 7—Investments in Unconsolidated Affiliates, for additional information on the Doga project.

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. The difference between the carrying value of these equity investments and the underlying equity in the net

assets amounted to $12 million at December 31, 2008. The differences are being amortized over the life of the energy projects. The following table presents summarized financial information of the investments in unconsolidated affiliates:

At December 31, 2008 and 2007, EME has a 38% ownership interest in a small biomass project that it accounts for under the cost method of accounting as it does not have a significant influence over the project's operating and financial activities. EME believes that the carrying amount at December 31, 2008 and 2007 was not impaired. EME's subsidiaries have provided loans or advances related to certain projects. The loans receivable at December 31, 2006 primarily consisted of a $26 million, 5% interest promissory note, interest payable semiannually, which was paid off in October 2007. The undistributed earnings of equity method investments were $37 million in 2008 and $38 million in 2007.

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

For 2006, the summarized financial information included the Doga project. Effective March 31, 2007, EME accounted for its ownership in the Doga project on the cost method as accumulated distributions exceeded accumulated earnings. Therefore, the Doga project is not included in the balances at December 31, 2007 and only three months for the year ended December 31, 2007. EME has not

estimated the fair value of cost method investments as quoted market prices are not available and the determination of fair value is highly subjective and cannot be readily ascertained.

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

The following table presents, as of December 31, 2008, 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:

The power sales agreements of certain wind projects qualify as operating leases under EITF No. 01-8, "Determining Whether an Arrangement Contains a Lease," and SFAS No. 13, "Accounting for Leases." The carrying amount and related accumulated depreciation of the property of these wind projects totaled $901 million and $62 million, respectively, at December 31, 2008. EME records rental income from wind projects that are accounted for as operating leases as electricity is delivered at rates defined in power sales agreements. Revenue from these power sales agreements were $46 million, $24 million and $10 million in 2008, 2007 and 2006.

In connection with Midwest Generation's financing activities, EME has given a first priority security interest 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 Generation's hedging activities. The amount of assets pledged or mortgaged totaled approximately $2.9 billion at December 31, 2008. 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.

EME applies SFAS No. 143, "Accounting for Asset Retirement Obligations" as interpreted by FIN No. 47, "Accounting for Conditional Asset Retirement Obligations." SFAS No. 143 as interpreted requires entities to record the fair value of a liability for an ARO in the period in which it is incurred, including 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. When an ARO 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.

In November 2008, Midwest Generation completed the asbestos removal and demolition costs related to the Powerton Station ARO. Midwest Generation also has conditional AROs related to asbestos removal and disposal costs at its owned buildings and power plant facilities. EME has not recorded a liability related to these structures because it cannot reasonably estimate fair value of the obligation at this time. The range of time over which EME may settle these obligations in the future (demolition or other method) is sufficiently large to not allow for the use of expected present value techniques.

EME has recorded AROs related to its wind facilities due to site lease obligations to return the land to grade at the end of the respective leases. Wind-related AROs cover site reclamation and turbine and related facility dismantlement. The earliest settlement of any of these obligations is anticipated to be in 2025. However, the operation of an individual facility may impact the timing of the ARO for that facility. Decisions made in conjunction with each facility's operation could extend or shorten the anticipated life depending on improvements and other factors.

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

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, 2008, recourse debt to EME

totaled $4.1 billion and non-recourse project debt totaled $573 million. Long-term obligations consist of the following:

			December 31,

			2008		2007
			(in millions)
Recourse
EME (parent only)
	Senior Notes, net
		due 2009 (7.73%)	$	13	$	13
		due 2013 (7.50%)		500		500
		due 2016 (7.75%)		500		500
		due 2017 (7.00%)		1,200		1,200
		due 2019 (7.20%)		800		800
		due 2027 (7.625%)		700		700
	Credit Agreement due 2012 (weighted average rate of 3.42% at 12/31/08)			376		—
Non-recourse
Due to EME Funding Corp.—Long-Term Obligation due 2008 (7.33%)				—		8
EME CP Holdings Co.
	Note Purchase Agreement due 2015 (7.31%)			67		72
Midwest Generation
	$500 million Credit Facility (weighted average rate of 2.34% at 12/31/08)			475		—
Other				31		30

Subtotal			$	4,662	$	3,823
Less current maturities of long-term obligations				24		17

Total			$	4,638	$	3,806

In 2007, EME issued $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notes due 2019 and $700 million of its 7.625% senior notes due 2027. EME pays interest on the senior notes on May 15 and November 15 of each year, beginning on November 15, 2007. The net proceeds were used, together with cash on hand, to purchase substantially all of EME's outstanding 7.73% senior notes due 2009 and all of Midwest Generation's 8.75% second priority senior secured notes due 2034; repay the outstanding balance of Midwest Generation's senior secured term loan facility; and make a dividend payment of $899 million to MEHC which enabled MEHC to purchase substantially all of its 13.5% senior secured notes due 2008. EME recorded a total pre-tax loss of $160 million ($98 million after tax) on early extinguishment of debt in 2007.

The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, of the senior notes plus a "make-whole" premium. The senior notes are EME's senior unsecured obligations, ranking equal in right of payment to all of EME's existing and future senior unsecured indebtedness, and will be senior to all

of EME's future subordinated indebtedness. EME's secured debt and its other secured obligations are effectively senior to the senior notes to the extent of the value of the assets securing such debt or other obligations. None of EME's subsidiaries have guaranteed the senior notes and, as a result, all the existing and future liabilities of EME's subsidiaries are effectively senior to the senior notes.

During 2007, EME amended its existing $500 million secured credit facility maturing on June 15, 2012, increasing the total borrowings available thereunder to $600 million, and subject to the satisfaction of conditions as set forth in the secured credit facility, EME is permitted to increase the amount available under the secured credit facility to an amount that does not exceed 15% of EME's consolidated net tangible assets, as defined in the secured credit facility. Loans made under this credit facility bear interest, at EME's election, at either LIBOR (which is based on the interbank Eurodollar market) or the base rate (which is calculated as the higher of Citibank, N.A.'s publicly announced base rate and the federal funds rate in effect from time to time plus 0.50%) plus, in both cases, an applicable margin. The applicable margin depends on EME's debt ratings. At December 31, 2008, EME had borrowings outstanding of $376 million, at the applicable margin of 1.50%, and $129 million of letters of credit outstanding under this credit facility. The credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate debt to corporate capital ratio. A failure to meet a ratio threshold could trigger other provisions, such as mandatory prepayment provisions or restrictions on dividends. At December 31, 2008, EME met both these ratio tests.

As security for its obligations under this credit facility, EME 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 proceeds unless an event of default occurs under the credit facility.

During 2007, Midwest Generation also amended and restated its existing $500 million senior secured working capital facility. Borrowings made under this credit facility bear interest at LIBOR + 0.55%, except if average utilized commitments during a period exceed $250 million, in which case the margin increases to 0.65%, which was the case at December 31, 2008. The working capital facility matures in 2012, with an option to extend for up to two years. The working capital facility contains financial covenants which require Midwest Generation to maintain a debt to capitalization ratio of no greater than 0.60 to 1. At December 31, 2008, the debt to capitalization ratio was 0.28 to 1. Midwest Generation uses its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation can also support its hedging activities by granting liens to eligible hedge counterparties. As of December 31, 2008, Midwest Generation had borrowings outstanding of $475 million and $3 million of letters of credit had been utilized under the working capital facility.

Annual maturities on long-term debt at December 31, 2008, for the next five years are summarized as follows: 2009—$24 million; 2010—$12 million; 2011—$14 million; 2012—$867 million; and 2013—$517 million.

As of December 31, 2008, standby letters of credit aggregated to $133 million and were scheduled to expire in 2009.

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:

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

			December 31,

			2008		2007
			(in millions)
Deferred tax assets
	Accrued charges and liabilities		$	122	$	112
	Derivative instruments			—		45
	Deferred income			5		5
	State taxes			4		2
	Other			7		—

		Total		138		164

Deferred tax liabilities
	Basis differences		$	592	$	481
	Derivative instruments			141		—
	Deferred investment tax credit			7		9
	Other			5		4

		Total		745		494

Deferred tax liabilities and tax credits, net			$	607	$	330

Classification of accumulated deferred income taxes:
	Included in current assets		$	—	$	21
	Included in current liabilities		$	66	$	—
	Included in non-current liabilities		$	541	$	351

The total amount of unrecognized tax benefits as of December 31, 2008 and 2007, that, if recognized, would affect the effective tax rate was $122 million and $114 million, respectively. The total amount of accrued interest and penalties was $57 million and $49 million as of December 31, 2008 and

2007, respectively. The total amount of interest expense and penalties recognized in income tax expense was $8 million for each 2008 and 2007. EME and its subsidiaries remain subject to examination by the Internal Revenue Service, the California Franchise Tax Board, and other state authorities from 1994 to present. It is reasonably possible that EME could reach a settlement with the Internal Revenue Service to settle all or a portion of the unrecognized tax benefits through tax year 2002 within the next 12 months. EME is included in the federal consolidated income tax return filed by Edison International. During 2008, the Internal Revenue Service commenced an examination of Edison International's consolidated federal income tax return for the years 2003 through 2006. EME believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $49 million within the next 12 months. Accrued income taxes reflected in accrued liabilities on EME's consolidated balance sheet totaled $128 million and $27 million at December 31, 2008 and 2007, respectively.

A 401(k) plan is maintained to supplement eligible employees' retirement income. The plan received contributions from EME of $15 million in 2008 and $12 million each in 2007 and 2006.

SFAS No. 158 requires companies to recognize the overfunded or underfunded status of a defined benefit pension plan and other postretirement plans as assets or liabilities in their balance sheet; the assets or liabilities are normally offset through other comprehensive income (loss). EME adopted SFAS No. 158 prospectively on December 31, 2006.

Noncontributory defined benefit pension plans (the non-union plan has a cash balance feature) cover most employees meeting minimum service requirements. The expected contributions (all by the employer) are approximately $9 million for the year ended December 31, 2009. The fair value of plan assets is determined primarily by quoted market prices.

Volatile market conditions have affected the value of the trusts established to fund its future long-term pension benefits. The market value of the investments (reflecting investment returns, contributions and benefit payments) within the plan trusts declined significantly during 2008. The reduction in the value of plan assets will result in increased future pension expense and contributions. Changes in the plan's funded status affect the assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. The Pension Protection Act of 2006 establishes new minimum funding standards and restricts plans underfunded by more than 20% from providing lump sum distributions and adopting amendments that increase plan liabilities.

			Years Ended December 31,

			2008			2007
			(in millions)
Change in projected benefit obligation
	Projected benefit obligation at beginning of year		$	196		$	184
	Service cost			13			16
	Interest cost			12			10
	Actuarial gain			(3	)		(7	)
	Benefits paid			(7	)		(7	)

		Projected benefit obligation at end of year	$	211		$	196

Change in plan assets
	Fair value of plan assets at beginning of year		$	134		$	115
	Actual return (loss) on plan assets			(44	)		10
	Employer contributions			16			16
	Benefits paid			(7	)		(7	)

		Fair value of plan assets at end of year	$	99		$	134

Funded status at end of year			$	(112	)	$	(62	)

Amounts recognized in consolidated balance sheets:
Long-term liabilities			$	(112	)	$	(62	)
Amounts recognized in accumulated other comprehensive income (loss):
Prior service cost			$	1		$	1
Net loss (gain)				48			(3	)
Accumulated benefit obligation at end of year			$	180		$	166
Pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation			$	211		$	196
Accumulated benefit obligation				180			166
Fair value of plan assets				99			134
Weighted-average assumptions used to determine obligations at end of year:
Discount rate				6.25%			6.25%
Rate of compensation increase				5.0%			5.0%

Other changes in plan assets and benefit obligations recognized in other comprehensive loss:

The estimated amortization amounts reclassified from other comprehensive loss for 2009 are $0.1 million for prior service costs and $3.5 million for net loss.

The following benefit payments, which reflect expected future service, are expected to be paid:

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. The expected contributions (all by the employer) for the postretirement benefits other than pensions trust are $2 million for the year ended December 31, 2009.

			Years Ended December 31,

			2008			2007
			(in millions)
Change in benefit obligation
	Benefit obligation at beginning of year		$	83		$	76
	Service cost			3			3
	Interest cost			6			5
	Amendments			3			—
	Actuarial loss			6			1
	Benefits paid			(2	)		(2	)

		Benefit obligation at end of year	$	99		$	83

Change in plan assets
	Fair value of plan assets at beginning of year		$	—		$	—
	Employer contributions			2			1
	Benefits paid			(2	)		(1	)

		Fair value of plan assets at end of year	$	—		$	—

Funded status at end of year			$	(99	)	$	(83	)

Amounts recognized in balance sheets:
Long-term liabilities			$	(99	)	$	(83	)
Amounts recognized in accumulated other comprehensive (income) loss:
Prior service credit			$	(3	)	$	(7	)
Net loss				21			16
Weighted-average assumptions used to determine obligations at end of year:
Discount rate				6.25%			6.25%
Assumed health care cost trend rates:
Rate assumed for following year				8.75%			9.25%
Ultimate rate				5.5%			5.0%
Year ultimate rate reached				2016			2015

Other changes in plan assets and benefit obligations recognized in other comprehensive loss:

The estimated amortization amounts reclassified from other comprehensive loss for 2009 are $1 million for prior service credit and $1 million for net loss.

Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of December 31, 2008, by $15 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 benefit obligation as of December 31, 2008, by $13 million and annual aggregate service and interest costs by $1 million.

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. Two corporate yield curves were considered, Citigroup and AON.

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. As a result of the significant increase in global financial markets volatility, during 2008 and in early 2009, the trusts' investment committee approved interim changes in target asset allocations. EME employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches. Risk is managed 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.

Permitted ranges around asset class portfolio weights are plus or minus 3%. 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.

The overall expected long-term rate of return on assets assumption is based on the long-term target asset allocation for plan assets and capital markets return forecasts for asset classes employed. A portion of postretirement benefits other than pensions trust asset returns are subject to taxation, so the expected long-term rate of return for these assets is determined on an after-tax basis.

Capital markets return forecasts are based on a long-term equilibrium forecast from an independent firm, as well as a separate analysis of expected equilibrium returns. The independent firm uses its research and judgment to determine long-term equilibrium forecasts. A core set of macroeconomic variables is used including real GDP growth, personal consumption expenditures, the federal funds target rate, dividend yield, and the treasury yield curve. Fixed income, equity and private equity returns are determined from these factors. In addition, a separate analysis of equilibrium returns is made. 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 and projected data and is consistent with experience over various economic environments. The premium of the broad market over United States government bonds is an historic average premium. The estimated rate of return for equity includes a 3% premium over the estimated total return of intermediate United States government bonds. 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.

Total stock-based compensation expense (reflected in administrative and general on the consolidated statements of income) was $7 million, $10 million and $11 million for 2008, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $3 million, $4 million and $4 million for 2008, 2007 and 2006, respectively.

Under various plans, Edison International has granted stock options at exercise prices equal to the average of the high and low price, and beginning in 2007, at the closing price at the grant date, Edison International may grant stock options and other awards related to or with a value derived from its common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the requisite service period, except for awards granted to retirement-eligible participants, as discussed in Note 1—Stock-Based Compensation. Stock-based compensation expense associated with stock options was $6 million, $6 million and $8 million in 2008, 2007 and 2006, respectively.

Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the option term. Stock options granted in 2008 and 2007 have no dividend equivalent rights. Unless transferred to nonqualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain

dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

The fair value for each option granted was determined as of the grant date using the Black- Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table.

The expected term represents the period of time for which the options are expected to be outstanding and is primarily based on historical exercise and post-vesting cancellation experience and stock price history. The risk-free interest rate for periods within the contractual life of the option is based on a zero coupon U.S. Treasury issued STRIPS (separate trading of registered interest and principal of securities) whose maturity equals the option's expected term on the measurement date. In 2006 to 2008, expected volatility is based on the historical volatility of Edison international's common stock for the most recent 36 months.

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

The weighted-average grant-date fair value of options granted during 2008, 2007 and 2006 was $9.88, $11.36 and $14.44, respectively. The total intrinsic value of options exercised was $6 million, $32 million and $18 million during 2008, 2007 and 2006. At December 31, 2008, there was $5 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately two-and-a-half years. The fair value of options vested during 2008, 2007 and 2006 was $4 million, $6 million and $8 million, respectively.

The amount of cash used by Edison International to settle stock options exercised by EME employees was $11 million, $49 million and $33 million for 2008, 2007 and 2006, respectively. Cash

received by Edison International from options exercised by EME employees for 2008, 2007 and 2006 was $5 million, $19 million and $15 million, respectively. The estimated tax benefit from options exercised was $2 million, $11 million and $7 million for 2008, 2007 and 2006, respectively.

A target number of contingent performance shares were awarded to executives in March 2006, March 2007 and March 2008, and vest at the end of December 2008, 2009 and 2010, respectively. Performance shares awarded in 2005 and 2006 accrue dividend equivalents which accumulate without interest and will be payable in cash following the end of the performance period when the performance shares are paid. Edison International has discretion to pay certain dividend equivalents in Edison International common stock. Performance shares awarded in 2007 and 2008 contain dividend equivalent reinvestment rights. An additional number of target contingent performance shares will be credited based on dividends on Edison International common stock for which the ex-dividend date falls within the performance period. The vesting of Edison International's performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International's common stock performance relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International's ranking among these companies. Dividend equivalents will be adjusted to correlate to the actual number of performance shares paid. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the requisite service period based on the fair values determined, except for awards granted to retirement-eligible participants, as discussed in Note 1—Stock-Based Compensation. Stock-based compensation expense (benefit) associated with performance shares was $(3) million, $3 million and $3 million for 2008, 2007 and 2006, respectively. The amount of cash used to settle performance shares classified as equity awards was $2 million, $5 million and $10 million for 2008, 2007 and 2006, respectively.

The performance shares' fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires a risk-free interest rate and an expected volatility rate assumption. The risk-free interest rate is based on a 52-week historical average of the three-year zero coupon U.S. Treasury issued STRIPS (separate trading of registered interest and principal of securities) and is used as proxy for the expected return for the specified group of companies. Volatility is based on the historical volatility of Edison International's common stock for the recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data services provider.

Edison International's risk-free interest rate used to determine the grant date fair values for the 2008, 2007 and 2006 performance shares classified as share-based equity awards was 3.9%, 4.8% and 4.1%, respectively. Edison International's expected volatility used to determine the grant date fair values for the 2008, 2007 and 2006 performance shares classified as share-based equity awards was 17.4%, 16.5% and 16.2%, respectively. The portion of performance shares classified as share-based liability awards are revalued at each reporting period. The risk-free interest rate and expected volatility rate used to determine the fair value as of December 31, 2008 was 0.8% and 19.2%, respectively, for the 2008 performance shares. The risk-free interest rate and expected volatility rate used to determine the fair value as of December 31, 2007 was 4.3% and 17.1%, respectively, for the 2007 performance shares.

The total intrinsic value of performance shares settled during 2008, 2007 and 2006 was $5 million, $12 million and $19 million, respectively, which included cash paid to settle the performance shares classified as liability awards for 2008, 2007 and 2006 of $2 million, $4 million and $8 million, respectively. At December 31, 2008, there was $1 million (based on the December 31, 2008 fair value of performance shares classified as liability awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of less than two years. The fair value of performance shares vested during 2008, 2007 and 2006 was $0.7 million, $4 million and $7 million, respectively.

A summary of the status of Edison International nonvested performance shares granted to EME employees and classified as equity awards is as follows:

The weighted-average grant-date fair value of performance shares classified as equity awards granted during 2008, 2007 and 2006 was $41.25, $58.01 and $52.86, respectively.

A summary of the status of Edison International nonvested performance shares granted to EME employees and classified as liability awards (the current portion is reflected in accrued liabilities and the long-term portion is reflected in other long-term liabilities on the consolidated balance sheets) is as follows:

EME leases office space, property and equipment under noncancelable lease agreements that expire in various years through 2035.

The minimum commitments do not include contingent rentals with respect to the wind projects which may be paid under certain leases on the basis of a percentage of sales calculation if this is in excess of the stipulated minimum amount.

Operating lease expense amounted to $208 million, $203 million and $201 million in 2008, 2007 and 2006, respectively.

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 $151 million in 2009, $155 million in 2010, $160 million in both 2011 and 2012, and $149 million in 2013, and the total remaining minimum lease payments are $1.5 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 in 2009, $170 million in 2010, and $151 million in each 2011, 2012 and 2013, and the total remaining minimum lease payments are $489 million. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases.

Under the terms of the foregoing sale-leaseback transactions, distributions are restricted by EME's subsidiaries unless specified financial covenants are met. At December 31, 2008, EME's subsidiaries met these covenants. In addition, the lease agreements and the Midwest Generation credit agreement contain covenants that include, among other things, restrictions on the ability of these subsidiaries to 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.

At December 31, 2008, EME's subsidiaries had firm commitments to spend approximately $150 million in 2009 on capital and construction expenditures. The majority of these expenditures primarily relate to the construction of wind projects and environmental improvements at the Illinois Plants. These expenditures are planned to be financed by cash on hand and cash generated from operations.

EME had entered into various turbine supply agreements with vendors to support its wind development efforts. At December 31, 2008, EME had secured 484 wind turbines (942 MW) for use in future projects for an aggregate purchase price of $1.2 billion, with remaining commitments of $706 million in 2009 and $232 million in 2010. One of EME's turbine suppliers has requested an escalation adjustment to its pricing for 2008 and 2009 turbines pursuant to its turbine supply agreement. EME is evaluating the request, and discussions with the supplier are ongoing. At December 31, 2008 and 2007, EME had recorded wind turbine deposits of $327 million and $273 million, respectively, included in other long-term assets on its consolidated balance sheet. Under certain of these agreements, EME may terminate the purchase of individual turbines, or groups of turbines, for convenience. Upon any such termination, EME may be obligated to pay termination charges to the vendor.

In 2008, EME had entered into an agreement to purchase 5 gas-fired turbines (479 MW) for use in the Walnut Creek project. During the fourth quarter of 2008, EME and its subsidiary terminated the turbine supply agreement for the project to preserve capital and recorded a pre-tax charge of $23 million ($14 million, after tax) reflected in "Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits" on EME's consolidated statements of income. EME plans to purchase turbines for the project subject to resolution of uncertainty regarding the availability of required emission credits.

At December 31, 2008, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $638 million in the next four years summarized as follows: 2009—$460 million; 2010—$160 million; 2011—$14 million; and 2012—$4 million.

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the first quarter of 2008 reflected in "Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits" on EME's consolidated statements of income.

At December 31, 2008, 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 nine years, is currently estimated to aggregate $40 million in the next five years, $8 million each year, 2009 through 2013. EME has entered into agreements to re-sell the transportation under this agreement which aggregates $50 million over the same period.

At December 31, 2008, Midwest Generation had contractual commitments for the transport of coal to their respective facilities. 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 PRB. Accordingly, Midwest Generation's contractual obligations for transportation are based on coal volumes set forth in its fuel supply contracts. Based on the committed coal volumes in the fuel supply contracts described above, these minimum commitments are currently estimated to aggregate $396 million in the next two years, summarized as follows: 2009—$236 million and 2010—$160 million.

At December 31, 2008, EME and its subsidiaries were party to a long-term power purchase contract, a coal cleaning agreement, turbine operations and maintenance agreements, and agreements for the purchase of limestone, ammonia and materials for environmental controls equipment. These minimum commitments are currently estimated to aggregate $286 million in the next five years: 2009—$59 million; 2010—$78 million; 2011—$67 million; 2012—$56 million; and 2013—$26 million.

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 takes 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. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV discussed below under "—Contingencies—Midwest Generation New Source Review Notice of Violation" and potential litigation by private groups related to the NOV. 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 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 asbestos claims pending as of February 2003 and related 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 had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2010. There were approximately 222 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2008. Midwest Generation had recorded a $52 million and $54 million liability at December 31, 2008 and 2007, respectively, related to this matter.

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. 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, 2008 and 2007, EME had recorded a liability of $95 million (of which $51 million is classified as a current liability) and $101 million, respectively, related to these matters.

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the CAA. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME Homer City cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.

At December 31, 2008 and 2007, EME's subsidiaries had a $9 million and $3 million receivable, respectively, recorded primarily related to insurance claims from unplanned outages. During 2008, 2007 and 2006, $6 million, $5 million and $11 million, respectively, related to business interruption insurance coverage were recorded and have been reflected in other income (expense), net on EME's consolidated statements of income. EME's subsidiaries received $7 million and $18 million in cash payments related to insurance claims during 2008 and 2007, respectively.

The construction and operation of power plants are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with existing environmental regulatory requirements. However, possible future developments, such as the promulgation of more

stringent environmental laws and regulations, future proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which EME and its subsidiaries conduct their businesses and could require substantial additional capital or operational expenditures or the ceasing of operations at certain of their facilities. There is no assurance that EME's financial position and results of operations would not be materially adversely affected. EME is unable to predict the precise extent to which additional laws and regulations may affect its future operations and capital expenditure requirements.

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 or operational expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by federal and state regulatory authorities.

The federal CAA, state clean air acts, and federal and state regulations implementing such statutes have substantial impacts on power generation facilities, particularly coal-fired plants. Federal environmental regulations require reductions in emissions and require states to adopt implementation plans that are equal to or more stringent than the federal requirements. Compliance with these regulations and SIPs will affect the costs and the manner in which EME conducts its business, and is expected to require EME 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.

The CAIR, issued by the US EPA on March 10, 2005, applies to 28 eastern states and the District of Columbia and is intended to address ozone and fine particulate matter attainment issues by reducing regional NO_X and SO₂ emissions. The CAIR reduces the current CAA Title IV Phase II SO₂ emission allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR also requires reductions in regional NO_X emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. Both Illinois and Pennsylvania have developed SIPs to meet CAIR requirements. The Illinois and Pennsylvania SIPs for the CAIR, with the exception for set-asides of NO_X allowances in Illinois, substantively matched the federal CAIR requirements.

The CAIR was challenged in court by state, environmental and industry groups, and in July 2008 a three-judge panel of the District of Columbia Circuit Court of Appeals issued a decision to vacate the CAIR in its entirety and remand to the US EPA to issue a new rule consistent with the decision once the Court issued its mandate. The decision raised significant questions as to whether the US EPA would be able to design cap-and-trade programs for NO_X and SO₂ that are authorized and consistent with the CAA provisions that address upwind contributions to downwind states' noncompliance with national ambient air quality standards for ozone and fine particulate matter. Following the decision, the US EPA requested that states reinstate the existing "SIP Call" ozone season NO_X cap-and-trade program, which was due to be replaced by the CAIR.

In September 2008, the US EPA and other parties requested a rehearing of the decision by the same three-judge panel or by the full District of Columbia Circuit Court. In December 2008, the Court remanded the CAIR to the US EPA without vacating the rule, "so that the US EPA may remedy CAIR's flaws in accordance with the Court's July 11, 2008 opinion in the case." The practical impact of the remand is that CAIR requirements became effective January 1, 2009 and are to remain in place until the US EPA promulgates a revised rule. The timing and substance of the revised rule are not yet clear. The Court did not set a date by which the US EPA must act on the remand, but the judges noted that they did not intend to grant an indefinite stay of their decision and that the petitioners could bring a petition to the Court if US EPA fails to act in a timely manner. There is substantial uncertainty as to how the US EPA will address the deficiencies identified by the Court and the impact revised regulations will have on SIPs promulgated to implement the CAIR. In addition, the US EPA has allowed states to rely on compliance with the CAIR to satisfy obligations under other CAA programs, including regional haze regulations and reasonably available control technology requirements. Depending on what happens with respect to the CAIR, the Illinois Plants and the Homer City facilities may be subject to additional requirements pursuant to these programs.

The Illinois Plants continue to be subject to the CAIR. EME expects that compliance with the CAIR, and revised or additional state regulations promulgated to comply with a revised CAIR and/or other air regulatory requirements, could result in increased capital expenditures and operating expenses beyond those already required by the CPS discussed below.

In order to comply with the CPS, Midwest Generation shut down Unit 6 at the Waukegan Station on December 31, 2007 and must permanently shut down Units 1 and 2 at the Will County Station by December 31, 2010.

The principal emission standards and control technology requirements for NO_X and SO₂ under the CPS are as described below:

NO_X Emissions—Beginning in calendar year 2012 and continuing in each calendar year thereafter, Midwest Generation must comply with an annual and seasonal NO_X emission rate of no more than 0.11 lbs/million Btu. In addition to these standards, Midwest Generation must install and operate SNCR equipment on Units 7 and 8 at the Crawford Station by December 31, 2015.

SNCR equipment on Unit 6 at the Joliet Station is currently estimated to cost $13 million (both figures are in 2008 dollars). This technology combination represents one possible compliance plan for the NO_X emission rate. Midwest Generation is evaluating other potential solutions that are less costly to meet the NO_X emission rate that combine the use of alternative NO_X removal technologies with certain unit shutdowns.

SO₂ Emissions—Midwest Generation must comply with an overall SO₂ annual emission rate of:

In addition to these standards, Midwest Generation must install and operate the following specific emission control technologies by the dates indicated:

The engineering work at the Powerton Station also included the potential installation of FGD equipment on Units 5 and 6, and Midwest Generation currently estimates approximately $1 billion (in 2008 dollars) of capital expenditures would be required for the FGD equipment at the Powerton Station. Midwest Generation also determined these capital expenditures could be reduced if the construction work sequence of FGD and SCR at the Powerton Station were reversed. The complexity of the Powerton Station installation and construction interferences are representative of the balance of the fleet and Midwest Generation currently estimates approximately $650/kW for any FGD installation it elects to make on other units.

Changes in the cost of labor, equipment, and materials, among other factors, may materially affect the above estimates for SCR, SNCR and FGD equipment.

Decisions to install the improvements described above have not been made. Midwest Generation is still reviewing all technology and unit shutdown combinations, including interim and alternative compliance solutions. These decisions will take into account many factors, including, among others, the effectiveness and cost of various control technologies, the remaining estimated useful life of each affected unit, the market outlook for the prices of various commodities, including electrical energy and capacity, coal and natural gas, availability of financing, and the statutory and regulatory environment including potential GHG regulation. Under current uncertain conditions, Midwest Generation cannot predict the extent to which its interim or long-term compliance with the CPS will result in the retrofit or temporary or permanent suspension or eventual shutdown of a material part of its operating units.

On December 18, 2007, the Pennsylvania Environmental Quality Board approved the Pennsylvania CAIR. This rule has been submitted to the US EPA for approval as part of the Pennsylvania SIP. The Pennsylvania CAIR is substantively similar to the CAIR. EME Homer City will be subject to the federal CAIR rule during 2009 and expects to be able to comply with the NO_X requirement using its existing SCR system. The Pennsylvania CAIR, including both NO_X and SO₂ limits, is expected to become effective in 2010. EME Homer City expects to comply with Pennsylvania CAIR through the continued operation of its scrubber on Unit 3 to reduce SO₂ emissions and the purchase of SO₂ allowances.

By means of a rule published in May 2005, the US EPA established the CAMR, which created the framework for a national, market-based cap-and-trade program to reduce mercury emissions from existing coal-fired power plants to a national cap of 38 tons by 2010 and to 15 tons by 2018, primarily through reductions in mercury achieved by lowering SO₂ and NO_X emissions under the CAIR. States were allowed, but not required, to join the trading program by adopting the CAMR model trading rules. States retained the right to promulgate alternative regulations equivalent to or more stringent than the CAMR cap-and-trade program, as long as the regulations were approved by the US EPA.

At the time that it published the CAMR, the US EPA also published a second rule, formally rescinding its previous finding that mercury emissions from electrical generating facilities had to be regulated as a hazardous air pollutant pursuant to Section 112 of the CAA, which would have imposed technology-based standards on emission sources. Both the CAMR and US EPA's decision to remove oil and coal-fired plants from the list of sources to be regulated under Section 112 of the CAA were challenged in the U.S. Court of Appeals for the D.C. Circuit by various environmental groups and state attorneys general.

On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated both rules and remanded the matter to the US EPA. The United States and the Utility Air Regulatory Group had petitioned the Supreme Court to review the D.C. Circuit's decision, but the United States subsequently filed a motion to withdraw its petition based on a determination by the US EPA to develop a new mercury regulation pursuant to Section 112 of the CAA. On February 23, 2009, the U.S. Supreme Court declined to review the D.C. Circuit's decision.

Until CAMR is replaced by a new mercury rule, mercury regulation will come from state regulatory bodies. As described below, EME's coal-fired electric generating facilities are already subject to significant unit-specific mercury emission reduction requirements under Illinois and Pennsylvania law (although, as noted below, a Pennsylvania court has recently invalidated Pennsylvania's mercury regulations). Until new federal standards are developed, EME will not be able to determine whether it will be necessary to undertake measures beyond those required by state regulations.

The final state rule for the reduction of mercury emissions in Illinois was adopted and became effective on December 21, 2006. The rule requires a 90% reduction of mercury emissions from coal-fired power plants averaged across company-owned Illinois stations and a minimum reduction of 75% for individual generating sources by July 1, 2009. The rule requires each station to achieve a 90% reduction by January 1, 2014 and, because emissions are measured on a rolling 12-month average,

stations must install equipment necessary to meet the January 1, 2014, 90% reduction by January 1, 2013.

Midwest Generation's compliance with the CPS supersedes the mercury rule described above for the Illinois Plants. The principal emission standards and control technology requirements for mercury under the CPS are as described below:

Beginning in calendar year 2015, and continuing thereafter on a rolling 12-month basis, Midwest Generation must either achieve an emission standard of .008 lbs mercury/GWh gross electrical output or a minimum 90% reduction in mercury for each unit (except Unit 3 at the Will County Station, which shall be included in calendar year 2016). In addition to these standards, Midwest Generation must install and operate the following specific control technologies:

Midwest Generation has installed activated carbon injection technology for the removal of mercury in 2008 for Crawford, Fisk and Waukegan Stations and is in the process of installing this technology in 2009 for Joliet, Powerton and Will County Stations. Capital expenditures relating to these controls were $37 million through 2008 and are expected to be $6 million in 2009.

On February 17, 2007, the PADEP published in the Pennsylvania Bulletin regulations that would require coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015. The rule does not allow the use of emissions trading to achieve compliance. The rule became final upon publication. The Pennsylvania CAMR SIP, which embodies PADEP's mercury regulation, was pending approval by the US EPA prior to the February 8, 2008 Court of Appeals decision vacating the federal CAMR. On September 15, 2008, PPL Generation filed a Petition for Review with the Commonwealth Court seeking relief from Pennsylvania's mercury rule for coal-fired power plants, alleging that the PADEP cannot regulate power plant emission sources under Section 111 of the CAA, but must instead consider emission controls on a case-by-case basis as required by Section 112. On January 30, 2009, the Court issued an opinion declaring Pennsylvania's mercury rule unlawful, invalid and unenforceable, and enjoining Pennsylvania from continued implementation and enforcement of the rule. The PADEP has appealed this matter to the Pennsylvania Supreme Court.

If the Homer City facilities are required to meet the 2010 deadline for mercury emissions reductions, EME Homer City would plan to achieve compliance by operating an existing FGD system on one generating unit and utilizing an appropriate combination of sorbent injection and coal washing on the other two units. In order to meet reductions in emissions by the 2015 deadline, it is likely that additional environmental control equipment will need to be installed. If additional environmental equipment is required in the form of FGD equipment, EME would need to make commitments during 2011 or 2012. EME continues to study available environmental control technologies and estimated costs to reduce SO₂ and mercury and to monitor developments related to mercury and other environmental regulations.

The US EPA designated non-attainment areas for its 8-hour ozone standard on April 30, 2004, and for its fine particulate matter 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.

On September 22, 2006 the US EPA issued a final rule that implements the revisions to its fine particulate standard originally proposed on January 17, 2006. Under the new rule, the annual standard remains the same as originally proposed but the 24-hour fine particulate standard is significantly more stringent. On February 24, 2009, the U.S. Court of Appeals for the D.C. Circuit remanded the annual fine particulate matter standard to the US EPA for review. The more stringent 24-hour fine particulate standard (and, depending on the course of the remand, a further revised annual standard) may require states to impose further emission reductions beyond those necessary to meet the existing standards. EME anticipates that any such further emissions reduction obligations would not be imposed under this standard until 2015 at the earliest, and intends to consider such rules as part of its overall plan for environmental compliance.

On March 12, 2008, the US EPA issued a final rule to make revisions to the primary and secondary national ambient air quality standards for ozone. With regard to the primary and standards for ozone, the US EPA reduced the level of the 8-hour standard to 0.075 parts per million (ppm). The US EPA solicited comment on alternative levels down to 0.060 ppm and up to and including retaining the current 8-hour standard of 0.08 ppm (effectively 0.084 ppm using current data rounding conventions). The rule may require states to impose further emission reductions beyond those necessary to meet the existing standards. EME anticipates that any such further emission reduction obligations would not be imposed under this standard until 2015 at the earliest, and intends to consider such rules as part of its overall plan for environmental compliance.

Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NO_X emission rate of 0.25 lb NO_X/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 "NO_X SIP Call" regulation that provided ozone-season NO_X emission allowances to a 19-state region east of the Mississippi. This program provides for NO_X allowance trading similar to the SO₂ (acid rain) trading program already in effect.

The Illinois Plants have complied with the NO_X regulations by installing advanced burner technology and by purchasing additional allowances. Midwest Generation plans to continue to purchase allowances as it implements the agreement it reached with the Illinois EPA, but expects to purchase fewer allowances as the required technology improvements are implemented.

The Illinois EPA has begun to develop SIPs to meet National Ambient Air Quality Standards for 8-hour ozone and fine particulates with the intent of bringing non-attainment areas, such as Chicago, into attainment. The SIPs are expected to deal with all emission sources, not just power generators, and to address emissions of NO_X, SO₂, and volatile organic compounds. The SIP for 8-hour ozone was to be submitted to the US EPA by June 15, 2007, but is currently expected to be submitted in early 2009. The SIP for fine particulates was to be submitted to the US EPA by April 5, 2008, but is currently expected to be submitted in 2010.

The CPS requires Midwest Generation to install air pollution controls that will contribute to attainment with the ozone and fine particulate matter per National Ambient Air Quality Standards. EME does not know at this time whether the reductions required by the CPS will be sufficient for compliance with future ozone and particulate matter regulations. See "—Clean Air Interstate Rule—Illinois" for further discussion.

In March 2007, the PADEP requested a redesignation of Clearfield and Indiana counties to attainment with respect to the 8-hour ozone standard. The PADEP also submitted a maintenance plan indicating that the existing (and upcoming) regulations controlling emissions of volatile organic compounds and NO_X will result in continued compliance with the 8-hour ozone standard. The US EPA accepted the plan on August 1, 2007. Accordingly, EME believes that the Homer City facilities will likely not need to install additional pollution control as a result of the 8-hour ozone standard.

With respect to fine particulates, Pennsylvania submitted the SIP to the US EPA on December 7, 2007. EME does not believe at this time that it will impose more stringent requirements than those already applicable to the Homer City facilities.

In July 1999, the US EPA published the "Regional Haze Rule" to reduce haze and protect visibility in designated federal areas. The goal of the 1999 rule is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions by 2064. 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. The US EPA issued a final rulemaking on regional haze on June 15, 2005.

States were required to revise their SIPs by December 2007 to demonstrate reasonable further progress towards meeting regional haze goals. On January 9, 2009, the US EPA found that 37 states, including Illinois and Pennsylvania, had failed to submit all or a portion of their regional haze SIPs. For those states that have yet to make a submission, or that have made a submission that does not include particular SIP elements, the US EPA is making a "finding of failure to submit." The US EPA finding initiates a two-year deadline for issuance of a Federal Implementation Plan which would provide the basic program requirements for each state that has not completed an approved plan of its own by January 15, 2011. Emission reductions 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. It is possible that sources subject to the CAIR will be able to satisfy their obligations under the regional haze regulations through compliance with the CAIR although, as previously noted, the D.C. Circuit Court's decision to remand the CAIR to the US EPA means that there is substantial uncertainty as to the future of the federal and state CAIR programs. However, until the SIPs 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.

The CPS, discussed above in "—Clean Air Interstate Rule—Illinois," addresses emissions reductions at BART affected sources. In Pennsylvania, the PADEP considers the CAIR to meet the BART requirements, and the Homer City facilities are only required to consider reductions in emissions of suspended particulate matter (PM10), which at this time are being evaluated by the state.

Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address CAA NSR compliance issues at the nation's coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at a facility. The US EPA's strategy has included both the filing of suits against a number of power plant owners, and the issuance of administrative notices of violation to a number of power plant owners alleging NSR violations.

Prior to EME's purchase of the Homer City facilities, the US EPA requested information under Section 114 of the CAA 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 CAA NSR requirements. In 2003, Midwest Generation and Commonwealth Edison received requests for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois Plants from the US EPA. In 2005, the US EPA submitted a request for additional information to Midwest Generation. Midwest Generation provided responses to these requests. On November 18, 2008, the US EPA and DOJ issued supplemental Section 114 requests to EME, Midwest Generation and Commonwealth Edison. EME and Midwest Generation have made an initial response to the requests and are working on a follow-up response to the requests.

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that Midwest Generation and Commonwealth Edison violated various provisions of the NSR rules as well as state air regulations at the Illinois Plants. On June 12, 2008, EME Homer City received an NOV from the US EPA. The EME Homer City NOV alleges that certain construction projects, all completed before EME Homer City acquired the Homer City facilities, violated various provisions of the NSR rules and Title V permit requirements. Discussions with the US EPA, the DOJ as well as state enforcement officials and environmental groups are under way. See "—Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Notice of Violation" and "EME Homer City New Source Review Notice of Violation" for further discussion.

Regulations under the federal Clean Water Act require permits for the discharge of pollutants into United States waters and permits for the discharge of storm water flows from certain facilities. The Clean Water Act also regulates the thermal component (heat) of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities.

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 large power plants. The purpose of the regulation was to reduce substantially the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems. Depending on the findings of the demonstration studies contemplated by the rule to demonstrate the costs and benefits of compliance, cooling towers and/or other mechanical means of reducing impingement and entrainment of aquatic organisms could have been required.

On January 27, 2007, the Second Circuit rejected the US EPA rule and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost benefit and restoration to achieve compliance with the rule. On July 9, 2007, the US EPA suspended the requirements for cooling water

intake structures, pending further rulemaking. On December 2, 2008 the Supreme Court heard oral arguments on this case. A decision is expected during the first half of 2009. The US EPA has delayed rulemaking pending the decision of the court. EME has collected impingement and entrainment data at its potentially affected Midwest Generation facilities in Illinois to begin the process of determining what corrective actions might need to be taken under the previous rule. Because there are no defined compliance targets absent a new rule, EME is currently in the process of generally reviewing a wide range of possible control technologies. Although the rule to be generated in the new rulemaking process could have a material impact on EME's operations, until the final compliance criteria have been published, EME cannot reasonably determine the financial impact.

The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 FGD 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 the PADEP that it was included in the Quarterly Noncompliance Report submitted to the US EPA. EME Homer City and the PADEP have entered into a consent order and agreement related to selenium discharge, which was entered by the Pennsylvania state court on July 17, 2007. Under the consent order and agreement, EME Homer City paid a civil penalty of $200,000 and agreed to install modifications to its wastewater system to achieve consistent compliance with discharge limits. EME Homer City has experienced very few exceedances since entering into the consent order and agreement.

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. 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 $4 million at December 31, 2008 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 investigation and/or remediation 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.

US EPA regulations currently classify coal combustion wastes as solid wastes that are exempt from hazardous waste requirements under what is known as the Bevill Amendment. The exemption applies to fly ash, bottom, slag, and flue gas emission control wastes generated from the combustion of coal or other fossil fuels. The US EPA has studied coal combustion wastes extensively and in 2000 concluded that fossil fuel combustions wastes do not warrant regulation as a hazardous waste under Subtitle C of the Resource Conservation and Recovery Act. However, the US EPA also concluded, in 2000 and again in a 2007 Notice of Data Availability and request for public comment, that coal combustion wastes disposed of in surface impoundments and landfills, or used for minefill, do require regulation under Subtitle D (as solid wastes) under the Resource Conservation and Recovery Act. The current classification of coal combustion wastes as exempt from hazardous waste requirements enables beneficial uses of coal combustion wastes, such as for cement production and fill materials. The Illinois Plants currently sell a significant portion of their coal combustion wastes for beneficial uses.

Legislation has been introduced in the U.S. House of Representatives and the US EPA is reviewing options for regulation of coal ash. The US EPA and many state regulatory agencies, including the Illinois EPA and the PADEP, are reviewing existing ash storage and disposal units and the adequacy of existing regulatory standards. EME is monitoring state legislative and regulatory activity, specifically in Illinois, Pennsylvania and West Virginia, but cannot predict the outcome of this activity.

Additional regulation of the storage, disposal, and beneficial uses of coal combustion wastes would affect the costs and the manner in which EME conducts its business, and would likely require EME to make additional capital expenditures with no assurance that the increased costs could be recovered from customers.

To date, the United States has pursued a voluntary GHG emissions reduction program to meet its obligations as a signatory to the United Nations Framework Convention on Climate Change. As a result of increased attention to climate change in the U.S., however, numerous bills have been introduced in

recent sessions of the U.S. Congress that would reduce GHG emissions in the U.S. Enactment of climate change legislation within the next several years now seems likely. However, there is still significant uncertainty about the cost of complying with any future GHG emission requirements. These costs will depend upon many factors, including the required levels of GHG emission reductions, the timing of those reductions, the impact on fuel prices, whether emission allowances will be allocated with or without cost to existing generators, and whether flexible compliance mechanisms, such as a GHG offset program similar to those sanctioned under the CAA for conventional pollutants, will be part of the policy.

While debate continues at the national level over domestic climate policy and the appropriate scope and terms of any federal legislation, many states are developing state-specific measures or participating in regional legislative initiatives to reduce GHG emissions. At this point, EME is unable to determine whether any of these proposals will be enacted into law or to estimate their potential effect on EME.

On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap-and-trade GHG program for electric generators, referred to as the Regional Greenhouse Gas Initiative (RGGI). In August 2006, the participating states issued a model rule to be used as a basis for individual state legislative and regulatory action to implement the program. The RGGI states (now numbering ten states) have passed laws and/or regulations to implement the RGGI program, which commenced in 2009. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania has participated as an observer of the process.

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington launched the Western Climate Initiative to develop regional strategies to address climate change. The Western Climate Initiative is identifying, evaluating and implementing collective and cooperative ways to reduce GHG in the region. In the spring of 2007, the Governor of Utah and the Premiers of British Columbia and Manitoba joined the Initiative. Other states and provinces have joined as observers. The Initiative partners set an overall regional goal in August 2007 for reducing GHG emissions to 15% below 2005 levels by 2020. By August 2008, these partners expect to complete the design of a market-based mechanism to help achieve that reduction goal.

On November 15, 2007, Illinois became a party to the Midwestern Accord, in which six of the twelve states in the Midwestern Governors' Association, along with the Province of Manitoba, have agreed to seek to develop regional GHG emission reduction goals within one year and to develop a multi-sector cap-and-trade program to achieve these goals. The accord called for such a program to be implemented in 30 months. On February 19, 2008, the six participating states announced that they would complete a model rule by the end of 2008 to create the framework for the cap-and-trade program, a schedule which has since been revised to fall 2009. Once this model rule has been drafted, each of the participating states could adopt the program through legislative action, executive order or other appropriate means. In February 2007, prior to the development of the Midwestern Accord, then-Illinois Governor Blagojevich announced a goal to reduce Illinois' GHG emissions to 1990 levels by 2020 and to 60% below 1990 levels by 2050.

Implementing regulations for such regional initiatives are likely to vary from state to state and may be more stringent and costly than federal legislative proposals currently being debated in the U.S. Congress. It cannot yet be determined whether or to what extent any federal legislative system would preempt regional or state initiatives, although such preemption would greatly simplify compliance and eliminate regulatory duplication. If state and/or regional initiatives are allowed to stand together with

federal legislation, generators could be required to purchase allowances to satisfy their state and federal compliance obligations.

In September 2006, California enacted two laws regarding GHG emissions. The first, known as AB 32 or the California Global Warming Solutions Act of 2006, establishes a comprehensive program of regulatory and market mechanisms to achieve reductions of GHG emissions. AB 32 requires the California Air Resources Board to develop regulations and market mechanisms targeted to reduce California's GHG emissions to 1990 levels by 2020. The California Air Resources Board's mandatory program will take effect commencing 2012 and will implement incremental reductions so that GHG emissions will be reduced to 1990 levels by 2020.

The second law, known as SB 1368, required the California Public Utilities Commission and the California Energy Commission to adopt GHG emissions performance standards for investor-owned and publicly owned utilities, respectively, for long-term procurement of electricity. The standards must equal the performance of a combined-cycle gas turbine generator. The California Public Utilities Commission adopted such a standard on January 25, 2007 (which limits emissions to 1,100 pounds of carbon dioxide per MWh). On August 29, 2007, the California Energy Commission adopted regulations pursuant to SB 1368 establishing and implementing GHG emissions performance standards for baseload generation of local publicly owned electric utilities. Utility purchases of power generated by EME's facilities in California are subject to the emissions performance standards established in SB 1368.

In addition, the California Public Utilities Commission is addressing climate change related issues in various regulatory proceedings. At this time, EME believes that all of its facilities in California meet the GHG emissions performance standard contemplated by SB 1368, but EME will continue to monitor both regulations, as they are developed, for potential impact on its existing facilities and its projects under development.

Climate change regulation may be affected by litigation in federal and state courts. For example, on April 2, 2007, the United States Supreme Court issued an opinion in Massachusetts et al. v. Environmental Protection Agency, et. al., ruling that the US EPA has the authority to regulate GHG emissions of new motor vehicles under the CAA and that it has a duty to determine whether GHG emissions of new motor vehicles contribute to climate change or offer a reasoned explanation for its failure to make such a determination when presented with a request for a rulemaking on the issue by the state claimants. The Court ruled that the US EPA's failure to make the necessary determination or offer a reasonable explanation for its refusal to do so was impermissible. While this case hinged on a provision of the CAA related to emissions of motor vehicles, a parallel provision of the CAA applies to stationary sources such as electric generators, and there is litigation pending in the D.C. Circuit Court of Appeals, Coke Oven Task Force v. Environmental Protection Agency, in which the holding in Massachusetts v. Environmental Protection Agency, et al., may be applied to stationary sources such as power plants. In July 2008, the US EPA issued an advanced notice of proposed rulemaking that presented relevant information and solicited public comment as to how the US EPA should respond to the Massachusetts case, but the US EPA did not take further action on this rulemaking prior to the end of President Bush's term in office.

On December 19, 2007, the Administrator of the US EPA announced that the US EPA would not grant the waiver that California had been seeking under established CAA procedures to implement

stringent GHG emission reduction requirements for motor vehicles. At least 16 other states have adopted or announced plans to adopt California's regulations. On January 2, 2008, California sued the US EPA in the 9th Circuit U.S. Court of Appeals challenging the decision to deny California's request for a waiver. In January 2009, President Obama ordered the US EPA to review its denial of California's waiver application. While these developments apply only to automotive sources of GHG emissions, they reflect heightened regulatory scrutiny of, and public concern about, GHG emissions across all sectors of the economy, including power generation.

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. In another case brought in April 2006, private citizens filed a complaint in the federal court in Mississippi against numerous defendants, including several electric utilities, arguing that emissions from the defendants' facilities contributed to climate change and seeking monetary damages related to the 2005 hurricane season. In August 2007, the court dismissed the case entirely. The plaintiffs have appealed this dismissal in the Fifth Circuit Court of Appeals.

On October 18, 2007, the Kansas Department of Health and Environment rejected a permit to construct two proposed coal-fired electrical generators based on the impact to health and the environment arising from the proposed units' emissions of carbon dioxide. This was the first reported rejection of a proposed coal plant permit based on a clean air statute. This decision has been appealed. In addition, there are a number of pending cases in which environmental groups are arguing that air permits for the construction of major coal-fired generating facilities cannot be issued unless the permits include best available control technology to control carbon dioxide emissions. The US EPA has taken the position that such controls are not required until it finalizes regulations relating to carbon dioxide emissions.

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 or that would impose additional costs or charges for the emission of carbon dioxide could have a materially adverse effect on EME. EME will continue to monitor the federal, regional and state developments relating to regulation of GHG emissions to determine their impact on its operations. Requirements to reduce emissions of carbon dioxide and other GHG emissions could significantly increase the cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power.

Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or SCE 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 SCE 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 made reimbursements for the cost of these programs and other services, which amounted to $66 million, $76 million and $69 million in 2008, 2007 and 2006,

respectively. At December 31, 2008 and 2007, the amount due to Edison International was $15 million and $3 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 1. Under these agreements, EME recognized tax liabilities applicable to continuing operations of $128 million, $152 million and $81 million for 2008, 2007 and 2006, respectively. See Note 10—Income Taxes. At December 31, 2008 and 2007, amounts included in receivables from affiliates associated with the tax-allocation agreements totaled $4 million and $20 million, respectively.

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 incentive compensation as set forth in the agreements. EME recorded revenues under the operation and maintenance agreements of $31 million for 2008, $30 million for 2007 and $26 million for 2006. Receivables from affiliates for Edison Mission Operation & Maintenance totaled $10 million and $11 million at December 31, 2008 and 2007, respectively.

In connection with certain wind projects acquired during the past three years, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments or made payments that were due upon commencement of construction and/or completion of construction scheduled during 2007 through 2009.

During the year ended December 31, 2006, EME received a capital contribution of $76 million in the form of ownership interests in a portfolio of wind projects and a small biomass project. Refer to Note 6—Acquisitions and Variable Interest Entities—Transfer of Wind Projects from an Affiliate, for further discussion.

The Edison International Ethics and Compliance Code is applicable to all directors, officers and employees of Edison International and its majority-owned subsidiaries, including EME. The Code is available on the Internet website maintained by EME's ultimate parent, Edison International, at www.edisonethics.com and is available in print without charge upon request from Edison International's Corporate Secretary. Any amendments or waivers of Code provisions for EME's principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, will be posted on Edison International's Internet website at www.edisonethics.com.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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, 2008 and December 31, 2007, by PricewaterhouseCoopers LLP:

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 Committee has delegated such pre-approval responsibilities to the Committee Chair. 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, 2008, 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.

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 filed October 4, 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 filed October 29, 2001.
	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.
	3.1.2		Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy, dated August 8, 2007, incorporated by reference to Exhibit 3.1.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2007.

Exhibit No.			Description

	3.2		Amended By-Laws of Edison Mission Energy, dated April 1, 2008, incorporated by reference to Exhibit 3.2 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2008.
	4.1		Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
	4.1.1		First Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
	4.1.2		Second Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed May 10, 2007.
	4.1.3		Third Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.3 to Edison Mission Energy's Form 8-K filed May 10, 2007.
	4.1.4		Fourth Supplemental Indenture, dated as of August 22, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.4 to Edison Mission Energy's Form S-4 filed September 10, 2007.
	4.2		Second Supplemental Indenture, dated as of April 30, 2007, between Edison Mission Energy and The Bank of New York, as trustee, supplementing the Indenture, dated as of June 28, 1999, pursuant to which Edison Mission Energy's 7.73% Senior Notes due 2009 were issued, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 1, 2007.
	4.3		Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed June 8, 2006.
	4.3.1		First Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed June 8, 2006.
	4.3.2		Second Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed June 8, 2006.
	4.4		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.

Exhibit No.			Description

	4.4.1		Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.4 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.
	4.5		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.
	4.5.1		Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.5 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.
	4.6		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.
	4.6.1		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.6 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.
	4.7		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.
	4.7.1		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.7 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.
	4.8		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.
	4.8.1		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.
	4.9		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.

Exhibit No.			Description

	4.9.1		Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
	4.10		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.
	4.10.1		Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.10 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.
	4.10.2		Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.10 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.
	4.11		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.
	4.11.1		Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.11 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†		Purchase & Reservation Agreement, dated as of June 4, 2007, between Edison Mission Energy and Suzlon Wind Energy Corporation, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2007.
	10.2†		Supply Agreement, dated as of March 28, 2007, between Edison Mission Energy and Mitsubishi Power Systems Americas, Inc., incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2007.
	10.3		Credit Agreement, dated as of June 15, 2006, between 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 10.1 to Edison Mission Energy's Form 8-K filed June 21, 2006.
	10.3.1		Amendment No. 1 to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.3 herein), dated as of May 7, 2007, among Edison Mission Energy, the Lenders party thereto, the Issuing Lenders party thereto, and Citigroup North America Inc., as administrative agent, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
	10.4		Credit Agreement, dated as of April 27, 2004 among Midwest Generation, LLC, 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 4.3 to Midwest Generation, LLC's Form 10-Q for the quarter ended March 31, 2004.

Exhibit No.			Description

	10.4.1		First Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated as of April 18, 2005 among Midwest Generation, LLC, the Lenders referred to therein the Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended March 31, 2005.
	10.4.2		Second Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated as of December 15, 2005, among Midwest Generation, LLC, the 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 10.6.2 to Midwest Generation, LLC's Form 10-K for the year ended December 31, 2005.
	10.4.3		Third Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated June 29, 2007, among Midwest Generation, LLC and the Lenders referred to therein and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended June 30, 2007.
	10.5		Security Agreement, dated as of June 15, 2006, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.2 to Edison Mission Energy's Form 8-K filed June 21, 2006.
	10.6		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.
	10.7		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.
	10.8		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.
	10.9		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.
	10.10		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.
	10.11		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.

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.

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.

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Balance Sheets
(In millions)

	December 31,

	2008		2007
Assets
Cash and cash equivalents	$	749	$	664
Short-term investments		1		81
Affiliate receivables		36		16
Other current assets		9		32

Total current assets		795		793
Investments in subsidiaries		7,363		6,404
Other long-term assets		657		512

Total Assets	$	8,815	$	7,709

Liabilities and Shareholder's Equity
Accounts payable and accrued liabilities	$	77	$	94
Affiliate payables		498		517
Current maturities of long-term debt		13		—

Total current liabilities		588		611
Long-term obligations		4,076		3,713
Long-term affiliate debt		1,352		1,356
Deferred taxes and other		115		106

Total Liabilities		6,131		5,786
Common Shareholder's Equity		2,684		1,923

Total Liabilities and Shareholder's Equity	$	8,815	$	7,709

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Income
(In millions)

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Cash Flows
(In millions)

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, 2008
Uncollectible accounts
	Customers	$	2	$	—	$	—		$	—	$	2
	All others		—		—		48	(1)		—		48

Total		$	2	$	—	$	48		$	—	$	50

Year Ended December 31, 2007
Uncollectible accounts
	Customers	$	2	$	—	$	—		$	—	$	2

Total		$	2	$	—	$	—		$	—	$	2

Year Ended December 31, 2006
Uncollectible accounts
	Customers	$	4	$	—	$	—		$	2	$	2
	All others		3		—		—			3		—

Total		$	7	$	—	$	—		$	5	$	2


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)


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý		Smaller reporting company o


SFAS No. 158		Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Post-Retirement Plans"
SFAS No. 161		Statement of Financial Accounting Standards No. 161, "Disclosures About Derivative Instruments and Hedging Activities" (an amendment of FASB No. 133)
SIP(s)		state implementation plan(s)
SNCR		selective non-catalytic reduction
SO₂		sulfur dioxide
US EPA		United States Environmental Protection Agency



EME	B1	BB-	BB-
Midwest Generation(1)	Baa3	BB+	BBB-
EMMT	Not Rated	BB-	Not Rated

		2009		2010		2011		2012		2013

		(in millions)
Debt service(1)
	Third parties	$	297	$	284	$	284	$	653	$	751
	Midwest Generation		117		117		120		121		122
Turbine commitments			706		232		—		—		—


CBPC	Corn Belt Power Cooperative	PC	PacifiCorp
CDWR	California Department of Water Resources	PG&E	Pacific Gas & Electric Company
CECG	Constellation Energy Commodities Group, Inc.	PJM	PJM Interconnection, LLC
ERCOT	Electric Reliability Council of Texas	PSCO	Public Service Company of Oklahoma
IPLC	Interstate Power and Light Company	PSE	Puget Sound Energy, Inc.
LIPA	Long Island Power Authority	SCE	Southern California Edison Company
MEC	Mid-American Energy Company	SPS	Southwestern Public Service
MPC	Monongahela Power Company	TEDAS	Türkiye Elektrik Dagitim Anonim Sirketi
MRES	Missouri River Energy Services	WFEC	Western Farmers Electric Cooperative
NSPC	Northern States Power Company

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
Sunrise	Fellows, California	Leased	Combined cycle generation facility
Watson	Carson, California	Leased	Natural gas-turbine cogeneration facility

		Page

Management's Overview; Critical Accounting Policies and Estimates			41
Results of Operations			50
Liquidity and Capital Resources			64
Market Risk Exposures			85

		Page

Results of Continuing Operations			50
Results of Discontinued Operations			63
Related Party Transactions			63
New Accounting Pronouncements			63

		Page

EME's Liquidity			64
Business Development			65
Capital Expenditures			66
EME's Historical Consolidated Cash Flow			68
Credit Ratings			70
Margin, Collateral Deposits and Other Credit Support for Energy Contracts			70
EME's Liquidity as a Holding Company			71
Dividend Restrictions in Major Financings			74
Contractual Obligations, Commitments and Contingencies			76
Off-Balance Sheet Transactions			81
Environmental Matters and Regulations			84

	EME			Midwest Generation

	(in millions)
Commitment	$	600		$	500
Less: Commitment from Lehman Brothers subsidiary		(36	)		—

		564			500
Outstanding borrowings		(376	)		(475	)
Outstanding letters of credit		(129	)		(3	)

Amount available	$	59		$	22

		2009		2010		2011

		(in millions)
Illinois Plants
	Plant capital expenditures	$	65	$	106	$	76
	Environmental expenditures		48		(a)		(a)
Homer City Facilities
	Plant capital expenditures		29		55		29
	Environmental expenditures		8		14		32
New Projects
	Projects under construction		73		—		—
	Turbine commitments		706		232		—
Other capital expenditures			35		9		7

Total		$	964	$	416	$	144

	Years Ended December 31,

	2008		2007		2006(1)
	(in millions)
Payment of interest	$	31	$	69	$	—
Payment of principal		79		118		—

Subordinated revolving loan payments		110		187		—
Tax payments under tax-allocation agreements		15		—		—

Total payments	$	125	$	187	$	—

Subsidiary	Financial Ratio	Covenant	Actual

Midwest Generation (Illinois Plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.28 to 1
EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.05 to 1

Financial Ratio	Covenant	Actual

Interest Coverage Ratio	Not less than 1.2 to 1	1.98 to 1
Corporate Debt to Corporate Capital Ratio	Not more than 0.75 to 1	0.60 to 1

Power Station(s)	Acquisition Price		Equity Investor	Original Equity Investment in Owner/Lessor		Amount of Lessor Debt at December 31, 2008

				(in millions)
Powerton/Joliet	$	1,367	PSEG/Citigroup, Inc.	$	238	$	119 679	Series A Series B	2009 2016
Homer City		1,591	GECC/ Metropolitan Life Insurance Company		798	$	237 510	Series A Series B	2019 2026

Years Ending December 31,	Principal Amount		Interest Amount		Total

	(in millions)
2009	$	5	$	112	$	117
2010		5		112		117
2011		9		111		120
2012		11		110		121
2013		12		110		122
Thereafter		1,310		181		1,491

Total	$	1,352	$	736	$	2,088

		Page

Commodity Price Risk			85
Accounting for Energy Contracts			94
Fair Value of Financial Instruments			96
Credit Risk			98
Interest Rate Risk			100

	24-Hour Northern Illinois Hub Forward Energy Prices(1)

	2009		2010
January 31, 2008	$	52.30	$	53.14
February 29, 2008		57.29		56.45
March 31, 2008		55.48		55.50
April 30, 2008		56.80		49.14
May 31, 2008		57.03		52.10
June 30, 2008		62.17		56.08
July 31, 2008		52.48		50.94
August 31, 2008		50.49		49.30
September 30, 2008		48.03		48.52
October 31, 2008		42.03		43.10
November 30, 2008		41.43		42.45
December 31, 2008		38.59		39.55

		2009				2010				2011

		GWh		Average price/ MWh		GWh		Average price/ MWh		GWh		Average price/ MWh
Energy Only Contracts(1)
	Northern Illinois Hub—AEP/Dayton Hub		9,945	$	65.44		6,555	$	68.61		612	$	76.40
Load Requirements Services Contracts(2)(3)
	Northern Illinois Hub		1,571	$	63.65		—		—		—		—

Total estimated GWh			11,516				6,555				612

		December 31, 2008		December 31, 2007

		(in millions)
Commodity price:
	Electricity contracts	$	375	$	(137	)

	Total Fair Value		Maturity <1 year			Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years

	(in millions)
Prices provided by external sources	$	373	$	232		$	141	$	—	$	—
Prices based on models and other valuation methods		2		(1	)		3		—		—

Total	$	375	$	231		$	144	$	—	$	—

	December 31, 2008				December 31, 2007

	Assets		Liabilities		Assets		Liabilities
	(in millions)
Electricity contracts	$	282	$	172	$	141	$	9
Other		3		1		—		—

Total	$	285	$	173	$	141	$	9

	(in millions)

Fair value of trading contracts at January 1, 2008	$	132
Net gains from energy trading activities		171
Amount realized from energy trading activities		(182	)
Other changes in fair value		(9	)

Fair value of trading contracts at December 31, 2008	$	112

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years			Maturity >5 years

	(in millions)
Prices actively quoted	$	2		$	3		$	(1	)	$	—		$	—
Prices provided by external sources		(102	)		(77	)		(23	)		(2	)		—
Prices based on models and other valuation methods		212			109			64			31			8

Total	$	112		$	35		$	40		$	29		$	8

	December 31, 2008

Credit Rating(1)	Exposure(2)		Collateral			Net Exposure
	(in millions)
A or higher	$	379	$	(222	)	$	157
A-		62		—			62
BBB+		49		—			49
BBB		132		1			133
BBB-		51		—			51
Below investment grade		10		(8	)		2

Total	$	683	$	(229	)	$	454


Financial Statements:
	Report of Independent Registered Public Accounting Firm	103
	Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006	104
	Consolidated Balance Sheets at December 31, 2008 and 2007	105
	Consolidated Statements of Shareholder's Equity for the years ended December 31, 2008, 2007 and 2006	107
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006	108
	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	109
	Notes to Consolidated Financial Statements	110


Power plant facilities		3 to 30 years
Leasehold improvements		Shorter of life of lease or estimated useful life
Emission allowances		25 to 33.75 years
Equipment, furniture and fixtures		3 to 10 years
Capitalized leased equipment		5 years

		Level 1		Level 2			Level 3			Netting and Collateral(2)			Total at December 31, 2008

		(in millions)
Assets at Fair Value
	Money market funds(1)	$	1,581	$	—		$	3		$	—		$	1,584
	Derivative contracts		2		417			221			(225	)		415
Liabilities at Fair Value
	Derivative contracts	$	—	$	(145	)	$	(8	)	$	51		$	(102	)

		2008

		(in millions)
Fair value of derivative contracts, net at January 1, 2008		$	120
Total realized/unrealized gains (losses):
	Included in earnings(1)		297
	Included in accumulated other comprehensive income (loss)		(2	)
Purchases and settlements, net			(203	)
Transfers in or out of Level 3			1

Fair value of derivative contracts, net at December 31, 2008		$	213

Change during the period in unrealized gains (losses) related to derivative contracts, net held at December 31, 2008(1)		$	125

		December 31, 2008				December 31, 2007

		Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(in millions)
Instruments
Non-derivatives:
	Long-term obligations	$	4,662	$	4,006	$	3,823	$	3,782

		Unrealized Gains (Losses) on Cash Flow Hedges			Unrecognized Gains (Losses) and Prior Service Adjustments Net(1)			Accumulated Other Comprehensive Income (Loss)

		(in millions)
Balance at December 31, 2006		$	111		$	(10	)	$	101
	Change for 2007		(171	)		7			(164	)

Balance at December 31, 2007			(60	)		(3	)		(63	)
	Change for 2008		300			(37	)		263

Balance at December 31, 2008		$	240		$	(40	)	$	200

	Three Months Ended March 31, 2006

	(unaudited)
Total operating revenues	$	4
Income (loss) before income taxes		(1	)
Benefit for income taxes		(3	)
Income from continuing operations		2

		December 31, 2008

		(in millions)
Current assets		$	31
Net property, plant and equipment			957
Other long-term assets			2

	Total assets	$	990

Current liabilities		$	29
Long-term obligations net of current maturities			25
Deferred revenues			15
Other long-term liabilities			18

	Total liabilities	$	87

Minority interest		$	77

			2008		2007

			(in millions)
Investments in Unconsolidated Affiliates
	Equity investment		$	351	$	375
	Cost investment			11		12

		Total	$	362	$	387