10-K

Use these links to rapidly review the document
TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PART IV

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

FORM 10-K

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

For the fiscal year ended December 31, 2009

Commission File Number 333-68630

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

Delaware (State or other jurisdiction of incorporation or organization)	95-4031807 (I.R.S. Employer Identification No.)
18101 Von Karman Avenue, Suite 1700 Irvine, California	92612
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (949) 752-5588

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

None	Not Applicable
(Title of Class)	(Name of each exchange on which registered)

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

Common Stock, par value $0.01 per share 

(Title of Class)

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

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

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

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

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o NO o

        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):

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

        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, 2009: $0. Number of shares outstanding of the registrant's Common Stock as of March 1, 2010: 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.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS			1
GLOSSARY			3
PART I			5
	ITEM 1. BUSINESS		5
		Overview	5
		Electric Power Industry	5
		Wholesale Markets	6
		Competition	7
		Operating Segments	7
		Overview of Facilities	8
		Merchant Power Plants	10
		Contracted Power Plants—Domestic	12
		Contracted Power Plants—International	15
		Overview of Projects under Construction	15
		Renewable Development Activities	16
		Marketing and Trading Activities	16
		Significant Customers	17
		Insurance	17
		Seasonality	17
		Discontinued Operations	17
		Regulatory Matters	17
		Environmental Matters and Regulations	20
		Employees	32
		EME's Relationship with Certain Affiliated Companies	32
	ITEM 1A. RISK FACTORS		32
		Environmental and Regulatory Risks	32
		Market Risks	34
		Financing Risks	38
		Operating Risks	40
	ITEM 1B. UNRESOLVED STAFF COMMENTS		42
	ITEM 2. PROPERTIES		42
		Description of Properties	42
	ITEM 3. LEGAL PROCEEDINGS		42
		Midwest Generation New Source Review Lawsuit	42
		Homer City New Source Review Notice of Violation	43
	ITEM 4. RESERVED		44
PART II			45
	ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		45
	ITEM 6. SELECTED FINANCIAL DATA		46

i

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			48
	MANAGEMENT'S OVERVIEW		48
		Introduction	48
		Highlights of Operating Results	49
		Environmental Developments	51
		EME's Renewable Program	53
		EME's Liquidity	54
	RESULTS OF OPERATIONS		55
		Introduction	55
		Results of Continuing Operations	55
		Results of Discontinued Operations	68
		Related-Party Transactions	68
		New Accounting Guidance	69
		Accounting for Derivative Instruments	69
		Fair Value of Derivative Instruments	69
	LIQUIDITY AND CAPITAL RESOURCES		72
		EME's Liquidity	72
		Capital Investment Plan	73
		EME's Historical Consolidated Cash Flow	76
		Credit Ratings	77
		Margin, Collateral Deposits and Other Credit Support for Energy Contracts	78
		EME's Liquidity as a Holding Company	80
		Dividend Restrictions in Major Financings	82
		Contractual Obligations, Commercial Commitments and Contingencies	85
		Off-Balance Sheet Transactions	86
		Environmental Matters and Regulations	89
	MARKET RISK EXPOSURES		90
		Introduction	90
		Commodity Price Risk	90
		Credit Risk	96
		Interest Rate Risk	98
	CRITICAL ACCOUNTING ESTIMATES AND POLICIES		99
		Introduction	99
		Derivatives	99
		Impairment of Long-Lived Assets	100
		Accounting for Contingencies, Guarantees and Indemnities	102
		Income Taxes	103
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			104
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			105
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			105
ITEM 9A. CONTROLS AND PROCEDURES			105
		Disclosure Controls and Procedures	105
		Management's Report on Internal Control over Financial Reporting	105
		Internal Control Over Financial Reporting	105
ITEM 9A(T). CONTROLS AND PROCEDURES			106

ii

	ITEM 9B. OTHER INFORMATION			106
		CONSOLIDATED STATEMENTS OF INCOME		108
		CONSOLIDATED BALANCE SHEETS		109
		CONSOLIDATED STATEMENTS OF TOTAL EQUITY		111
		CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		112
		CONSOLIDATED STATEMENTS OF CASH FLOWS		113
			Note 1. Summary of Significant Accounting Policies	114
			Note 2. Fair Value Measurements	124
			Note 3. Derivative Instruments and Risk Management	127
			Note 4. Accumulated Other Comprehensive Income	134
			Note 5. Acquisitions and Variable Interest Entities	135
			Note 6. Restructuring Costs	139
			Note 7. Divestitures	139
			Note 8. Investments in Unconsolidated Affiliates	139
			Note 9. Property, Plant and Equipment	141
			Note 10. Financial Instruments	143
			Note 11. Income Taxes	146
			Note 12. Compensation and Benefit Plans	149
			Note 13. Commitments and Contingencies	163
			Note 14. Related-Party Transactions	171
			Note 15. Supplemental Cash Flows Information	173
			Note 16. Quarterly Financial Data (unaudited)	173
PART III				174
	ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			174
	ITEM 11. EXECUTIVE COMPENSATION			174
	ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			174
	ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			174
	ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES			174
PART IV				176
	ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			176
SIGNATURES				182

iii

FORWARD-LOOKING STATEMENTS

       This annual report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect EME's current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by EME that is incorporated in this annual report, or that refers to or incorporates this annual report, may also contain forward-looking statements. In this annual report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact EME or its subsidiaries, include but are not limited to:

•

environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect EME's cost and manner of doing business;

•

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

•

weather conditions, natural disasters and other unforeseen events;

•

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

•

the cost and availability of fuel and fuel transportation services;

•

the cost and availability of emission credits or allowances;

•

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

•

the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other aspects of the complex and volatile markets in which EME and its subsidiaries participate;

•

the availability and creditworthiness of counterparties, and the resulting effects on liquidity in the power and fuel markets in which EME and its subsidiaries operate and/or the ability of counterparties to pay amounts owed to EME in excess of collateral provided in support of their obligations;

•

governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including the market structure rules applicable to each market and price mitigation strategies adopted by ISOs and RTOs;

1

•

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

•

EME's ability to borrow funds and access the capital markets on reasonable terms;

•

actions taken by Edison International and EME's directors, each of whom is appointed by Edison International, in the interests of Edison International and its shareholders, which could include causing EME, subject to contractual obligations and applicable law, to distribute cash or assets or otherwise take actions that may alter the portion of Edison International's portfolio of assets held and developed by EME;

•

project development and acquisition risks, including those related to project site identification, financing, construction, permitting, and governmental approvals;

•

operating risks, including equipment failure, availability, heat rate, output, costs of repairs and retrofits, and availability and cost of spare parts;

•

creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;

•

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

•

general political, economic and business conditions; and

•

EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and payment agreements with EME's respective affiliates.

       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.

2

GLOSSARY

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

Ameren	Ameren Corporation
AOI	adjusted operating income (loss)
ARO(s)	asset retirement obligation(s)
BACT	best available control technology
BART	best available retrofit technology
Big 4	Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu	British thermal units
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CARB	California Air Resources Board
CO2	carbon dioxide
Commonwealth Edison	Commonwealth Edison Company
CPS	Combined Pollutant Standard
CPUC	California Public Utilities Commission
DOJ	United States Department of Justice
EIA	Energy Information Administration
EME	Edison Mission Energy
Homer City	EME Homer City Generation L.P.
EMMT	Edison Mission Marketing & Trading, Inc.
EPAct 2005	Energy Policy Act of 2005
EWG(s)	exempt wholesale generator(s)
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGD	flue gas desulfurization
Fitch	Fitch Ratings
Fossil-fueled facilities	Midwest Generation fossil-fueled power plants and Homer City electric generating station
FPA	Federal Power Act
GAAP	United States generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
Illinois EPA	Illinois Environmental Protection Agency
Illinois PCB	Illinois Pollution Control Board
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.

3

MW	megawatts
MWh	megawatt-hours
NAAQS	National Ambient Air Quality Standard(s)
NAPP	Northern Appalachian
NOV	Notice of Violation
NOX	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
PURPA	Public Utility Regulatory Policies Act of 1978 (as amended)
PSD	Prevention of Significant Deterioration
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
SIP(s)	state implementation plan(s)
SNCR	selective non-catalytic reduction
SO2	sulfur dioxide
US EPA	United States Environmental Protection Agency

4

PART I

ITEM 1. BUSINESS

Overview

       EME is a holding company whose subsidiaries and affiliates are 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 competitive power markets through EMMT, its subsidiary. EME was formed in 1986 and is an indirect subsidiary of Edison International. Edison International also owns SCE, one of the largest electric utilities in the United States.

       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 renewable energy facilities (primarily wind projects and one biomass project). As of December 31, 2009, EME's subsidiaries and affiliates owned or leased interests in 39 operating projects with an aggregate net physical capacity of 11,269 MW of which EME's pro rata share was 10,072 MW. At December 31, 2009, EME's subsidiaries and affiliates also owned two wind projects under construction totaling 390 MW of net generating capacity.

Location and Available Information

       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.

Electric Power Industry

       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. See further discussion of regulations under "Regulatory Matters—U.S. Federal Energy Regulation."

       In 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

5

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.

       In various regional wholesale power markets, market administrators and independent market monitors have acknowledged that generators historically have not been provided adequate compensation in the energy markets to avoid the retirement of existing generation or provide adequate financial incentives to attract new investment when needed to ensure system reliability. As a result, capacity markets have emerged to provide additional financial incentives for electric capacity by compensating supply resources for the capability to supply electricity when needed, and demand resources for the electricity they avoid using. Capacity markets are expected to provide additional revenues for independent power producers.

Wholesale Markets

       EME's largest power plants are its fossil fuel power plants located in Illinois, which are collectively referred to as the Midwest Generation 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. Collectively, EME refers to both the Midwest Generation plants and Homer City facilities as the fossil-fueled facilities. The fossil-fueled facilities sell power primarily 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 indicating the minimum prices at which a bidder is willing to dispatch energy 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 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, price caps and other market rules intended to facilitate competition and discourage the exercise of market power.

       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 generator and operates capacity markets. PJM's capacity markets have a single market-clearing price. In June 2007, PJM implemented the RPM for capacity, under which capacity commitments are made in advance to provide a long-term pricing signal for capacity resources. The RPM is intended to provide a mechanism for PJM to meet the region's need for generation capacity, while allocating the cost to load-serving entities through a locational reliability charge. PJM also implemented marginal losses for transmission for its competitive wholesale electric market.

       Load-serving entities and generators, such as EME's subsidiaries Midwest Generation (with respect to the Midwest Generation plants) and Homer City (with respect to the Homer City facilities), may participate in PJM's capacity markets or transact capacity sales on a bilateral basis. Sales may also be made from PJM into the MISO RTO, which includes all or

6

parts of Illinois, Wisconsin, Indiana, Michigan, Ohio, and other states in the region, and into the NYISO, which controls the transmission grid and energy and capacity markets for New York State.

       Two of EME's wind projects sell electricity into RTOs as merchant generators. The Lookout wind project sells power into the PJM market, and the Goat Wind wind project sells power into the Electric Reliability Council of Texas market. The rest of EME's wind power generation facilities currently sell capacity, energy and/or ancillary services pursuant to bilateral contracts with electric utilities, regional cooperatives and public power authorities.

Competition

       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, the location of their generation facilities, and their contractual arrangements with affiliated entities.

       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 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, the ability of EME's fossil fuel-fired plants 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.

Operating Segments

       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 fossil-fueled facilities. EME is headquartered in Irvine, California with additional offices located in Bolingbrook and Chicago, Illinois, and Boston, Massachusetts.

7

Overview of Facilities

       As of December 31, 2009, EME's operations consisted of ownership or leasehold interests in the following operating projects:

Power Plants			Location	Primary Electric Purchaser2	Fuel Type	Ownership Interest			Net Physical Capacity (in MW)		EME's Capacity Pro Rata Share (in MW)
MERCHANT POWER PLANTS
	Midwest Generation plants1		Illinois	PJM	Coal		100	%		5,471		5,471
	Midwest Generation plants1		Illinois	PJM	Oil/Gas		100	%		305		305
	Homer City facilities1		Pennsylvania	PJM	Coal		100	%		1,884		1,884
	Goat Wind		Texas	ERCOT	Wind		99.9	%3		150		150
	Lookout		Pennsylvania	PJM	Wind		100	%		38		38
CONTRACTED POWER PLANTS – Domestic
Natural Gas
	Big 4 Projects
		Kern River1	California	SCE	Natural Gas		50	%		300		150
		Midway-Sunset1	California	SCE	Natural Gas		50	%		225		113
		Sycamore1	California	SCE	Natural Gas		50	%		300		150
		Watson	California	SCE	Natural Gas		49	%		385		189
	Westside Projects1
		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 Point4		Washington	PSE	Natural Gas		50	%		140		70
	Sunrise1		California	CDWR	Natural Gas		50	%		572		286
Renewable Energy
	Buffalo Bear		Oklahoma	WFEC	Wind		100	%		19		19
	Crosswinds		Iowa	CBPC	Wind		99	%3		21		21
	Elkhorn Ridge		Nebraska	NPPD	Wind		67	%		80		53
	Forward		Pennsylvania	CECG	Wind		100	%		29		29
	Hardin		Iowa	IPLC	Wind		99	%3		15		15
	High Lonesome		New Mexico	APSC	Wind		100	%		100		100
	Jeffers		Minnesota	NSPC	Wind		99.9	%3		50		50
	Minnesota Wind projects5		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 Lake1		Iowa	MEC	Wind		100	%		109		109
	Wildorado		Texas	SPS	Wind		99.9	%3		161		161
	Huntington Waste-to-Energy		New York	LIPA	Biomass		38	%		25		9
Coal
	American Bituminous1		West Virginia	MPC	Waste Coal		50	%		80		40

8

Power Plants		Location	Primary Electric Purchaser2	Fuel Type	Ownership Interest			Net Physical Capacity (in MW)		EME's Capacity Pro Rata Share (in MW)
CONTRACTED POWER PLANTS – International
	Doga1	Turkey	TEDAS	Natural Gas		80	%		180		144
Total									11,269		10,072

¹

Plant is operated under contract by an EME operations and maintenance subsidiary or the plant is operated or managed directly by an EME subsidiary.

²

Electric purchaser abbreviations are as follows:

APSC	Arizona Public Service Company	NSPC	Northern States Power Company
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
NPPD	Nebraska Public Power District

³

Represents EME's current ownership interest. If the project achieves a specified rate of return, EME's interest will decrease.

⁴

EME sold its ownership interest in the March Point project to its partner, Equilon Enterprises, LLC in February 2010.

⁵

Comprised of seven individual wind projects.

       At December 31, 2009, the fuel sources for these projects were as follows:

Fuel Source	Percentage of EME's Generation Capacity
Coal		73	%
Natural gas		15	%
Renewable energy		12	%

       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.

9

Merchant Power Plants

Midwest Generation Plants

       The Midwest Generation plants consist of the following:

		Location	Leased/ Owned	Fuel	Megawatts
Operating Plant or Site
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 Station3	Grundy County, Illinois
	Crawford peaker4	Chicago, Illinois
	Joliet peaker5	Joliet, Illinois
	Calumet peaker5	Chicago, Illinois
	Electric Junction peaker5	Aurora, Illinois
	Lombard peaker5	Lombard, Illinois
	Sabrooke peaker5	Rockford, Illinois

¹

The Waukegan Station is comprised of Units 7 and 8. Midwest Generation shut down permanently Waukegan Station Unit 6 (100 MW) on December 21, 2007. For further discussion, see "Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide—Illinois."

²

The Will County Station is comprised of Units 1, 2, 3, and 4. Midwest Generation has agreed with the Illinois EPA to shut down permanently Will County Station Units 1 and 2 (totaling 299 MW) on or before December 31, 2010. For further discussion, see "Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide—Illinois."

³

All Collins Station units ceased operations and were decommissioned on or before December 31, 2004.

⁴

Peaking units ceased operations as of April 21, 2005.

⁵

Peaking units ceased operations as of December 31, 2004.

Power Sales

       Energy and capacity from the Midwest Generation plants are sold under terms, including price, duration and quantity, arranged by EMMT, an EME subsidiary engaged in the power marketing and trading business, with customers through a combination of bilateral agreements

10

(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 Midwest Generation plants. Power generated at the Midwest Generation plants is generally sold into the PJM market.

Fuel Supply

       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.

       Coal is transported under long-term transportation agreements with Union Pacific Railroad and various short-haul carriers. As of December 31, 2009, 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 one year to 10 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 Midwest Generation 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.

Homer City Facilities

       The Homer City facilities are leased and consist of three coal-fired units (referred to as Units 1, 2 and 3 in this annual report) and associated support facilities, all of which are located in Indiana County, Pennsylvania.

Power Sales

       Energy and capacity from the Homer City facilities are sold under terms, including price, duration 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. The Homer City facilities are situated in the PJM control area and have direct, high voltage interconnections to PJM and also to the NYISO. Electric power generated at the Homer City facilities is generally sold into the PJM market.

Fuel Supply

       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

11

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. 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.

Emission Allowances for the Fossil-Fueled Facilities

       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 fossil-fueled facilities, EME obtained emission allowance rights 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.

Goat Wind Wind Project

       EME owns a 99.9% interest in Goat Wind LP, which owns a 150 MW wind farm project in Texas, which EME refers to as the Goat Wind wind project. The project sells electricity into the Electric Reliability Council of Texas market as a merchant wind generator. The Goat Wind wind project was constructed in two phases. Phase I achieved commercial operation in April 2008 and Phase II achieved commercial operation in June 2009.

Lookout Wind Project

       EME owns 100% of 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.

Contracted Power Plants—Domestic

Natural Gas

Big 4 Projects

       EME owns partnership investments in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, as described below. These projects sell power to 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.

12

Kern River Project

       EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Kern River project. Kern River Cogeneration sells electricity to SCE under an agreement that expires in 2011. Kern River Cogeneration also sells steam to Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc., under an agreement with a term equivalent to the power purchase agreement.

Midway-Sunset Project

       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. As mandated by CPUC Decision 07-09-040, dated September 20, 2007, Midway-Sunset sells electricity to SCE under an extension of its prior power purchase agreement, with revised pricing. On September 28, 2009, Midway-Sunset entered into a power purchase agreement with PG&E that expires in 2016, for which CPUC approval is pending. Midway-Sunset also sells electricity and steam to Aera Energy LLC under agreements that expire concurrently with the new PG&E power purchase agreement.

Sycamore Project

       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. As mandated by CPUC Decision 07-09-040, dated September 20, 2007, Sycamore Cogeneration sells electricity to SCE under an extension of its prior power purchase agreement, with revised pricing. 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.

Watson Project

       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. As mandated by CPUC Decision 07-09-040, dated September 20, 2007, Watson Cogeneration sells electricity to SCE under an extension of its prior power purchase agreement, with revised pricing. 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.

Westside Projects

       EME owns 50% partnership interests in each of Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, and Sargent Canyon

13

Cogeneration Company, each of which owns a 38 MW natural gas-fired cogeneration facility located in California. Due to similar economic characteristics, EME views these projects collectively and refers to them as the Westside projects. Three of these projects sold electricity to PG&E under 15-year power purchase agreements, each of which expired during the first quarter of 2007. Currently, these projects sell electricity to PG&E under agreements that provide for sales at "as available" rates.

Sunrise Project

       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.

Renewable Energy

Wind

       EME owns interests in the following operating wind projects which sell electricity pursuant to long-term power purchase agreements with third parties with original terms ranging from 10 to 30 years. The table below provides the expiration of each of the contracted wind plant's power purchase agreements and the project's commercial operation or acquisition date.

Contracted Wind Plants	Power Purchase Agreement Expiration Year	Commercial Operation or Acquisition Date
Buffalo Bear wind project	2033	December 2008
Crosswinds wind project1	20224	June 2007
Elkhorn Ridge wind project	2029	March 2009
Forward wind project	2017	April 2008
Hardin wind project2	2027	May 2007
High Lonesome wind project	2039	July 2009
Jeffers wind project	2028	October 2008
Minnesota wind projects3	2021-20345	April 2006
Mountain Wind I & II projects	2033	July 2008/September 2008
Odin wind project	2028	May 2008
San Juan Mesa wind project	2025	December 2005
Sleeping Bear wind project	2032	September 2007
Spanish Fork wind project	2028	July 2008
Storm Lake wind project	2026	April 2006
Wildorado wind project	2027	April 2007

¹

Ten separate limited liability companies collectively form the wind farm.

²

Seven separate limited liability companies collectively form the wind farm.

³

Thirty-seven separate limited liability companies each own a small wind-powered electric generation facility.

⁴

Agreement includes a five-year renewal option.

⁵

Each of the Minnesota wind projects sells electricity under a power purchase agreement with NSPC that expires between 2025 and 2034, or with IPLC that expires in 2021.

14

Biomass

Huntington Waste-to-Energy Project

       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.

Coal

American Bituminous Project

       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.

Contracted Power Plants—International

Doga Project

       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.

Overview of Projects under Construction

       As of December 31, 2009, EME had the projects described below under construction.

Big Sky Wind Project

       EME owns 100% of Big Sky Wind, LLC, which owns a 240 MW wind project under construction in Illinois, which EME refers to as the Big Sky wind project. Construction of this project commenced during the fourth quarter of 2009 and is scheduled for completion in early 2011. The project plans to sell electricity into the PJM market as a merchant generator or to third-party customers under power sales contracts.

Cedro Hill Wind Project

       EME owns 100% of Cedro Hill Wind, LLC, which owns a 150 MW wind project under construction in Texas, which EME refers to as the Cedro Hill wind project. Construction of this project commenced during the fourth quarter of 2009 and is scheduled for completion during the fourth quarter of 2010. The project has entered into a 20-year power purchase agreement with the City of San Antonio.

15

Renewable Development Activities

       EME had a development pipeline of potential wind projects with projected installed capacity of approximately 4,000 MW at January 31, 2010. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. As of December 31, 2009, EME had commitments to purchase 183 wind turbines (349 MW) and had 67 wind turbines (163 MW) in storage to be used for future wind projects. Successful completion of development of a wind project depends upon obtaining permits and agreements necessary to support an investment and 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.

       During 2008, EME had 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 2009, EME sold a number of solar projects under development to First Solar Electric and terminated the agreement.

Marketing and Trading Activities

       EME's power marketing and trading subsidiary, EMMT, markets the energy and capacity of EME's merchant generating fleet and, in addition, trades electric power and related commodity and financial products, including forwards, futures, options and swaps. EMMT segregates its marketing and trading activities into two categories:

•

Marketing—EMMT engages in the sale of energy and capacity and the purchase of fuels, including coal, natural gas and fuel oil, through intercompany contracts with EME's subsidiaries that own or lease the fossil-fueled facilities and EME's merchant wind energy facilities. EME uses derivative instruments to reduce its exposure to market risks that arise from fluctuations in the prices of electricity, capacity, fuel, emission allowances, and transmission rights. The objective of these activities is to sell the output of the power plants on a forward basis or to hedge the risk of future changes in prices, thereby increasing the predictability of earnings and cash flows. Hedging activities include on-peak and off-peak periods and may include load service requirements contracts with local utilities. Transactions entered into related to hedging activities are designated separately from EMMT's trading activities and are recorded in what EMMT calls its hedge book. Not all contracts entered into by EMMT for hedging purposes qualify as hedges for accounting purposes.

•

Trading—As an extension of its marketing and hedging activities, EMMT seeks to generate trading profits from volatility in the price of electricity, capacity, fuels, and transmission congestion by buying and selling contracts in wholesale markets under limitations approved by EME's risk management committee.

16

Significant Customers

       In the past three fiscal years, the fossil-fueled facilities sold electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 48%, 50% and 51% of EME's consolidated operating revenues for the years ended December 31, 2009, 2008 and 2007, respectively. For the years ended December 31, 2009 and 2008, a second customer, Constellation Energy Commodities Group, Inc. accounted for 16% and 10%, respectively, of EME's consolidated operating revenues. Sales to Constellation are primarily generated from the fossil-fueled facilities and consist of energy sales under forward contracts. In 2008 and 2007, EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Midwest Generation plants to Commonwealth Edison under load requirements services contracts. By May 2009, all these contracts had expired. 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.

Insurance

       EME maintains insurance policies consistent with those normally carried by companies engaged in similar business and owning similar properties. EME's insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boiler or 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. No assurance can be given that EME's insurance will be adequate to cover all losses.

Seasonality

       For a discussion of seasonality, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations."

Discontinued Operations

       For a discussion of discontinued operations, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Divestitures."

Regulatory Matters

General

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

17

U.S. Federal Energy Regulation

Federal Power Act

       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.

       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.

       Deregulation of the electric generating sector began with the enactment of PURPA, which established a regulatory scheme for certain qualifying facilities. Most qualifying facilities, as that term is defined in PURPA, are exempt from the ratemaking and several other provisions of the FPA. It was further expanded with the passage of the Energy Policy Act of 1992, which established a regulatory scheme for EWGs and foreign utility companies. EWGs 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. More recently, in 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.

       Each of EME's U.S. generating facilities has either been determined by the FERC to qualify as a qualifying facility, or the subsidiary owning the facility has been determined to be an EWG. In addition, EME's power marketing subsidiaries, including EMMT, have been authorized by the FERC to make wholesale market sales of power at market-based rates and are subject to the FERC ratemaking regulation under the FPA.

Public Utility Regulatory Policies Act of 1978

       PURPA provides two primary benefits to qualifying facilities. First, all cogeneration facilities that are qualifying facilities are exempt from certain provisions of the FPA and regulations of the FERC thereunder. Second, the FERC regulations promulgated under PURPA initially required electric utilities to purchase electricity generated by qualifying facilities at a price based on the purchasing utility's avoided cost and to sell backup power to the qualifying facility on a nondiscriminatory basis. EPAct 2005 provides for the elimination of a utility's obligation to purchase power from qualifying facilities at its avoided cost if the FERC determines that the relevant market meets certain conditions for competitive, nondiscriminatory access. The FERC's regulations also permit qualifying facilities and utilities

18

to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs, but do not require utilities to purchase power at such prices.

       Several of EME's projects, including the Big 4 projects, are qualifying cogeneration facilities. Qualifying cogeneration facilities 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 and 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. 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.

Reliability Standards

       The FERC has designated the North American Electric Reliability Corporation (NERC) 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 appropriate steps to be compliant with current NERC reliability standards that apply to its operations.

Transmission of Wholesale Power

       Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is subject to FERC jurisdiction pursuant to 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, power marketers and EWGs to more effectively compete in the wholesale market.

State Energy Regulation

Illinois Power Procurement

       The Illinois Power Agency Act regulates the procurement of power by Commonwealth Edison and the Ameren Illinois utilities for their bundled-rate customers. In June 2009, the newly created Illinois Power Agency became 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.

19

       The Illinois Commerce Commission, which continues in its role of oversight and approval of the power planning and procurement for utilities' bundled retail customers, approved in January 2009 a procurement plan for 2009 that was proposed by the Illinois Power Agency. The plan, which was based on five-year demand forecasts, uses a laddered procurement strategy for the 2009-2014 period. In 2009, the Illinois Power Agency acquired through a single request for proposals roughly one third of the forecasted demand for bundled load for Commonwealth Edison and the Ameren Illinois utilities. Renewable requirements, in the first year, were 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. In December 2009, the Illinois Power Agency's procurement plan for supply for the utilities' bundled customers for the 2010-2015 period was approved by the Illinois Commerce Commission.

Environmental Matters and Regulations

       Because EME does not own or operate any assets, other than the stock of its subsidiaries, it does not have any direct environmental obligations or liabilities. However, legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the environment impose numerous restrictions on the operation of EME's existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by EME's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations. The facilities of EME's subsidiaries which are most affected by environmental regulation are located in Illinois and Pennsylvania.

       Additional information about environmental matters affecting EME, including projected environmental capital expenditures, is included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Investment Plan." EME continues to monitor legislative and regulatory developments and to evaluate possible strategies for compliance. If EME were to decide not to install additional environmental control equipment and, instead, shut down a unit, an impairment analysis and possible change in the estimated remaining life would be required (which could significantly increase the annual depreciation expense). For additional discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Merchant Coal-Fired Power Plants."

Climate Change

       There have been a number of efforts at both the federal and state legislative and regulatory levels to adopt or enact regulations to reduce GHG emissions. Any climate change regulation or other legal obligation that would require substantial reductions in emissions of GHGs or that would impose additional costs or charges for the emission of GHGs could significantly increase the cost of generating electricity from fossil fuels, especially coal, which could adversely affect EME.

20

Federal Legislative/Regulatory Developments

       In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act. The bill, which was endorsed by EME's parent company, Edison International, would establish a cap-and-trade system for GHG emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate GHG emissions from all covered entities would be established and decline over time. Emitters of GHGs would be required to have allowances for GHG emissions during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated free of charge in declining amounts over time. Emitters of GHGs would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative GHG reduction efforts). Similar legislation was introduced in the U.S. Senate in September 2009. EME cannot predict whether legislation imposing limits on GHG emissions in the U.S. will be passed in 2010 and the timing, contents and potential effects on EME of any legislation that may be enacted remain uncertain.

       Even if Congress does not pass legislation mandating GHG emissions reductions, regulatory developments under the CAA may also result in GHG emissions requirements that could affect EME. In April 2007, the U.S. Supreme Court held, in Massachusetts, et al. v. Environmental Protection Agency, et al., that GHGs are "air pollutants" under the CAA and that the US EPA has a duty to determine whether GHG emissions from new motor vehicles contribute to climate change or offer a reasoned explanation for its failure to make such a determination. In response to this decision, in December 2009 the US EPA issued a finding that certain GHGs, including CO₂, endanger the public health and welfare, which enables the US EPA to establish GHG emissions limits for new light-duty vehicles. It is expected that the US EPA will issue the final light-duty vehicle emissions limits in March 2010.

       The December 2009 endangerment finding, if it is upheld after litigation, will trigger future regulation of stationary sources of GHGs, such as power plants, which the US EPA plans to phase in beginning in 2011. In addition, when the regulation of GHGs from light-duty vehicles is finalized, GHG emissions will become subject to review under the CAA's PSD (construction or modification of major sources) permit program. Sources subject to a PSD review for GHGs would be required to use BACT to control GHG emissions. Because CO₂ is emitted in greater quantities than other CAA-regulated pollutants, regulating it under the PSD program would cover a large number of sources. To avoid the regulatory and enforcement consequences of such an outcome, in November 2009 the US EPA proposed a regulation, known as the "GHG tailoring rule." The GHG tailoring rule would redefine the PSD program to increase the threshold emission limit of CO₂ equivalents in a year from 250 tons to 25,000 metric tons. Whether or not this regulation is finalized, it is likely that EME's fossil-fueled generating facilitities would be major sources for purposes of the PSD programs. However, because the current PSD proposal affects only new or modified resources, it is not expected to have an immediate effect on EME's existing generating plants. If EME is required to install pollution controls in the future or otherwise modify its operations in order to reduce CO₂ emissions, the impact will depend on the nature and timing of the controls to be applied, both of which remain uncertain. EME does not believe that currently there are commercially and technically feasible, full scale methods to control GHG emissions from its fossil-fueled generating facilities.

21

       In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which will require all sources within specified categories, including electric generation facilities, to begin emissions monitoring in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011. EME already monitors and reports CO₂ emissions through CAA requirements and voluntarily through participation in The Climate Registry. EME's 2007, not independently verified, GHG emissions were approximately 47.4 million metric tons (the most recent period for which EME has available data).

Regional Legislative Initiatives

       There are a number of regional initiatives relating to GHG emissions. 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 Congress. It cannot yet be determined whether or to what extent any federal legislation would preempt regional or state initiatives, because these initiatives are in varying stages of development and implementation. If state and/or regional initiatives remain in effect after federal legislation is enacted, generators could be required to satisfy them in addition to federal standards.

       Seven northeastern states have entered into a Memorandum of Understanding to establish a regional cap-and-trade GHG program for electric generators, referred to as the Regional Greenhouse Gas Initiative (RGGI). The RGGI states (now numbering 10) have passed laws and/or regulations to implement the RGGI program. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania participated in the process as an observer.

       Arizona, California, Montana, New Mexico, Oregon, Utah, Washington and the Canadian provinces of British Columbia, Manitoba, Ontario, and Quebec have launched the Western Climate Initiative to develop strategies to reduce GHG emissions in the region to 15% below 2005 levels by 2020. In September 2008, the Initiative partners released recommendations for a regional cap-and-trade program to help achieve that reduction goal. In February 2010, Arizona gave notice that it would not take part in the Western Climate Initiative's cap-and-trade program.

       Illinois is a party to the Midwestern Greenhouse Gas Reduction Accord, by which six Midwestern states and the Canadian province of Manitoba agreed to develop regional GHG emission reduction goals within one year using a multi-sector cap-and-trade program to be implemented within 30 months. In June 2009, the Midwestern Greenhouse Gas Reduction Accord Advisory Group released its recommendations for emissions reduction targets and the design of a regional cap-and-trade program. The group is also drafting a framework for the cap-and-trade program that will serve as a basis for individual state legislative or regulatory action to implement the program.

State Specific Legislation

       California has enacted two laws regarding GHG emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce GHG emissions. AB 32 requires the CARB to develop regulations, potentially including market-based compliance mechanisms, targeted to reduce

22

California's GHG emissions to 1990 levels by 2020. The CARB's mandatory program will commence in 2012 and will implement incremental reductions aimed at reducing GHG emissions to 1990 levels by 2020. The CARB has released preliminary draft regulations establishing a California cap-and-trade program, which include revisions to the CARB's mandatory GHG emissions reporting regulation and are expected to be finalized by the CARB in October 2010.

       The second law, SB 1368, required the CPUC and the California Energy Commission to adopt GHG emissions performance standards that restrict the ability of investor-owned and publicly owned utilities, respectively, to enter into long-term arrangements for the purchase of electricity. The standards must equal the performance of a combined-cycle gas turbine generator. The standards that have been adopted prohibit California load-serving entities from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO₂ per MWh. Utility purchases of power generated by EME's facilities in California are subject to the emissions performance standards established in SB 1368. At this time, EME believes that all of its facilities in California meet the GHG emissions performance standard adopted under SB 1368, but EME will continue to monitor the regulations, as they are developed, for potential impact on its existing facilities and its projects under development.

Litigation Developments

       In 2009, three courts issued decisions in cases involving the question of whether power plants and other large sources could constitute a public nuisance, making the sources potentially liable for damages or other remedies.

       In October 2009, a California federal district court dismissed the complaint that had been filed by the native Alaskan village of Kivalina and the Kivalina tribe in February 2008 against 24 defendants, including Edison International, who directly or indirectly engaged in the electric generating, oil and gas, or coal mining lines of business. Plaintiffs had alleged GHG emissions from the defendants' business activities contributed to global warming impacts that are melting the Arctic sea ice that protects the village from winter storms and that the village would soon need to be abandoned or relocated at a cost of between $95 million and $400 million. Although EME was not named as a defendant, the complaint identified EME as a direct or indirect operating subsidiary of Edison International through which Edison International engages in electric power generation. The court dismissed the plaintiffs' federal nuisance claims stating that they were inappropriate for judicial resolution because they required policy choices that were reserved to the legislative or executive branches of the government (the "political question doctrine"). The court also held that the plaintiffs did not have standing under federal law to bring the case, in part because of the lack of connection between the defendants' conduct and the harm that plaintiffs alleged was occurring. The court also dismissed plaintiffs' state law nuisance claims, but without prejudice to those claims being re-filed in state court. The plaintiffs have appealed the dismissal order to the Ninth Circuit Court of Appeals.

       In contrast to the district court decision in Kivalina, the U.S. Court of Appeals for the Second Circuit, in September 2009, and the U.S. Court of Appeals for the Fifth Circuit, in

23

October 2009, reversed and remanded lower court decisions that had dismissed complaints (filed in New York and Mississippi, respectively), against electric utilities and others, for injunctive relief and/or damages allegedly arising as a result of GHG emissions. These courts held that plaintiffs had standing and that their claims (sounding in various common law theories, including public nuisance in the New York case and public nuisance, private nuisance, trespass and negligence in the Mississippi case) were not barred by the political question doctrine. Neither EME nor its subsidiaries was named as a defendant in the New York case. At the time the action was dismissed by the court in Mississippi, the plaintiffs were seeking to amend their complaint to include Edison International and several affiliates of Edison International, including EME, as defendants.

       Each of these differing results remains subject to appeal, rehearing, or potential review by the U.S. Supreme Court, and thus the ultimate impact of these cases remains uncertain. In addition, EME cannot predict whether the appellate decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims.

Air Quality

       The CAA establishes a comprehensive program to protect and improve the nation's air quality by regulating certain air emissions from mobile and stationary sources. The states implement and administer many of these programs and may impose additional or more stringent requirements under the CAA scheme. The federal CAA, state clean air acts, and federal and state regulations implementing such statutes apply to plants owned by EME, and have their largest impact on the operation of coal-fired plants. The federal environmental regulations require states to adopt state implementation plans for certain pollutants, known as SIPs, that are equal to or more stringent than the federal requirements. These plans detail how the state will attain the standards that are mandated by the relevant law or regulation.

       The CAA requires the US EPA to review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect public health and welfare. These concentration levels are known as National Ambient Air Quality Standards, or NAAQS. The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO₂.

       Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and to maintain good air quality in attainment areas. All SIPs are submitted to the US EPA for approval. If a state fails to develop adequate plans, the US EPA will develop and implement a plan. The attainment status of areas can change, and states may be required to develop new SIPs that address these changes. Many of EME's facilities are located in counties that have not attained NAAQS for ozone and fine particulate matter. NO_x emissions from power plants impact ambient air ozone levels and SO₂ emissions from power plants impact ambient air fine particulate matter levels.

       As described further below, on December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NO_x and SO₂ emissions at the Midwest Generation plants. The agreement requires Midwest Generation to achieve air emission

24

reductions for NO_x and SO₂, and those reductions should contribute to or effect compliance with various existing US EPA ambient air quality standards. It is possible that if lower ozone, particulate matter, NO_x or SO₂ NAAQS are finalized by US EPA in the future, Illinois may implement regulations that are more stringent than those required by Midwest Generation's existing agreement with the Illinois EPA.

Nitrogen Oxide and Sulfur Dioxide

Clean Air Interstate Rule

       The CAIR, issued by the US EPA on March 10, 2005, was intended to address ozone and fine particulate matter attainment issues by reducing regional NO_x and SO₂ emissions. The CAIR had mandated significant reductions in NO_x and SO₂ emission allowance caps under the CAA in the 28 eastern states and the District of Columbia, where compliance with the NAAQS for ozone and fine particulate matter was at issue. There is substantial uncertainty as to how the US EPA will address the deficiencies identified in 2008 decisions by the U.S. Court of Appeals for the D.C. Circuit that resulted in the remand of the CAIR to the US EPA for the issuance of a revised rule. The CAIR remains in effect until the US EPA issues a revised rule, which is currently expected to be proposed in 2010. As a result of the D.C. Circuit Court's decisions, it is unclear whether the US EPA will be able to design a cap-and-trade program for NO_x and SO₂ that is consistent with the CAA. It is also unclear whether existing SIPs in certain states, particularly Illinois and Pennsylvania, will be sufficient to comply with the CAA. The fossil-fueled facilities may be subject to additional requirements, which could result in increased capital expenditures and operating expenses to comply with a revised CAIR or alternative regulations under the CAA. In the case of the Midwest Generation plants, these new requirements could exceed those applicable under the CPS.

Proposed NAAQS for SO₂

       In November 2009, the US EPA proposed a new one-hour NAAQS for SO₂. The new standard is proposed to be between 50 and 100 parts per billion. The US EPA is required by a consent decree to take final action by June 2, 2010. The proposed rule would require states to submit SIPs in 2014, with compliance by 2017.

Illinois

       On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NO_x and SO₂ emissions at the Midwest Generation 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. 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

25

must install and operate SNCR equipment on Units 7 and 8 at the Crawford Station by December 31, 2015.

       SO₂ Emissions—Midwest Generation must comply with an overall SO₂ annual emission rate beginning with 0.44 lbs/million Btu in 2013 and decreasing annually until it reaches 0.11 lbs/million Btu in 2019 and thereafter.

       Midwest Generation has not decided upon a particular combination of retrofits to meet the required step down in emission rates and 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. The CPS also requires Midwest Generation to shut down Units 1 and 2 at the Will County Station by December 31, 2010.

       During 2009, Midwest Generation conducted tests of NO_x removal technology based on SNCR that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NO_x portion of the CPS. Capital expenditures for installation of SNCR equipment are expected to be approximately $88 million in 2010 and approximately $70 million in 2011.

       Testing of FGD technology based on dry sodium sorbent injection demonstrated significant reductions in SO₂ when using the low-sulfur coal employed by Midwest Generation; however, further analysis and evaluation are required to determine the appropriate method to comply with the SO₂ portion of the CPS. Use of FGD technology based on injection of dry sodium sorbent in combination with Midwest Generation's use of low-sulfur coal is expected to require substantially less capital and installation time than dry scrubber technology, but would likely result in higher ongoing operating costs than dry scrubber technology and may consequently result in lower dispatch rates and reduced competitiveness. Midwest Generation may also combine the use of dry sorbent injection technology with upgrades to its particulate removal systems to meet environmental regulations.

       Midwest Generation cannot predict what specific method of SO₂ removal will be used or the total costs that will be incurred to comply with the CPS. A decision whether to proceed with the above or other approaches to compliance remains subject to further analysis and evaluation of several factors, such as market conditions, regulatory and legislative developments, and forecasted capital and operating costs. Midwest Generation could elect to shut down units when required in order to comply with the SO₂ removal requirements of the CPS. Due to existing uncertainties about the factors noted above, Midwest Generation may defer final decisions about particular units as long as possible. Accordingly, final decisions on whether to install controls, the particular controls that will be installed and the resulting capital commitments may not occur for up to two years for some of the units and potentially later for others. Midwest Generation continues to evaluate various scenarios and cannot predict the extent of shutdowns and retrofits or the particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS.

26

Pennsylvania

       The Homer City facilities were subject to the federal CAIR during 2009 and complied with both the NO_x and SO₂ requirements by using existing equipment and purchasing SO₂ allowances. Pennsylvania adopted a state version of the CAIR, which the US EPA approved in December 2009. Homer City expects to comply with the Pennsylvania CAIR, which is substantially similar to the federal CAIR, in the same manner in which it complies with the federal CAIR.

Mercury

Clean Air Mercury Rule

       Until new federal standards are developed to replace the CAMR, EME will not be able to determine whether it will be necessary to undertake mercury emission control measures beyond those required by state regulations. The CAMR was established by the US EPA as an attempt to reduce mercury emissions from existing coal-fired power plants using a cap-and-trade program. EME's coal-fired electric generating facilities emit mercury and other regulated emissions. As a result of the decision by the U.S. Court of Appeals for the D.C. Circuit in February 2007 that rejected both the CAMR and the related decision by the US EPA to remove oil and coal-fired plants from the list of sources to be regulated under Section 112 of the CAA 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, Pennsylvania's mercury regulations have been invalidated).

Illinois

       Midwest Generation's compliance with the CPS supersedes the Illinois mercury regulations that would otherwise be applicable to the Midwest Generation plants. The CPS requires that, 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 was required to install and operate carbon injection equipment on all operating units. Installation of the equipment was completed in 2009. Capital expenditures relating to these controls were $42 million. Midwest Generation will also be required to install cold side electrostatic precipitator or baghouse equipment on Unit 7 at the Waukegan Station by December 31, 2013, and on Unit 3 at the Will County Station by December 31, 2015.

27

Pennsylvania

       Until new legislation is passed authorizing the adoption of revised mercury regulations, the Homer City facilities will not be required to comply with Pennsylvania mercury limitations. The PADEP attempted to implement regulations that would have required coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015, as embodied in the Pennsylvania CAMR SIP. The rule did not allow the use of emissions trading to achieve compliance. The Pennsylvania Supreme Court upheld a decision by the Commonwealth Court declaring Pennsylvania's mercury rule unlawful, invalid and unenforceable, and enjoining Pennsylvania from continued implementation and enforcement of the rule.

Ozone and Particulates

National Ambient Air Quality Standards

       In September 2006, the US EPA issued a final rule that would significantly reduce the 24-hour fine particulate standard (from 65 ug/m3 to 35 ug/m3), but in February 2009, the U.S. Court of Appeals for the D.C. Circuit remanded the annual fine particulate matter standard to the US EPA for further review.

       In March 2008, the US EPA issued a final rule revising the primary and secondary NAAQS for ozone, reducing the level of the 8-hour standard to 0.075 parts per million (ppm). In January 2010, the US EPA proposed revisions that would further lower the 8-hour primary ozone standard to a level in the range of 0.060 - 0.070 ppm and impose a cumulative, seasonal secondary standard in the range of 7 - 15 ppm-hours. Final standards are expected in August 2010. EME believes that it is in compliance with existing standards and anticipates that any such further emission reduction obligations would not be imposed under this standard until 2014 at the earliest.

Illinois

       The Illinois SIP for 8-hour ozone was submitted to the US EPA on March 18, 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. As the fine particulate and ozone standards are finalized, as described above, Illinois may be required to implement additional emission control measures to address emissions of NO_x, SO₂ and volatile organic compounds.

Pennsylvania

       In August 2007, the US EPA accepted the PADEP's maintenance plan, which indicated 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. However, in March 2009, the PADEP recommended to the US EPA that Indiana County (where the Homer City facilities are located) be designated non-attainment under the US EPA's 2008 revised 8-hour ozone standard. Until the US EPA completes its revision to the 8-hour ozone standard, redesignations are finalized, and additional regulations are developed to achieve attainment with the revised standard, EME will not know what specific

28

requirements it will have to meet. However, EME expects that its currently installed SCRs will be capable of meeting these new requirements.

       Effective April 1, 2009, the PADEP changed its air opacity policy, eliminating many exemptions and reducing the allowable exceedance rate to 0.5% of a unit's operating time. Homer City undertook optimization of unit ramp rates and combustion parameters at the Homer City facilities to reduce the deratings required to meet the opacity standards. Additional capital improvements may also be required. Homer City operated below the 0.5% exceedance rate during the second, third and fourth quarters of 2009.

       With respect to fine particulates, in November 2009, the US EPA indicated that Indiana County, Homer City Township had not attained applicable standards. The PADEP must now submit an updated SIP by November 13, 2012. EME cannot determine the potential effects of the SIP at this time.

Regional Haze

       The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. The goal of the rules 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 BART or implement other control strategies to meet regional haze control requirements. The US EPA issued a final rulemaking on regional haze in 2005, requiring emission controls that constitute BART for industrial facilities that emit air pollutants which reduce visibility by causing or contributing to regional haze. These amendments required states to develop implementation plans to comply with BART by December 2007, to identify the facilities that will have to reduce SO_2, NO_x and particulate matter emissions, and then to set BART emissions limits for those facilities. Failure to do so results in a Federal Implementation Plan.

       Neither Illinois nor Pennsylvania has submitted a SIP that addresses regional haze issues under the CAA and so, beginning on December 31, 2009, both states became subject to a two-year deadline after which a Federal Implementation Plan will govern related emission issues. As a result of this uncertainty and the questions surrounding the CAIR program, EME cannot predict whether it will be required to install BART or implement other control strategies at the Midwest Generation plants and/or the Homer City facilities, what specific measures will be required or how much they will cost.

       The CPS, discussed above in "—Nitrogen Oxide and Sulfur Dioxide—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.

New Source Review Requirements

       The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at the facility. Since 1999, the US

29

EPA has pursued a coordinated compliance and enforcement strategy to address CAA compliance issues at the nation's coal-fired power plants. The strategy has included both the filing of suits against a number of power plant owners, and the issuance of administrative NOVs to a number of power plant owners alleging NSR violations.

       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 Midwest Generation plants. After attempts at settlement failed, on August 27, 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, based in part on the allegations in the NOV and alleging that construction projects undertaken prior to Midwest Generation's ownership violated various provisions of the NSR rules and Title V requirements. On June 12, 2008, Homer City received an NOV from the US EPA, which alleges that certain construction projects, all completed before Homer City acquired the Homer City facilities, violated various provisions of the NSR rules and Title V permit requirements. For further discussion, see "Legal Proceedings—Midwest Generation New Source Review Lawsuit" and "Homer City New Source Review Notice of Violation."

Water Quality

Clean Water Act

       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 temperature of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities.

       In January 2007, the U.S. Court of Appeals for the Second Circuit rejected the US EPA rule on cooling water intake structures and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost-benefit analysis for determining the best technology available and the use of restoration to achieve compliance with the rule. On July 2007, the US EPA suspended the requirements for cooling water intake structures, pending further rulemaking. In April 2009, the U.S. Supreme Court reversed the Second Circuit and held that the US EPA may consider, but is not required to use, cost-benefit analysis in formulating regulations under Clean Water Act Section 316(b). The Court did not review the Second Circuit's rejection of the use of restoration as compliance with Section 316(b), which means the Second Circuit decision on this issue remains valid. The US EPA is currently rewriting the rule, and it is unknown whether revised regulations will use cost-benefit analysis.

       EME has collected data at its potentially affected Midwest Generation plants in Illinois to begin determining what corrective actions might have been needed under the previous rule. Because there are no defined compliance targets absent a new rule, EME is reviewing a wide range of possible control technologies. Although the new rule could have a material impact on EME's operations, until the final compliance criteria have been published, EME cannot reasonably determine the financial impact.

30

Illinois

       In October 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 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, the Illinois Joint Committee on Administrative Rules as well as the US EPA. Following state adoption and approval, the US EPA also must approve the rule. Hearings began in January 2008, and are continuing in 2010. Midwest Generation is a party in those proceedings. 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.

Pennsylvania

       The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 wet scrubbing system at the Homer City facilities has exceeded the stringent water-quality based limits for selenium in the station's NPDES permit. Homer City and the PADEP have entered into a consent order and agreement related to selenium discharge, effective July 17, 2007, under which 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.

Hazardous Substances and Hazardous Waste Laws

       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.

Coal Combustion Wastes

       US EPA regulations currently classify coal combustion wastes as solid wastes that are exempt from hazardous waste requirements. The exemption applies to fly ash, bottom ash, 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

31

concluded that fossil fuel combustions wastes do not warrant regulation as a hazardous waste under Subtitle C of 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. Midwest Generation currently provides a portion of its coal combustion wastes for beneficial uses. Midwest Generation is also examining the impact of current and proposed emission control technologies on ash quality for beneficial use.

       The US EPA is expected to publish proposed regulations relating to coal combustion waste in 2010. Additional regulation of the storage, disposal and beneficial reuse of coal combustion waste could affect the management of such wastes and could require EME to incur additional capital and operating costs with no assurance that the additional costs could be recovered.

Employees

       At December 31, 2009, EME and its subsidiaries employed 1,843 people, including:

•

approximately 729 employees at the Midwest Generation plants covered by a collective bargaining agreement governing wages, certain benefits and working conditions. This collective bargaining agreement will expire on December 31, 2011. Midwest Generation also has a separate collective bargaining agreement governing retirement, health care, disability and insurance benefits that expires on June 15, 2010; and

•

approximately 191 employees at the Homer City facilities covered by a collective bargaining agreement governing wages, benefits and working conditions. This collective bargaining agreement will expire on December 31, 2012.

EME's Relationship with Certain Affiliated Companies

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

ITEM 1A. RISK FACTORS

Environmental and Regulatory Risks

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 operations of EME's projects.

32

       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 an NOV and filed a lawsuit against Midwest Generation alleging violations of the CAA and certain opacity and particulate matter standards at the Midwest Generation plants and has issued an NOV alleging violations of the CAA at the Homer City facilities.

       The current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. Environmental advocacy groups, regulatory agencies, and legislators in the United States have been focusing considerable attention on CO₂ emissions from coal-fired power plants and their potential role in climate change, and the US EPA has finalized a finding that certain GHGs, including CO₂, endanger the public health and welfare. The adoption of laws and regulations to implement CO₂ controls could adversely affect coal-fired plants.

       Coal plant emissions of NO_x, SO₂, mercury and particulates are also 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.

       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 some of 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.

The controls imposed on the Midwest Generation plants as a result of the CPS may require material expenditures or unit shutdowns.

       Midwest Generation has entered into an agreement with the Illinois EPA to reduce mercury, NO_x and SO₂ emissions at the Midwest Generation plants. The agreement has been embodied in an Illinois rule called the CPS. All of Midwest Generation's Illinois coal-fired

33

electric generating units are subject to the CPS. Capital expenditures relating to controls contemplated by the CPS could be significant and could make some units uneconomic to maintain or operate. Midwest Generation may ultimately decide to comply with CPS requirements by shutting down units rather than making improvements. Midwest Generation is evaluating technology and unit shutdown combinations and 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 1. Business—Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide—Illinois."

EME is subject to extensive energy industry regulation.

       EME's operations are subject to extensive regulation by governmental agencies. EME's projects are subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, and access to transmission. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants.

       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.

       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. EME in the course of its business must obtain and periodically renew licenses, permits and approvals for its facilities. 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.

Market Risks

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

34

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

•

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

•

weather conditions prevailing in surrounding areas from time to time;

•

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

•

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

•

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

•

the cost and availability of emission credits or allowances;

•

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

•

the ability of regional pools to pay market participants' settlement prices for energy and related products;

•

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

•

legal and political challenges to the rules used to calculate capacity payments in the markets in which EME operates.

       In addition, unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced when it is to be used. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of time. Due to the volume of sales into PJM from the fossil-fueled 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.

35

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. Fuel costs can be influenced by many factors outside EME's control, including weather, market liquidity, transportation inefficiencies, demand for energy commodities (both as fuel and as feedstock for manufacturing processes), natural gas, crude oil and coal production levels, natural disasters, wars, embargoes and other catastrophic events, governmental regulation and legislation, and the creditworthiness, liquidity and willingness of fuel suppliers and transporters to do business with EME and its subsidiaries. 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 expected requirements, it is still subject to the risks of supply interruptions, transportation cost increases, and fuel price volatility. In addition, fuel deliveries will 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. All of these factors may have an adverse effect on EME's financial condition and results of operations.

EME may not hedge market risks effectively.

       EME is exposed to market risks through its ownership and operation of merchant energy power plants and through its power marketing business. These market risks include, among others, volatility arising from the timing differences associated with buying fuel, converting fuel into energy and delivering energy to a buyer. EME uses forward contracts and derivative 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's hedging activities may not cover the entire exposure of its assets or positions to market price volatility, and the level of coverage will vary over time. Amounts hedged at any given time are not indicative of amounts that may be hedged in the future. Fluctuating commodity prices may affect EME's financial results, either favorably or unfavorably, to the extent that assets and positions have not been hedged. In addition, EME's risk management strategies may not be as effective as anticipated.

       The effectiveness of EME's hedging activities may depend on the amount of credit available to post collateral, 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 contract price of the commodity and its current market price. Significant movements in market prices can result in a requirement to provide cash collateral and letters of credit in very large amounts. Without adequate liquidity to meet margin and collateral requirements, EME could be exposed to the following:

•

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

36

•

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

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

Competition could adversely affect EME's business.

       EME has numerous competitors in all aspects of its business, some of whom may have greater liquidity, greater access to credit and other financial resources, lower cost structures, larger staffs or more experience than EME. EME's competitors may be able to respond more quickly and efficiently to new laws and regulations or emerging technologies, or to devote greater resources to the development, operation, and maintenance of their power generation facilities than EME. Multiple 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. These factors 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 and may also have lower costs of operation. Over time, some of EME's merchant facilities may become obsolete in their markets, or be unable to compete with such 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.

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. The impact of proprietary trading activities on EME's financial results is affected by transmission congestion levels in wholesale power markets, the level of which cannot be predicted. These derivative contracts are recorded on its balance sheet at fair value. Some of these derivative contracts do not qualify 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 market prices.

37

Financing Risks

EME may not be able to raise capital on favorable terms, which could adversely affect its results of operation.

       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 at the fossil-fueled facilities, which could lead to the eventual shutdown of a material part of such facilities. 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. 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.

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

       As of December 31, 2009, EME's consolidated debt was approximately $4.0 billion. In addition, EME's subsidiaries had $3.2 billion of long-term, power plant lease obligations that are due over a period ranging up to 25 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, to comply with evolving environmental regulations, or to plan for and react to business and industry changes. If cash flows and capital resources were insufficient to cover scheduled debt payments, 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.

EME conducts a substantial portion of its operations through its subsidiaries and may be limited in its ability to access funds from these subsidiaries to service its debt.

       EME depends to a large degree upon dividends and other intercompany transfers of funds from its subsidiaries to meet debt service and other obligations. In addition, the ability of EME's subsidiaries to pay dividends and make other payments to EME may be restricted by, among other things, applicable corporate and other laws, potentially adverse tax consequences, and agreements entered into by the subsidiaries. If EME is unable to access the cash flow of its subsidiaries, it may have difficulty meeting its own debt obligations.

38

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 they otherwise might enter into.

       The instruments governing EME's indebtedness and the indebtedness and lease obligations 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.

       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.

The interests of Edison International as EME's equity holder may conflict with the interests of holders of debt.

       EME is indirectly owned and controlled by Edison International, which has the ability to control EME's policies and operations. The directors appointed by Edison International are able to make decisions affecting EME's capital structure which could include, subject to contractual obligations and applicable law, decisions to incur or repurchase debt, pay dividends, or otherwise take actions that may alter the portion of Edison International's portfolio of assets that is held and developed by EME. The interests of Edison International may not in all cases be aligned with the interests of the holders of EME's debt or the debt and lease obligations of EME's subsidiaries. For example, if EME encounters financial difficulties or becomes unable to pay its debts as they mature, the interests of Edison International might conflict with the interests of holders of EME's debt. In addition, Edison International may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its equity investments, even though such transactions might involve risks to EME's business or the holders of EME's debt. Furthermore, Edison International may in the future own businesses that directly or indirectly compete with EME. Edison International also may pursue acquisition opportunities that may be complementary to EME's business, and as a result, those acquisition opportunities may not be available to EME.

39

Operating Risks

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

       EME's development activities are subject to risks including, without limitation, risks related to the identification of project sites, financing, construction, permitting, governmental approvals and the negotiation of project agreements, including power purchase agreements. 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. 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. 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.

       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. If EME is not successful in developing new projects, it may be required to cancel turbine orders or sell turbines that were purchased. Such cancellations and/or sales may result in substantial losses and, under certain circumstances, may give rise to disputes with the turbine vendor. In addition, 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 to fund the capital expenditures needed to develop them, or that EME will ultimately realize a satisfactory rate of return.

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

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

•

performance below expected levels of output, efficiency or availability;

•

interruptions in fuel supply;

•

disruptions in the transmission of electricity;

•

curtailment of operations due to transmission constraints;

•

breakdown or failure of equipment or processes;

•

shortages of equipment or spare parts;

•

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

40

•

restrictions on emissions;

•

releases of hazardous substances to air, soil, surface water or groundwater;

•

inability to transport and dispose of coal ash at reasonable prices;

•

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

•

operator/contractor error; and

•

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

       These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of or damage to the environment, and suspension of operations. The occurrence of one or more of the events listed above could decrease or eliminate revenues generated by EME's projects or significantly increase the costs of operating them, and could also result in EME being named as a defendant in lawsuits asserting claims for substantial damages, potentially including environmental cleanup costs, personal injury, property damage, fines and penalties.

       Unplanned outages typically increase operation and maintenance expenditures and reduce revenues. EME could also be required to purchase replacement power in the open market to satisfy contractual commitments. 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 cause EME to lose its interest in the project.

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

41

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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

       Inapplicable.

ITEM 2. PROPERTIES

       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; Bolingbrook, Illinois; Chantilly, Virginia; and Boston, Massachusetts. The Chicago lease is for approximately 41,000 square feet and expires on December 31, 2014. A portion of the Chicago facility, representing approximately 15,000 square feet, is subleased through November 30, 2011. The Bolingbrook lease is for approximately 12,000 square feet and expires on January 1, 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, 2009, the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of EME's income before tax or is one in which EME has an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project.

Description of Properties

Plant	Location	Interest in Land	Plant Description
Homer City facilities	Pittsburgh, Pennsylvania	Owned	Coal-fired generation facility
Midwest Generation plants	Northeast Illinois	Owned	Coal, oil/gas-fired generation facilities
Sunrise	Fellows, California	Leased	Combined cycle generation facility
Sycamore	Bakersfield, California	Leased	Natural gas-turbine cogeneration facility
Watson	Carson, California	Leased	Natural gas-turbine cogeneration facility

ITEM 3. LEGAL PROCEEDINGS

Midwest Generation New Source Review Lawsuit

       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 PSD requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install controls sufficient to meet BACT emissions rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of

42

the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.

       On August 27, 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or NSR permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond those required under the CPS. By order dated January 19, 2010, the court allowed a group of Chicago-based environmental action groups to intervene in the case.

       The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by undertaking the indemnity obligation and defense of the claims.

       An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Homer City New Source Review Notice of Violation

       On June 12, 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, 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 PSD requirements of the CAA. The US EPA also alleges that 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. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. 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 cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.

       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 Homer City

43

acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.

       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 Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by undertaking the indemnity obligation and defense of the claims.

ITEM 4. RESERVED

44

PART II

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 2009 and 2008. EME made cash dividend payments totaling $925 million in 2007. Dividends from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax considerations, and restrictions imposed by applicable law. For more information about dividend restrictions in EME's corporate credit facility, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividend Restrictions in Major Financings."

45

ITEM 6. SELECTED FINANCIAL DATA

       The selected financial data was derived from EME's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report. EME's international operations are accounted for as discontinued operations, except the Doga project in Turkey. 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.

INCOME STATEMENT DATA (in millions)
		Years Ended December 31,
		2009			2008			2007			2006			2005
Operating Revenues		$	2,377		$	2,811		$	2,580		$	2,239		$	2,265
Operating Expenses
	Fuel, plant operations and plant operating lease		1,552			1,544			1,444			1,332			1,287
	Gain on buyout of contract, loss on contract, asset impairment and other charges and credits		4			14			6			—			7
	Depreciation and amortization		236			194			162			144			134
	Administrative and general		196			207			204			140			154
			1,988			1,959			1,816			1,616			1,582
Operating Income			389			852			764			623			683
Equity in income from unconsolidated affiliates			100			122			200			186			229
Impairment loss on equity method investment			—			—			—			—			(55	)
Interest and other income			24			48			103			120			69
Interest expense			(296	)		(279	)		(273	)		(279	)		(300	)
Loss on early extinguishment of debt			—			—			(160	)		(146	)		(4	)
Income from continuing operations before income taxes			217			743			634			504			622
Provision for income taxes			16			243			219			189			208
Income from continuing operations			201			500			415			315			414
Income (loss) from operations of discontinued subsidiaries, net of tax			(7	)		1			(2	)		98			29
Income before accounting change			194			501			413			413			443
Cumulative effect of change in accounting, net of tax1			—			—			—			—			(1	)
Net Income			194			501			413			413			442
Net Loss Attributable to Noncontrolling Interests			3			—			1			1			—
Net Income Attributable to EME Common Shareholders		$	197		$	501		$	414		$	414		$	442

¹

The 2005 loss from a change in accounting principle resulted from the adoption of a new accounting standard for conditional asset retirements.

46

BALANCE SHEET DATA (in millions)
	As of December 31,
	2009		2008		2007		2006		2005
Assets	$	8,633	$	9,080	$	7,272	$	7,235	$	6,655
Current liabilities		549		635		454		631		537
Long-term obligations		3,929		4,638		3,806		3,035		3,330
Total EME common shareholder's equity		2,761		2,684		1,923		2,582		1,910

47

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.

MANAGEMENT'S OVERVIEW

Introduction

       EME is a holding company whose subsidiaries and affiliates are 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 through its EMMT subsidiary.

       This overview is presented in four sections:

•

Highlights of operating results;

•

Environmental developments, including compliance activities at EME's fossil-fueled facilities, and legislative, regulatory and legal developments related to GHGs;

•

Update on EME's renewable program; and

•

Information regarding EME's liquidity.

48

Highlights of Operating Results

(in millions)		2009			2008			Change			2007
Operating revenues		$	2,377		$	2,811		$	(434	)	$	2,580
Operating expenses			1,988			1,959			(29	)		1,816
	Operating income		389			852			(463	)		764
Other income (expense)			(172	)		(109	)		(63	)		(130	)
	Income from continuing operations before income taxes		217			743			(526	)		634
	Provision for income taxes		16			243			227			219
Income from continuing operations			201			500			(299	)		415
Income (loss) from operations of discontinued subsidiaries, net of tax			(7	)		1			(8	)		(2	)
Net income			194			501			(307	)		413
Net loss attributable to noncontrolling interests			3			—			3			1
Net income attributable to EME common shareholders		$	197		$	501		$	(304	)	$	414

       The following table shows the AOI of EME's projects:

(in millions)	2009			2008			Change			2007
Midwest Generation plants	$	340		$	688		$	(348	)	$	583
Homer City facilities		186			202			(16	)		221
Renewable energy projects		53			60			(7	)		31
Energy trading		49			164			(115	)		142
Gas projects		106			128			(22	)		205
Other		9			(18	)		27			7
		743			1,224			(481	)		1,189
Corporate administrative and general		(163	)		(172	)		9			(169	)
Corporate depreciation and amortization		(15	)		(12	)		(3	)		(8	)
AOI1	$	565		$	1,040		$	(475	)	$	1,012

49

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

(in millions)		2009		2008		Change			2007
AOI		$	565	$	1,040	$	(475	)	$	1,012
Less:
	Equity in earnings of unconsolidated affiliates		100		122		(22	)		200
	Dividend income from projects		12		10		2			12
	Production tax credits		56		44		12			29
	Other income, net		5		12		(7	)		6
	Net loss attributable to noncontrolling interests		3		—		3			1
Operating Income		$	389	$	852	$	(463	)	$	764

¹

AOI is equal to operating income under GAAP, plus equity in earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.

       EME's 2009 earnings were significantly lower than 2008 primarily due to the following:

•

Lower wholesale energy prices reduced revenues from EME's merchant coal-fired generation and trading operations. The effects of the economic recession and mild weather during the summer months contributed to declines in electrical demand for the Northern Illinois and PJM West locations during 2009. Electrical load, calculated from data published by PJM, for these locations declined 5% and 3%, respectively, during 2009 compared to 2008. In addition, the price of natural gas, which often serves as the marginal fuel source in the region, declined significantly. The reduction in natural gas prices together with lower electrical demand resulted in significantly lower wholesale energy prices. The average 24-hour PJM real-time price for energy at the Northern Illinois Hub and the PJM West Hub declined to $28.86/MWh and $38.31/MWh, respectively, during 2009 as compared to $49.01/MWh and $68.56/MWh, respectively, during 2008.

•

Lower electrical load contributed to decreased transmission congestion in the eastern power grid, thereby resulting in $115 million lower trading income in 2009 as compared to 2008.

•

Higher costs were incurred at Midwest Generation to comply with the CAIR annual NO_x emission program that began in 2009 and new mercury emission controls. Partially offsetting these higher costs were cost reductions at Midwest Generation and Homer City due in part to the deferral of plant overhaul activities.

50

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

       Midwest Generation is subject to various requirements with respect to environmental compliance for the Midwest Generation plants. In 2006, Midwest Generation entered into an agreement with the Illinois EPA, which has been embodied in an Illinois rule called the CPS, to control emission of mercury, NO_x and SO₂ from its coal-fired plants. During 2008 and 2009, Midwest Generation installed equipment to reduce its mercury emissions. During 2009, Midwest Generation also conducted tests of NO_x removal technology based on SNCR and SO₂ removal using FGD technology based on dry sodium sorbent injection that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NO_x portion of the CPS. Capital expenditures for installation of SNCR technology are expected to be approximately $88 million in 2010 and $70 million in 2011.

       Testing of FGD technology based on injection of dry sodium sorbent demonstrated significant reductions in SO₂ emissions when using the low-sulfur coal employed by Midwest Generation; however, further analysis and evaluation is required to determine the appropriate method to comply with the SO₂ portion of the CPS. Use of FGD technology based on injection of dry sodium sorbent in combination with Midwest Generation's use of low-sulfur coal is expected to require substantially less capital and installation time than dry scrubber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of the plants. Midwest Generation may also combine the use of dry sorbent injection technology with upgrades to its particulate removal systems to meet environmental regulations.

       Midwest Generation does not yet know what specific method of SO₂ removal will be used or the total costs that will be incurred to comply with the CPS. Any decision regarding whether or not to proceed with the above or other approaches to compliance remains subject to further analysis and the evaluation of several factors, including market conditions, regulatory and legislative developments, and forecasted capital and operating costs. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, the particular controls that will be installed, and the resulting capital commitments may not occur for up to two years for some of the units and potentially further out for others. Midwest Generation could elect to shut down units when required in order to comply with the SO₂ removal requirements of the CPS. Midwest Generation continues to evaluate various scenarios and cannot predict the extent of shutdowns and retrofits or the particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS.

Midwest Generation New Source Review Lawsuit

       In August 2009, the US EPA and the State of Illinois filed a lawsuit against Midwest Generation in Illinois federal court based on claims contained in a 2007 NOV regarding alleged violations of the New Source Performance Standards of the CAA, the CAA's Title V operating permit requirements and applicable opacity and particulate matter standards.

51

Midwest Generation is contesting such claims. The lawsuit seeks, among other things, substantial monetary penalties and an injunction requiring Midwest Generation to install controls sufficient to meet BACT emissions rates as determined by the court at all units subject to the lawsuit. See "Legal Proceedings—Midwest Generation New Source Review Lawsuit" for further discussion. Should liability of Midwest Generation be established, remedies ordered by the court could go beyond what is required for compliance with the CPS.

Homer City Environmental Issues and Capital Resource Limitations

       Homer City operates SCR equipment on all three units to reduce NO_x emissions, operates FGD equipment on Unit 3 to reduce SO₂ emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations under the CAIR and Pennsylvania mercury regulations. If required, the timing of such compliance remains uncertain. Homer City projects that if FGD equipment becomes required, it would need to make capital commitments for such equipment three to four years in advance of the effectiveness of such requirements. Homer City continues to review technologies available to reduce SO₂ and mercury emissions and to monitor developments related to mercury and other environmental regulations. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual or other obligation to provide funding to Homer City.

Greenhouse Gas Regulation Developments

       The nature of future environmental regulation and legislation will have a substantial impact on EME. EME believes that resolution of current uncertainties about the future, through well-balanced and appropriately flexible regulation and legislation, is needed to support the necessary evolution of the electric industry into using cleaner, more efficient infrastructure and to attract the capital ultimately needed for this effort. Legislative, regulatory, and legal developments related to potential controls over GHG emissions in the United States are ongoing. Actions to limit or reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels. EME may not be able to recover these costs through market prices for electricity.

       Recent significant developments include the following:

•

Legislation to regulate GHG emissions continues to be considered by Congress; however, the timing, content, and potential effects on EME and its subsidiaries of any GHG legislation that may be enacted remain uncertain.

•

In December 2009, the US EPA issued a final finding that certain GHGs, including CO₂, threaten the public health and welfare. The US EPA has issued a proposed rule, known as the "GHG tailoring rule," under which all new and major modifications of existing stationary sources emitting 25,000 metric tons of CO₂ equivalents annually,

52

including power plants, would be required to include BACT to minimize their GHG emissions. Since the current proposal affects only new or modified resources, it is not expected to have any immediate effect, if adopted, on existing fossil-fuel generating stations of Midwest Generation or Homer City, but it could affect the cost of new construction or modifications. The US EPA could also use its authority in the future to regulate existing sources of GHG emissions. If controls are required to be installed at the facilities of EME in order to reduce GHG emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

•

Three recent court cases addressed the question of whether power plants that emit GHGs constituted public nuisances that could be held liable for damages or other remedies. In one case (in which Edison International is a named defendant); a California federal district court dismissed the plaintiffs' claims. Although EME was not named as a defendant, the complaint identified EME as a direct or indirect operating subsidiary of Edison International through which Edison International engages in electric power generation. In the other two cases, federal courts of appeals permitted the suits to go forward. Each of these differing results remains subject to appeal and thus the ultimate impact of these cases remains uncertain. EME cannot predict whether these recent decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims.

EME's Renewable Program

       EME has a development pipeline of potential wind projects with projected installed capacity of approximately 4,000 MW at January 31, 2010 compared to approximately 5,000 MW at December 31, 2008. The decline in the pipeline is primarily due to the transfer of projects into construction and cost containment efforts resulting in the reduction in the number of projects funded under our joint development agreements. EME had purchase contracts for 512 MW of wind turbines for future projects as of December 31, 2009. EME plans to deploy these wind turbines when projects meet acceptable financial thresholds, have long-term power sales agreements, and can attract long-term project financing. If EME is unable to develop such projects on acceptable terms and conditions, certain turbine orders may be terminated. Such an event would likely result in a material charge.

       At December 31, 2009, EME had two projects under construction: the 240 MW Big Sky wind project, and the 150 MW Cedro Hill wind project, which are scheduled for completion in early 2011 and late 2010, respectively. EME has obtained financing for the Big Sky wind project ($206 million). During the first quarter of 2010, EME commenced construction of the 130 MW Taloga wind project located in Oklahoma and executed a power sales agreement for an 80 MW project located in Nebraska, referred to as the Laredo Ridge wind project. After designating turbines for these projects, EME has reduced its available turbines for future projects to 302 MW.

53

EME's Liquidity

       EME intends to focus on a selective growth strategy, focusing primarily on the completion of renewable energy projects under construction and the development of similar projects which deploy current turbines in storage and on order. In 2010, EME anticipates capital expenditures of $1.3 billion to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EME intends to negotiate turbine payment deferrals, where possible. EME has secured financing of $206 million through vendor financing and anticipates funds from U.S. Treasury grants filed during the first quarter of 2010 totaling $92 million. EME intends to seek project level financing for wind projects in construction during 2010.

       The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2009:

(in millions)	EME			Midwest Generation
Commitment	$	600		$	500
Less: Commitment from Lehman Brothers subsidiary		(36	)		—
		564			500
Outstanding borrowings		—			—
Outstanding letters of credit		(101	)		(3	)
Amount available	$	463		$	497

       Recognizing the uncertainties faced by independent power producers and coal generators, in particular, EME is continuing to restrain the use of its cash for discretionary capital expenditures in order to preserve liquidity pending future decisions about capital expenditures for environmental compliance by its coal fleet.

54

RESULTS OF OPERATIONS

Introduction

       This section discusses operating results in 2009, 2008 and 2007. EME's continuing operations primarily include the fossil-fueled facilities, renewable energy and gas-fired projects, energy trading, corporate interest expense and general and administrative expenses. EME's discontinued operations include all international operations, except the Doga project.

Results of Continuing Operations

Overview

       EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the fossil-fueled 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.

       The following section and table provide a summary of results of EME's operating projects and corporate expenses for the three years ended December 31, 2009, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

       The following table shows the AOI of EME's projects:

	Years Ended December 31,
(in millions)	2009			2008			2007
Midwest Generation plants	$	340		$	688		$	583
Homer City facilities		186			202			221
Renewable energy projects		53			60			31
Energy trading		49			164			142
Big 4 projects		46			87			147
Sunrise		37			24			33
Doga		8			8			14
March Point		11			—			—
Westside projects		4			9			11
Other projects		9			13			13
Other operating income (expense)		—			(31	)		(6	)
		743			1,224			1,189
Corporate administrative and general		(163	)		(172	)		(169	)
Corporate depreciation and amortization		(15	)		(12	)		(8	)
AOI1	$	565		$	1,040		$	1,012

55

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

		Years Ended December 31,
(in millions)		2009		2008		2007
AOI		$	565	$	1,040	$	1,012
Less:
	Equity in earnings of unconsolidated affiliates		100		122		200
	Dividend income from projects		12		10		12
	Production tax credits		56		44		29
	Other income, net		5		12		6
	Net loss attributable to noncontrolling interests		3		—		1
Operating Income		$	389	$	852	$	764

¹

AOI is equal to operating income under GAAP, plus equity in earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.

Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

       The following table presents additional data for the Midwest Generation plants:

		Years Ended December 31
(in millions)		2009			2008			2007
Operating Revenues		$	1,487		$	1,778		$	1,579
Operating Expenses
	Fuel1		547			482			400
	Gain on sale of emission allowances2		(1	)		(3	)		(18	)
	Plant operations		397			434			420
	Plant operating leases		75			75			75
	Depreciation and amortization		109			106			99
	(Gain) on buyout of contract and (gain) loss on disposal of assets		2			(16	)		—
	Administrative and general		21			22			22
	Total operating expenses		1,150			1,100			998
Operating Income			337			678			581
Other Income			3			10			2
AOI		$	340		$	688		$	583

56

			Years Ended December 31
(in millions)			2009		2008		2007
Statistics3
	Generation (in GWh):
		Energy only contracts		28,977		26,010		22,503
		Load requirements services contracts		1,333		5,090		7,458
	Total			30,310		31,100		29,961
	Aggregate plant performance:
		Equivalent availability		85.3%		81.0%		75.8%
		Capacity factor		63.3%		64.8%		60.9%
		Load factor		74.2%		80.0%		80.4%
		Forced outage rate		5.8%		8.3%		9.7%
	Average realized price/MWh:
		Energy only contracts	$	41.17	$	51.82	$	48.79
		Load requirements services contracts	$	62.52	$	62.64	$	63.43
	Capacity revenue only (in millions)		$	178	$	111	$	27
	Average realized fuel costs/MWh		$	18.54	$	15.49	$	13.36

¹

Included in fuel costs were $63 million, $5 million and $5 million in 2009, 2008 and 2007, respectively, related to the net cost of emission allowances. Midwest Generation purchased NO_x emission allowances from Homer City at fair market value. Purchases were $1 million and $0.4 million in 2009 and 2007, respectively. There were no purchases in 2008. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

²

Midwest Generation sold excess SO₂ emission allowances to Homer City at fair market value. Sales to Homer City were $2 million in 2008 and $21 million in 2007. There were no sales in 2009. These sales reduced operating expenses. Midwest Generation recorded $3 million of intercompany profit during 2008 consisting of $1 million and $2 million on emission allowances sold by Midwest Generation to Homer City during the first quarter of 2008 and the fourth quarter of 2007, respectively, but not yet used by Homer City until the second quarter of 2008 and the first quarter of 2008, respectively. In addition, Midwest Generation recorded $4 million of intercompany profit during 2007 that was eliminated by Midwest Generation in 2006 on emission allowances sold by Midwest Generation to Homer City in the fourth quarter of 2006 but not used by Homer City until the first quarter of 2007.

³

For an explanation of how the statistical data is determined, see "Non-GAAP Disclosures—Fossil-Fueled Facilities" and "Statistical Definitions."

       AOI from the Midwest Generation plants decreased $348 million in 2009 compared to 2008, and increased $105 million in 2008 compared to 2007. The 2009 decrease in AOI was primarily attributable to a decline in realized gross margin, partially offset by an increase in unrealized gains related to hedge contracts (described below), and lower plant operations expense. The decline in realized gross margin was primarily due to a 21% decline in average realized energy prices resulting from lower energy prices and higher fuel costs to comply with the CAIR annual NO_x emission program that began in 2009 and to implement new mercury emission controls. This decline was partially offset by higher capacity revenue primarily due to higher capacity prices from the RPM auctions. Plant operations expense was lower in 2009 as compared to 2008 due to cost containment efforts and the deferral of plant overhaul activities.

57

       Lower wholesale power prices reduced revenues from the Midwest Generation plants in 2009. The effects of the economic recession and mild weather during the summer months contributed to declines in electrical demand for the Northern Illinois Hub location during 2009. Electrical load, calculated from data published by PJM, for this location declined 5% during 2009 compared to 2008. In addition, the price of natural gas, which often serves as the marginal fuel source in the region, declined significantly. The reduction in natural gas prices together with lower electrical demand resulted in significantly lower energy prices. The average 24-hour PJM real-time price for energy at the Northern Illinois Hub declined to $28.86/MWh during 2009 as compared to $49.01/MWh during 2008.

       The 2008 increase in AOI 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. The increase in realized gross margin was due to an increase in capacity prices as a result of the RPM auctions. The increase in generation and slightly higher average realized energy prices was partially offset by higher coal and transportation costs.

       Included in operating revenues were unrealized gains (losses) of $30 million, $(6) million and $(25) million in 2009, 2008 and 2007, respectively. Unrealized gains in 2009 were primarily due to hedge contracts that are not accounted for as cash flow hedges (referred to as economic hedges). In addition, $14 million was reversed from accumulated other comprehensive income and recognized in 2009 related to the power contracts with Lehman Brothers Commodity Services, Inc. Unrealized losses in 2008 included a $24 million write-down of power contracts with Lehman Brothers Commodity Services, Inc. for 2009 and 2010 generation. These contracts qualified as cash flow hedges until EME dedesignated the contracts due to nonperformance risk and subsequently terminated the contracts. The change in fair value was recorded as an unrealized loss during 2008. In addition, unrealized gains (losses) included the ineffective portion of hedge contracts at the Midwest Generation plants attributable to changes in the difference between energy prices at NiHub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system) resulting from marginal losses. Unrealized losses in 2007 were also attributable to energy contracts that 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.

       Included in fuel expenses were unrealized gains of $15 million for the year ended December 31, 2009 due to oil futures contracts that were accounted for as economic hedges. The contracts were entered into in 2009 to hedge a portion of a fuel adjustment provision of a rail transportation contract. For more information regarding forward market prices and unrealized gains (losses), see "Market Risk Exposures—Commodity Price Risk" and "Results of Operations—Accounting for Derivative Instruments," respectively.

58

Powerton Station Outage

       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, which have been settled and paid. 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.

Homer City

       The following table presents additional data for the Homer City facilities:

		Years Ended December 31,
(in millions)		2009		2008		2007
Operating Revenues		$	663	$	717	$	764
Operating Expenses
	Fuel1		251		270		306
	Loss on sale of emission allowances		1		—		—
	Plant operations		102		126		119
	Plant operating leases		102		102		102
	Depreciation and amortization		16		16		14
	Loss on sale of assets		1		—		—
	Administrative and general		4		4		4
	Total operating expenses		477		518		545
Operating Income			186		199		219
Other Income			—		3		2
AOI		$	186	$	202	$	221
Statistics2
	Generation (in GWh)		11,446		11,334		13,649
	Equivalent availability		84.7%		80.7%		89.4%
	Capacity factor		69.2%		68.3%		82.5%
	Load factor		81.7%		84.6%		92.4%
	Forced outage rate		9.4%		9.8%		4.1%
	Average realized energy price/MWh	$	48.85	$	56.24	$	54.40
	Capacity revenue only (in millions)	$	89	$	46	$	30
	Average fuel costs/MWh	$	21.89	$	23.35	$	22.45

¹

Included in fuel costs were $16 million, $20 million and $31 million in 2009, 2008 and 2007, respectively, related to the net cost of emission allowances. Homer City purchased SO₂ emission allowances from Midwest Generation at fair market value. Purchases were $2 million in 2008 and $21 million in 2007. There were no purchases in 2009. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

²

For an explanation of how the statistical data is determined, see "Non-GAAP Disclosures-Fossil-Fueled Facilities" and "Statistical Definitions."

59

       AOI from the Homer City facilities decreased $16 million in 2009 compared to 2008 and $19 million in 2008 compared to 2007. The 2009 decrease in AOI was primarily attributable to a decline in realized gross margin partially offset by lower plant operations expense. The decline in realized gross margin was primarily due to a 13% decline in average realized energy prices, partially offset by an increase in capacity revenues and lower coal costs. The decline in plant operations expense was due to cost containment efforts and the deferral of plant overhaul activities.

       Lower wholesale power prices reduced revenues from the Homer City facilities in 2009. The effects of the economic recession and mild weather during the summer months contributed to declines in electrical demand for the PJM West location during 2009. Electrical load, calculated from data published by PJM, for this location declined 3% during 2009 compared to 2008. In addition, the price of natural gas, which often serves as the marginal fuel source in the region, declined significantly. The reduction in natural gas prices together with lower electrical demand resulted in significantly lower energy prices. The average 24-hour PJM real-time price for energy at the PJM West Hub declined to $38.31/MWh during 2009 as compared to $68.56/MWh during 2008.

       The 2008 decrease in AOI compared to 2007 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 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 operating revenues were unrealized gains (losses) from hedge activities of $15 million, $21 million and $(10) million in 2009, 2008 and 2007, 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. The ineffective portion of hedge contracts at Homer City was 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). For more information regarding forward market prices and unrealized gains (losses), see "Market Risk Exposures—Commodity Price Risk" and "Results of Operations—Accounting for Derivative Instruments," respectively.

       The average realized energy price received by Homer City in 2009, 2008 and 2007 was $48.85/MWh, $56.24/MWh and $54.40/MWh, respectively, compared to the 24-hour average historical market price at the Homer City busbar for the same periods of $34.91/MWh, $57.72/MWh and $51.03/MWh, respectively. The average realized energy price for 2009 was above the 24-hour PJM average historical market price at the Homer City busbar due to hedge contracts entered into in prior periods. 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

60

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 "Results of Operations—Accounting for Derivative Instruments."

Non-GAAP Disclosures—Fossil-Fueled Facilities

Adjusted Operating Income (Loss)

       AOI is equal to operating income plus other income (expense) for the fossil-fueled facilities. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is meaningful for investors as the components of other income (expense) are integral to the results of the fossil-fueled facilities.

Average Realized Energy Price

       The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized gains (losses) and other non-energy related revenue by (ii) generation as shown in the table below. Revenue related to capacity sales are excluded from the calculation of average realized energy price.

		Years Ended December 31,
Midwest Generation Plants (in millions)
		2009			2008			2007
Operating revenues		$	1,487		$	1,778		$	1,579
Less:
	Load requirements services contracts		(83	)		(319	)		(473	)
	Unrealized (gains) losses		(30	)		6			25
	Capacity and other revenues		(181	)		(117	)		(33	)
Realized revenues		$	1,193		$	1,348		$	1,098
Generation—energy only contracts (in GWh)			28,977			26,010			22,503
Average realized energy price/MWh			$41.17			$51.82			$48.79

		Years Ended December 31,
Homer City (in millions)
		2009			2008			2007
Operating revenues		$	663		$	717		$	764
Less:
	Unrealized (gains) losses		(15	)		(21	)		10
	Capacity and other revenues		(89	)		(59	)		(31	)
Realized revenues		$	559		$	637		$	743
Generation (in GWh)			11,446			11,334			13,649
Average realized energy price/MWh			$48.85			$56.24			$54.40

61

       The average realized energy price is presented as an aid in understanding the operating results of the fossil-fueled facilities. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the Midwest Generation plants operating revenues to consolidated operating revenues presented in the preceding table is set forth below:

		Years Ended December 31,
(in millions)		2009		2008		2007
Operating revenues
	Midwest Generation plants	$	1,487	$	1,778	$	1,579
	Homer City facilities		663		717		764
	Renewable energy projects		141		108		51
	Other revenues		86		208		186
Consolidated operating revenues as reported		$	2,377	$	2,811	$	2,580

Average Realized Fuel Costs

       The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including the effects of hedges. It is determined by dividing (i) fuel expense adjusted for unrealized gains (losses) by (ii) generation as shown in the table below.

		Years Ended December 31,
Midwest Generation Plants (in millions)
		2009		2008		2007
Fuel expenses		$	547	$	482	$	400
Add back:
	Unrealized gains		15		—		—
Realized fuel expenses		$	562	$	482	$	400
Total generation (in GWh)			30,310		31,100		29,961
Average realized fuel costs/MWh			$18.54		$15.49		$13.36

       The average realized fuel costs are presented as an aid in understanding the operating results of the Midwest Generation plants. Average realized fuel costs are a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel expenses. Management believes that average realized fuel costs are meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the Midwest Generation

62

plants fuel expense to consolidated fuel expense presented in the preceding table is set forth below.

		Years Ended December 31,
(in millions)		2009			2008			2007
Fuel expense
	Midwest Generation plants	$	547		$	482		$	400
	Homer City facilities		251			270			306
	Other		(2	)		(5	)		(22	)
Consolidated fuel expense as reported		$	796		$	747		$	684

Statistical Definitions

•

Generation from load requirements services contracts represents two load requirements services contracts, awarded as part of an Illinois auction, with Commonwealth Edison that commenced on January 1, 2007. One contract expired in May 2008 and the remaining contract expired in May 2009.

•

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

•

The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.

•

The load factor is determined by dividing capacity factor by the equivalent availability factor.

•

The forced outage rate refers to unplanned maintenance outages and forced deratings.

•

The average realized price for load requirements service contracts reflects the contract price for sales to Commonwealth Edison under load requirements services contracts that include energy, capacity and ancillary services. It is determined by dividing (i) operating revenue related to the contracts by (ii) generation.

Seasonal Disclosure—Fossil-Fueled Facilities

       In 2009, the seasonal fluctuations in electric demand normally occurring for the fossil-fueled facilities were minimized by milder winter conditions and cooler than normal summer months. Normally, due to fluctuations in electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the fossil-fueled 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, AOI from the fossil-fueled facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be

63

affected by changes in market prices. For further discussion regarding market prices, see "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities."

Renewable Energy Projects

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

			Years Ended December 31,
(in millions)			2009		2008		2007
Operating Revenues			$	141	$	108	$	51
Production Tax Credits				56		44		29
				197		152		80
Operating Expenses
	Plant operations			55		35		18
	Depreciation and amortization			92		59		34
	Administrative and general			3		2		1
	Total operating expenses			150		96		53
Other Income				3		4		3
Net Loss Attributable to Noncontrolling Interests				3		—		1
AOI1			$	53	$	60	$	31
Statistics2
	Generation (in GWh)			3,081		2,286		1,533
	Aggregate plant performance:
		Equivalent availability		88.7%		80.4%		85.5%
		Capacity factor		31.4%		33.1%		37.8%

¹

AOI is equal to operating income (loss) plus production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles AOI as shown above to operating income (loss) under GAAP:

		Years Ended December 31
(in millions)		2009			2008		2007
AOI		$	53		$	60	$	31
Less:
	Production tax credits		56			44		29
	Other income		3			4		3
	Net loss attributable to noncontrolling interests		3			—		1
Operating Income (Loss)		$	(9	)	$	12	$	(2	)

²

The statistics section summarizes key performance measures related to wind projects, which represents substantially all of the renewable energy projects.

64

       AOI from renewable energy projects decreased $7 million in 2009 compared to 2008, and increased $29 million in 2008 compared to 2007. The 2009 decrease in AOI was primarily attributable to mild wind conditions, which reduced the revenue increases relative to the increased operating costs associated with additional projects coming on line. Expenses incurred for projects under construction also contributed to the decrease in AOI. New projects that commenced operations were the primary drivers for increases in the revenues and operating costs and AOI in 2008. EME's share of installed capacity of new wind projects that commenced operations during 2009, 2008 and 2007 was 223 MW, 396 MW and 292 MW, respectively.

       EME's operating wind projects include 189 turbines manufactured by Suzlon Wind Energy Corporation (Suzlon). During 2008 and through the third quarter of 2009, EME's operations were impacted by rotor blade cracks in certain Suzlon Model S88 wind turbines using V-2 blades. To address the commercial impact of these issues on EME and its projects, during the second quarter of 2008 and fourth quarter of 2009, EME entered into agreements with Suzlon providing EME with enhanced warranty and credit protections. 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 provided liquidated damages for unavailability of turbines. AOI in 2009 and 2008 included $17 million and $28 million ($4 million related to 2007 generation), respectively, of the Suzlon liquidated damages. At December 31, 2009, EME had a receivable from Suzlon of $20 million. Suzlon completed the blade remediation program to resolve the blade cracking issue in August 2009. Turbine availability has improved since the blade remediation and liquidated damage claims have decreased accordingly. The blade cracking issue appears to be resolved, but further operating experience will be required to confirm.

Energy Trading

       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 U.S. power grid using products available over the counter, through exchanges, and from ISOs. AOI from energy trading activities decreased $115 million in 2009 compared to 2008, and increased $22 million in 2008 compared to 2007. The 2009 decrease in AOI from energy trading activities was attributable to lower transmission congestion in the eastern U.S. power grid. The 2008 increase in AOI from energy trading activities was primarily attributable to increased transmission congestion and market volatility in key markets. In addition, energy trading included favorable results for load service transactions in 2009 and 2008.

Adjusted Operating Income from Unconsolidated Affiliates

Big 4 Projects

       AOI from the Big 4 projects decreased $41 million in 2009 compared to 2008, and $60 million in 2008 compared to 2007. The 2009 decrease in AOI was primarily due to lower natural gas prices affecting electricity and steam revenues. The 2008 decrease in AOI was primarily due to $60 million in lower AOI from the Sycamore and Watson projects as a result

65

of lower pricing in 2008 than previously applied under a long-term power sales agreement that expired.

       On September 28, 2009, Midway-Sunset entered into a power purchase agreement with Pacific Gas and Electric Company, subject to CPUC approval. For further discussion regarding power sales from the Midway-Sunset, Sycamore and Watson projects, all of which are currently selling power to SCE under the terms and conditions contained in their prior long-term power purchase agreements, with revised pricing terms as mandated by CPUC Decision 07-09-040, dated September 20, 2007, see "Item 1. Business—Overview of Facilities—Contracted Power Plants-Domestic—Natural Gas—Big 4 Projects."

Sunrise

       AOI from the Sunrise project increased $13 million in 2009 from 2008 and decreased $9 million in 2008 from 2007. The 2009 increase was primarily due to higher availability incentive payments in 2009 and lower maintenance expenses. The 2008 decrease was primarily due to lower availability incentive payments in 2008 and higher maintenance expenses due to unplanned outages in 2008.

March Point

       In 2009, EME recommenced recording its share of equity in income from the March Point project and recorded $11 million for the year. Although EME's investment in the project was determined to be fully impaired in 2005, declining natural gas prices reduced fuel expenses and returned the project to profitability. To the extent that cash is received from the project in excess of EME's investment, such amount will be included in equity in income from unconsolidated affiliates on EME's consolidated statements of income. In February 2010, EME received an $18 million equity distribution from the March Point project. EME subsequently sold its ownership interest in the March Point project to its partner.

Seasonal Disclosure

       EME's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.

Doga

       AOI from the Doga project decreased $6 million in 2008 compared to 2007. Effective March 31, 2007, EME accounted for its ownership in the Doga project on the cost method (AOI is recognized when cash is distributed from the project). AOI from Doga were higher in 2007 when EME's investment was fully recovered and AOI was recognized based on distributions received from the Doga project.

Other Operating Income (Expense)

       Other operating income (expense) in 2009 included a small gain on the sale of a portion of EME's solar project development pipeline, offset by a write-down of capitalized costs

66

related to a development project during the fourth quarter of 2009. Other operating income (expense) in 2008 resulted from a charge of $23 million related to the termination of a turbine supply agreement in connection with the Walnut Creek project and a $7 million 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.

Corporate Administrative and General Expenses

       Corporate administrative and general expenses decreased $9 million in 2009 from 2008. The 2009 decrease resulted from lower project development consulting costs. In April 2009, EME reduced approximately 75 positions in its regional and corporate offices. Cost reductions related to the reduction in positions were offset by lower capitalized labor costs in 2009.

Interest Related Income (Expense)

			Years Ended December 31,
(in millions)			2009			2008			2007
Interest income			$	7		$	26		$	85
Interest expense:
	EME debt			(267	)		(254	)		(215	)
	Non-recourse debt:
		Midwest Generation		(7	)		(14	)		(45	)
		EME Funding		—			—			(2	)
		EME CP Holding Co.		(5	)		(5	)		(6	)
		Viento Funding II, Inc.1		(9	)		—			—
		Other projects		(8	)		(6	)		(5	)
			$	(296	)	$	(279	)	$	(273	)
Loss on early extinguishment of debt			$	—		$	—		$	(160	)

¹

In June 2009, a subsidiary of EME, Viento Funding II, Inc., completed a non-recourse financing of EME's interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For further details of this financing, see "—Viento Funding II Wind Financing."

       Interest income decreased $19 million in 2009 from 2008 and $59 million in 2008 from 2007. The 2009 decrease was primarily attributable to lower interest rates in 2009 compared to 2008. 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.

       EME's interest expense to third parties, before capitalized interest, increased $4 million in 2009 from 2008 and $14 million in 2008 from 2007. The 2009 increase was primarily due to higher debt balances under EME's credit facility in 2009, compared to 2008, and EME's wind financing in June 2009. The 2008 increase primarily resulted from EME's refinancing activities in May 2007. Capitalized interest decreased $13 million in 2009, compared to 2008, and increased $8 million in 2008, compared to 2007. The 2009 decrease resulted from a reduction in projects under construction. The 2008 increase was primarily due to wind projects under construction.

67

       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.

Income Taxes

       EME's effective tax rates were 7%, 33% and 34%, respectively, for the years ended December 31, 2009, 2008 and 2007. The effective tax rate for 2009 was impacted by lower pretax income in relation to the level of production tax credits and estimated state income tax benefits allocated from Edison International. Production tax credits for wind projects of $56 million, $44 million and $29 million were recognized for the years ended December 31, 2009, 2008 and 2007, respectively. Estimated state income tax benefits allocated from Edison International of $15 million, $5 million and $10 million were recognized for the years ended December 31, 2009, 2008 and 2007, respectively. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 11. Income Taxes."

       Effective January 1, 2009, Massachusetts changed its tax regulations to require affiliated corporations to file tax returns on a combined basis. As a result of this change, Edison International and its subsidiaries will file tax returns on a combined basis in Massachusetts beginning with 2009 tax returns. Prior to 2009, tax returns were filed on a separate return basis.

       In May 2009, Edison International and the Internal Revenue Service completed a settlement of federal tax disputes and affirmative claims for open tax years 1986 through 2002. As a result, state tax years for the same periods are now open pending review by state taxing authorities of agreed final federal adjustments. The settlement includes the resolution of issues pertaining to EME which were largely timing in nature. During the second quarter of 2009, EME recorded an income tax benefit of $6 million due to the settlement and related estimated impact of interest and state income taxes. The amount recorded is subject to change based on the final determination of interest and state taxes and items affected under the tax-allocation agreement.

Results of Discontinued Operations

       Loss from discontinued operations, net of tax, increased $8 million in 2009 compared to 2008. Results in 2009 and 2008 included foreign exchange gains (losses) and interest expense associated with contract indemnities related to EME's sale of international projects in December 2004. In addition, EME increased its estimated liability for a tax indemnity by $6 million during the second quarter of 2009.

Related-Party Transactions

       EME owns interests in partnerships that sold electricity generated by their project facilities to SCE and others under the terms of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $366 million, $686 million and $747 million in 2009, 2008 and 2007, respectively.

68

New Accounting Guidance

       New accounting guidance is discussed in Note 1—Summary of Significant Accounting Policies—New Accounting Guidance under "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements."

Accounting for Derivative Instruments

       EME uses derivative instruments to reduce its exposure to market risks that arise from fluctuations in the prices of electricity, capacity, fuel, emission allowances, and transmission rights. For derivative instruments recorded at fair value, changes in fair value are recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting. For derivatives that 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.

       EME classifies unrealized gains and losses from derivative instruments as part of operating revenues or fuel expenses. The results of derivative activities are recorded as part of cash flows from operating activities on 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, 2009:

		Years Ended December 31,
(in millions)		2009		2008			2007
Midwest Generation plants
	Non-qualifying hedges	$	40	$	(16	)	$	(14	)
	Ineffective portion of cash flow hedges		5		10			(11	)
Homer City facilities
	Non-qualifying hedges		1		1			(1	)
	Ineffective portion of cash flow hedges		14		20			(9	)
Total unrealized gains (losses)		$	60	$	15		$	(35	)

       At December 31, 2009, unrealized gains of $47 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($40 million for 2010 and $7 million for 2011).

Fair Value of Derivative Instruments

       In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EME's derivative instruments, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Fair Value Measurements" and "—Note 3. Derivative Instruments and Risk Management," respectively.

69

Non-Trading Derivative Instruments

       The fair value of outstanding non-trading commodity derivative instruments at December 31, 2009 and 2008 was $215 million and $375 million, respectively. In assessing the fair value of EME's non-trading commodity derivative 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 decrease in the fair value of commodity contracts at December 31, 2009 as compared to December 31, 2008 is attributable to the settlement of contracts in 2009 that were entered into in 2008 at higher prices than contracts outstanding at December 31, 2009. A 10% change in the market price of the underlying commodity at December 31, 2009 would increase or decrease the fair value of outstanding non-trading commodity derivative instruments by approximately $102 million. Since these non-trading commodity derivative instruments are economic hedges, an increase or decrease in fair value would be offset by an increase or decrease in the cash flows of the underlying asset. The change in the fair value of the derivative and the change in cash flows from the economically hedged item may not be recognized in operating revenues in the same periods.

       Level 1 derivative positions include exchange-traded derivatives. Level 2 derivative positions include derivatives whose fair value is based on forward market prices in active markets adjusted for nonperformance risks when there are no unobservable inputs that are significant to the valuation. EME considers active markets to be those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. 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.

Energy Trading Derivative Instruments

       The fair value of outstanding energy trading derivative instruments at December 31, 2009 and 2008 was $122 million and $112 million, respectively. The change in the fair value of trading contracts for the year ended December 31, 2009 was as follows:

(in millions)
Fair value of trading contracts at January 1, 2009	$	112
Net gains from energy trading activities		55
Amount realized from energy trading activities		(46	)
Other changes in fair value		1
Fair value of trading contracts at December 31, 2009	$	122

70

       A 10% change in the market price of the underlying commodity at December 31, 2009 would increase or decrease the fair value of trading contracts by approximately $1 million. The impact of changes to the various inputs used to determine the fair value of Level 3 derivatives would not be anticipated to be material to EME's results of operations as such changes would be offset by similar changes in derivatives classified within Level 3 as well as other categories.

       Level 1 derivative positions include exchange-traded derivatives. Level 2 derivative positions include non-exchange-traded derivatives. These derivatives are priced based on forward market prices adjusted for nonperformance risks 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 instruments.

       Inactive markets are considered to be those markets with few transactions, long-term pricing or prices that vary over time. EME's transactions in Level 3 may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the duration of the contract or EME is only able to obtain indicative broker quotes that cannot be corroborated by observable market data. In such cases, fair values for Level 3 derivative positions are 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 accounted for as derivatives, 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. EME's assets and liabilities classified as Level 3 represent approximately 42% of EME's total assets and 6% of EME's total liabilities measured at fair value before the impact of offsetting collateral and netting at December 31, 2009.

71

LIQUIDITY AND CAPITAL RESOURCES

EME's Liquidity

       At December 31, 2009, EME and its subsidiaries had cash and cash equivalents of $796 million and a total of $960 million of available borrowing capacity under their credit facilities. EME's consolidated debt at December 31, 2009 was $4.0 billion, of which $37 million was current. In addition, EME's subsidiaries had $3.2 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 25 years.

       The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2009:

(in millions)	EME			Midwest Generation
Commitment	$	600		$	500
Less: Commitment from Lehman Brothers subsidiary		(36	)		—
		564			500
Outstanding borrowings		—			—
Outstanding letters of credit		(101	)		(3	)
Amount available	$	463		$	497

       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.

       EME intends to focus on a selective growth strategy, focusing primarily on the completion of renewable energy projects under construction and the development of similar projects which deploy current turbines in storage and on order. In 2010, EME anticipates capital expenditures of $1.3 billion (as described in the proceeding table) to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EME intends to negotiate turbine payment deferrals, where possible. EME has secured financing of $206 million through vendor financing and anticipates funds from U.S. Treasury grants filed during the first quarter of 2010 totaling $92 million. EME intends to seek project level financing for wind projects in construction during 2010.

       EME may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

72

Capital Investment Plan

       The previously expected and actual capital expenditures for 2009, and the currently estimated capital expenditures for 2010 through 2012 by EME's subsidiaries for existing projects, corporate activities and turbine commitments are as follows:

(in millions)		2009 Expected1		2009 Actual		2010		2011		2012
Midwest Generation Plants
	Plant capital expenditures	$	65	$	54	$	72	$	79	$	10
	Environmental expenditures2		48		24		98		70		—
Homer City Facilities
	Plant capital expenditures		29		19		31		52		24
	Environmental expenditures		8		7		5		3		22
Renewable Projects
	Capital and construction expenditures3		73		171		746		—		—
	Turbine commitments4,5		706		265		357		22		—
Other capital expenditures			35		8		20		17		9
Total		$	964	$	548	$	1,329	$	243	$	65

¹

Anticipated expenditures as previously disclosed in EME's Annual Report on Form 10-K for the year ended December 31, 2008.

²

Environmental expenditures include primarily expenditures related to SNCR equipment. Additional expenditures are anticipated, however, the amounts and timing have not been determined. For additional discussion, see "Item 1. Business—Environmental Matters and Regulations."

³

Includes projects beginning construction in January 2010 and $206 million in turbine purchases for 2010 where financing has been arranged. For further discussion, see "Project-Level Financing" below.

⁴

Turbine commitments related to the Taloga and Laredo Ridge wind projects totaling $106 million are excluded from turbine commitments and included in capital and construction expenditures in 2010. Turbine commitment figures for 2010 include amounts subject to dispute under provisions in one of the turbine supply agreements.

⁵

Amounts exclude balance of project costs for 302 MW available for new projects, which would be an additional $225 million to $350 million based on typical project costs.

       In 2009, EME incurred plant capital expenditures related to the fossil-fueled facilities consistent with anticipated expenditures and EME's cost containment efforts. Environmental expenditures for 2009 were lower than anticipated due to the selection of lower cost environmental compliance equipment.

       Capital and construction expenditures for renewable projects were higher than anticipated in 2009 due to the addition of the Big Sky and Cedro Hill wind projects in construction. Expenditures for turbine commitments were lower than anticipated in 2009 due to the deferral of turbine payments and deliveries, and the conversion of deliveries to optional purchases.

73

       Turbine commitments are shown below:

		2009			2010			2011
Disclosed in EME's 2008 Annual Report on Form 10-K		$	706		$	232		$	—
	Deferrals and conversions to options		(271	)		207			23
	Transfers to construction		(182	)		(184	)		(3	)
	2009 actual additional commitments and adjustments1		12			102			2
		$	265		$	357		$	22

¹

Changes relate to options, installation and delivery costs. Turbine commitment figures for 2010 include amounts subject to dispute under provisions in one of the turbine supply agreements.

       One of EME's existing turbine supply agreements can be terminated for convenience. Termination of this agreement in its entirety would further reduce turbine commitments by $84 million during 2010. In the event of such termination by EME, a write-off of approximately $21 million would be recognized. Another of EME's existing turbine supply agreements can be terminated for cause or for convenience. If EME terminates the agreement, this election is likely to lead to a dispute regarding grounds for termination and/or available remedies, among other matters.

Project-Level Financing

       In October 2009, EME, through its subsidiary, Big Sky, entered into turbine financing arrangements totaling approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project. For further details, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Financial Instruments."

Estimated Expenditures for Existing Projects

       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.

       Environmental expenditures at Homer City relate to emission monitoring and control projects. Midwest Generation is subject to various commitments with respect to environmental compliance. Midwest Generation continues to review all technology and unit shutdown combinations, including interim and alternative compliance solutions. For more information on the current status of environmental improvements in Illinois, see "Management's Overview—Environmental Developments" and "Item 1. Business—Environmental Matters and Regulations."

74

       The preceding capital expenditures table includes the following projects that commenced construction or were awarded a power sales contract subsequent to December 31, 2009:

Taloga Wind Project

       The Taloga wind project is a 130 MW wind project in Oklahoma scheduled for completion in late 2010. EME commenced construction activities in February 2010. EME plans to use wind turbines currently in storage to complete the Taloga wind project. The remaining costs to complete the project, including construction and turbine transportation and installation, are expected to be approximately $89 million. In January 2010, the project entered into a 20-year power purchase agreement with Oklahoma Gas and Electric Company.

Laredo Ridge Wind Project

       The Laredo Ridge wind project is an 80 MW wind project in Nebraska scheduled for completion in late 2010. In February 2010, EME allocated turbines under one of its existing turbine supply agreements for 53 wind turbines to complete the Laredo Ridge wind project. The remaining costs to complete the project, including turbine payments, construction, and turbine transportation and installation, are expected to be approximately $177 million. The Laredo Ridge wind project is being developed under a joint development agreement. EME intends to purchase the project in the second quarter of 2010. The project has contracted to sell power to the Nebraska Public Power District under a 20-year power sales contract.

Estimated Expenditures for Future Projects

       EME had a development pipeline of potential wind projects with projected installed capacity of approximately 4,000 MW at January 31, 2010. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. EME has wind turbines in storage and on order for wind projects under construction and to be used for future wind projects (turbine commitments are reflected separately in the preceding capital expenditure table). Successful completion of development of a wind project depends upon obtaining permits and agreements necessary to support an investment and 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.

Walnut Creek Project

       Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a 10-year power sales contract starting in 2013 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. 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 a November 2008 decision, the Los Angeles Superior Court enjoined SCAQMD from issuing Priority Reserve emission credits to Walnut Creek and other projects. Legal challenges related to the Priority Reserve emission credits are continuing. Legislation that passed the State Assembly and is currently pending in the Senate would provide access to the credits for

75

Walnut Creek, subject to further regulatory steps and litigation risk. 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 qualifying credits. Construction on the Walnut Creek project will not begin until its access to the Priority Reserve emission credits is restored or another source of credits is identified. The capital costs to construct this project, excluding interest, are estimated in the range of $500 million to $600 million.

EME's Historical Consolidated Cash Flow

       This section discusses EME's consolidated cash flows from operating, financing and investing activities.

Condensed Consolidated Statement of Cash Flows

	Years Ended December 31,
(in millions)	2009			2008			2007
Operating cash flow from continuing operations	$	258		$	728		$	519
Operating cash flow from discontinued operations		(7	)		1			(2	)
Net cash provided by operating activities		251			729			517
Net cash provided by (used in) financing activities		(714	)		844			(417	)
Net cash used in investing activities		(548	)		(760	)		(319	)
Net increase (decrease) in cash and cash equivalents	$	(1,011	)	$	813		$	(219	)

Consolidated Cash Flows from Operating Activities

       The 2009 decrease in cash provided by operating activities from continuing operations was primarily attributable to lower realized revenues due to lower market prices in 2009, compared to 2008 and a decrease in margin deposits received from counterparties at December 31, 2009.

       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.

Consolidated Cash Flows from Financing Activities

       The 2009 increase in cash used in financing activities from continuing operations was attributable to repayments of $376 million and $475 million under EME's corporate credit facility and Midwest Generation's working capital facility, respectively. These repayments were partially offset by proceeds received from the issuance of a $189 million term loan as part of a $202 million project financing completed in June 2009.

       The 2008 increase in cash provided by financing activities from continuing operations was attributable to an increase in borrowings in 2008 under EME's corporate credit facility and

76

Midwest Generation's working capital facility. In addition, EME received $12 million from the minority shareholders of the Elkhorn Ridge wind project.

Consolidated Cash Flows from Investing Activities

       Excluding the impact of changes in short-term investments (described below), cash used in investing activities is 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 $562 million in 2009, $889 million in 2008 and $838 million in 2007. The changes in the level of expenditures are primarily due to investments for renewable energy projects. Included in investments in other assets were turbine deposits for wind projects prior to the commencement of construction of $265 million in 2009, $213 million in 2008, and $271 million in 2007.

       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 considered cash equivalents and are classified as part of cash and cash equivalents in the consolidated balance sheet. Maturities of short-term investments are included as a source of cash from investing activities and have decreased during the past two years primarily due to EME curtailing its purchase of short-term investments.

       Other factors that impacted investing activities included:

•

payments of $22 million and $19 million during 2009 and 2008, respectively, toward the purchase price of wind projects;

•

proceeds of $28 million from the sale of 33% of EME's membership interest in the Elkhorn Ridge wind project during the second quarter of 2008; and

•

payments of $22 million during 2007 towards the purchase price of new wind projects, payment of $24 million during 2007 to acquire an option to purchase specific projects, and payments of $11 million towards the purchase price of the Wildorado wind project during 2007.

Credit Ratings

Overview

       Credit ratings for EME, Midwest Generation and EMMT are as follows:

	Moody's Rating	S&P Rating	Fitch Rating
EME1	B2	B	BB-
Midwest Generation2	Ba1	BB-	BBB-
EMMT	Not Rated	B	Not Rated

¹

Senior unsecured rating.

²

First priority senior secured rating.

77

       The S&P and Fitch ratings are on negative outlook, while the Moody's rating outlook is stable. 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. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, 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. For discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."

Credit Rating of EMMT

       The Homer City sale-leaseback documents restrict Homer City's ability to enter into derivative 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 also include a requirement that Homer City's counterparty to such transactions, whether it is EMMT or another party, and Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and Homer City is not rated. In order to continue to sell forward the output of the Homer City facilities through EMMT, EME has obtained a consent from the sale-leaseback owner participants that allows Homer City to enter into such sales, under specified conditions, through March 1, 2014. Homer City continues to be in compliance with the terms of the consent; however, because EMMT's credit rating has dropped below BB-, the consent is revocable by the sale-leaseback owner participants at any time. The sale-leaseback owner participants have not indicated that they intend to revoke the consent; however, there can be no assurance that they will not do so in the future. An additional consequence of EMMT's lowered credit rating is that outstanding accounts receivable between EMMT and Homer City have been reduced to zero, as required under the terms of the consent. Revocation of the consent would not affect trades between EMMT and Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market on the terms set forth in the Homer City sale-leaseback documents. For further discussion, see "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

       To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required

78

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, 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, 2009, EMMT had deposited $85 million in cash with clearing brokers in support of futures contracts and had deposited $35 million in cash with counterparties in support of forward energy and congestion contracts. Cash collateral provided to others offset against derivative liabilities totaled $49 million at December 31, 2009. In addition, EME had received cash collateral of $124 million at December 31, 2009, to support credit risk of counterparties under margin agreements; $68 million of which is classified as restricted cash. The liability for margin deposits received from counterparties has been offset against net derivative assets.

       Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2009, if wholesale energy prices change or additional transactions are entered into. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of December 31, 2009 could increase by approximately $90 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, 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. EMMT also has hedge contracts that do not require margin, 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 all derivative instruments with credit-risk-related contingent features is in an asset position on December 31, 2009 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 additional collateral postings under the contingent features described above.

       Midwest Generation has cash on hand and a credit facility to support margin requirements specifically related to contracts entered into by EMMT related to the Midwest Generation plants. In addition, EME has cash on hand and a credit facility to provide credit support to subsidiaries. For discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "—EME's Liquidity." Also, for further discussion, see "—EME's Liquidity as a Holding Company."

79

EME's Liquidity as a Holding Company

Overview

       At December 31, 2009, EME had corporate cash and cash equivalents and short-term investments of $415 million to meet liquidity needs as well as $463 million of capacity under its credit facility. EME's corporate cash and cash equivalents include $180 million pertaining to EME as a stand alone holding company, as well as cash and cash equivalents related to EMMT (which can be lent or distributed to EME, subject to applicable corporate and other laws). 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. For further discussion, see "—Dividend Restrictions in Major Financings."

Intercompany Tax-Allocation Agreement

       EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient 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. In connection with the settlement of federal tax disputes and affirmative claims with the Internal Revenue Service for open tax years 1986 through 2002, EME made a payment of $18 million and assigned a tax receivable of $125 million to its parent, Mission Energy Holding Company, in satisfaction of its obligations under a tax-allocation agreement in the second quarter of 2009. In addition, EME received net tax-allocation payments of $166 million in 2009 and made net tax-allocation payments to Edison International of $95 million and $112 million in 2008 and 2007, respectively.

80

EME's Credit Facility Financial Ratios

       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 following details of EME's interest coverage ratio and a maximum corporate-debt-to-corporate-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements.

       The following table sets forth the major components of the interest coverage ratio for the 12 months ended December 31, 2009 and 2008:

			Years Ended December 31,
(in millions)			2009			2008
Funds Flow Available for Interest
	Distributions
		Midwest Generation1	$	200		$	206
		Homer City2		75			110
		Big 4 Projects3		62			114
		Viento Funding II, Inc.4		167			—
		Other projects		88			55
	Tax payments received from subsidiaries			68			364
	Realized trading income			36			175
	Tax allocation receipts (payments)			139			(92	)
	Operating expenses			(151	)		(155	)
	Other items, net			(14	)		(14	)
			$	670		$	763
Net Interest Expense
	EME corporate debt		$	261		$	248
	Addback: Capitalized interest			19			32
	Powerton-Joliet intercompany notes			112			112
	EME interest income			(2	)		(6	)
			$	390		$	386
Ratio				1.72			1.98
Covenant threshold (not less than)				1.20			1.20

¹

In January 2010, Midwest Generation made an equity distribution payment of $30 million.

²

Under EME's credit facility, the definition of interest coverage ratio includes the repayment of subordinated loans to Homer City. During 2009, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $25 million to Homer City which were repaid by Homer City and are included in distributions in 2009.

³

Prior to the repayment of the Series B bonds of EME Funding Corp. in September 2008, distributions from the Big 4 projects represented funds transferred to EME after debt service and restricted cash provisions set forth in this financing.

⁴

The proceeds of the Viento Funding II wind financing, net of financing costs, were distributed to EME.

81

       The following table sets forth the major components of the corporate-debt-to-corporate-capital ratio at December 31, 2009 and 2008:

			December 31,
(in millions)			2009			2008
Corporate Debt
	Indebtedness for money borrowed		$	3,700		$	4,564
	Powerton-Joliet termination value			1,046			1,163
	Letters of credit			104			132
			$	4,850		$	5,859
Corporate Capital
	Common shareholder's equity		$	2,761		$	2,684
	Less:
		Non-cash cumulative changes in accounting		1			1
		Accumulated other comprehensive income		(78	)		(200	)
	Adjustments:
		After-tax losses incurred on termination of Collins lease		587			587
		Dividend to MEHC for repayment of 13.5% notes		899			899
				4,170			3,971
	Corporate debt			4,850			5,859
			$	9,020		$	9,830
Corporate-debt-to-corporate-capital ratio				0.54			0.60
Covenant threshold (not more than)				0.75			0.75

Dividend Restrictions in Major Financings

General

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

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

       Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at December 31, 2009 or for the 12 months ended December 31, 2009:

Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation (Midwest Generation plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.18 to 1
Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.96 to 1

82

Midwest Generation Financing Restrictions on Distributions

       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.

Homer City

       Homer City completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, 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 12-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 Homer City less amounts paid for operating expenses, capital expenditures funded by Homer City, 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 12-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 has not guaranteed Homer City's obligations under the leases.

EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries

       EME's corporate credit agreement contains covenants that restrict its ability and the ability of several of its subsidiaries to make distributions. This restriction impacts the subsidiaries that own interests in the Westside projects, the Sunrise project, the fossil-fueled facilities, and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME's shareholder if an event of default were to occur and be continuing under EME's secured credit agreement after giving effect to the distribution.

EME's Senior Notes and Guaranty of Powerton-Joliet Leases

       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 and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in

83

such agreements computed as of the end of the most recent fiscal quarter preceding such sale or disposition. At December 31, 2009, the maximum sale or disposition of EME assets is determined as follows:

(in millions)			December 31, 2009
Consolidated Net Tangible Assets
	Total consolidated assets		$	8,633
	Less:
		Consolidated current liabilities		(549	)
		Intangible assets		(99	)
			$	7,985
10% Threshold			$	799

       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.

       As a wholly owned indirect subsidiary of Edison International, EME is subject to determinations made by its directors, each of whom is appointed by Edison International, to act in the interests of Edison International and its shareholders, which may result in EME making distributions of cash or assets, subject to the limitations described above and applicable law, at any time or from time to time, which may affect assets held or under development.

Viento Funding II Wind Financing

       In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The financing included a $189 million seven-year term loan and a $13 million letter of credit facility, which replaced project letters of credit previously issued under the EME corporate credit facility. In July 2009, Viento Funding II amended the credit agreement to add a working capital facility. Availability under the working capital facility is initially $3.8 million and increases semi-annually to $5.2 million by maturity. The agreement restricts the use of proceeds from the working capital facility to operation and maintenance expenditures at these three wind projects.

       Distributions from Viento Funding II are subject to compliance with the terms and conditions of its credit facilities, including a covenant to meet a 12-month historic debt service coverage ratio as specified in the agreements of 1.20 to 1.0. Viento Funding II's payment obligations are secured by pledges of its direct and indirect ownership interests in the three wind projects.

84

Contractual Obligations, Commercial Commitments and Contingencies

Contractual Obligations

       EME has contractual obligations and other commercial commitments that represent prospective cash requirements. The following table summarizes EME's significant consolidated contractual obligations as of December 31, 2009.

				Payments Due by Period
(in millions)		Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years
Long-term debt1		$	6,481	$	322	$	640	$	1,088	$	4,431
Operating lease obligations2			3,448		353		665		627		1,803
Purchase obligations3:
	Capital improvements		441		441		—		—		—
	Turbine commitments		485		463		22		—		—
	Fuel supply contracts		932		457		475		—		—
	Gas transportation agreements		68		8		16		17		27
	Coal transportation		388		244		144		—		—
	Other contractual obligations		236		84		127		25		—
Employee benefit plan contribution4			24		24		—		—		—
Total Contractual Obligations5,6		$	12,503	$	2,396	$	2,089	$	1,757	$	6,261

¹

For additional details, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Financial Instruments." Amount also includes interest payments totaling $2.5 billion over applicable period of the debt.

²

At December 31, 2009, minimum operating lease payments were primarily related to long-term leases for the Powerton and Joliet Stations and the Homer City facilities. For further discussion, see "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies."

³

For additional details, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies."

⁴

Amount includes estimated contribution for pension plans and postretirement benefits other than pensions. The estimated contributions beyond 2010 are not available. For more information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 12. Compensation and Benefit Plans—Pension Plans and Postretirement Benefits Other than Pensions."

⁵

At December 31, 2009, EME had a total net liability recorded for uncertain tax positions of $97 million, which is excluded from the table. EME cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the Internal Revenue Service. For more information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 11. Income Taxes."

⁶

The contractual obligations table does not include derivative obligations and AROs, which are discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Derivative Instruments and Risk Management," and "—Note 9. Property, Plant and Equipment," respectively.

85

Commercial Commitments

Standby Letters of Credit

       As of December 31, 2009, standby letters of credit under EME and its subsidiaries' credit facilities aggregated $119 million and were scheduled to expire as follows: $111 million in 2010 and $8 million in 2011.

Contingencies

       EME's significant contingencies related to the Midwest Generation NSR lawsuit, the Homer City NSR NOV, environmental remediation, and environmental developments are discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies."

Off-Balance Sheet Transactions

Introduction

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

Investments Accounted for under the Equity Method

       EME has a number of investments in power projects that are accounted for under the equity method. Under the equity method, the project assets and related liabilities are not consolidated 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.

       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 long-term debt that is 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 not require EME to contribute additional capital. At December 31, 2009, entities which EME has accounted for under the equity method had indebtedness of $245 million, of which $104 million is proportionate to EME's ownership interest in these projects.

Sale-Leaseback Transactions

       EME has entered into sale-leaseback transactions related to the Powerton Station and Units 7 and 8 of the Joliet Station in Illinois and the Homer City facilities in Pennsylvania. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to

86

Consolidated Financial Statements—Note 13. Commitments and Contingencies—Lease Commitments."

       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 on its consolidated financial statements, but constitute continuing involvement 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 on 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 $35 million, $46 million and $54 million in 2009, 2008 and 2007, respectively.

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

Power Station(s)	Acquisition Price		Equity Investor	Original Equity Investment in Owner/Lessor (in millions)		Amount of Lessor Debt at December 31, 2009		Maturity Date of Lessor Debt
Powerton/Joliet	$	1,367	PSEG/Citigroup, Inc.	$	238	$	—    Series A		2009
							679    Series B		2016
Homer City		1,591	GECC/Metropolitan		798	$	219    Series A		2019
			Life Insurance				506    Series B		2026
			Company

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

       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

87

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, 2009.

		Years Ended December 31,
(in millions)		2009		2008		2007
Cash payments under plant operating leases
	Powerton and Joliet facilities	$	185	$	185	$	185
	Homer City facilities		151		152		151
Total cash payments under plant operating leases		$	336	$	337	$	336
Rent expense
	Powerton and Joliet facilities	$	75	$	75	$	75
	Homer City facilities		102		102		102
Total rent expense		$	177	$	177	$	177

       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, 2009 and 2008, prepaid rent on these leases was $1,038 million and $878 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. In addition, a default under the terms of the Powerton and Joliet leases would trigger obligations under EME's guarantee of such leases. These events could have a material adverse effect on EME's results of operations and financial position.

EME's Obligations to Midwest Generation

       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 and used by EME to repay corporate indebtedness. Although interest and principal payments made by EME to Midwest Generation under an intercompany loan assist in the payment of the lease rental payments owed by Midwest Generation, the intercompany obligation does not appear on

88

EME's consolidated balance sheet. The following table summarizes principal payments due under this intercompany loan:

Years Ending December 31,     (in millions)		Principal Amount		Interest Amount		Total
	2010	$	5	$	112	$	117
	2011		9		111		120
	2012		11		110		121
	2013		12		110		122
	2014		544		109		653
	Thereafter		766		72		838
	Total	$	1,347	$	624	$	1,971

       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.

Environmental Matters and Regulations

       For a discussion of environmental matters and regulations, see "Item 1. Business."

89

MARKET RISK EXPOSURES

Introduction

       EME's primary market risk exposures are associated with the sale of electricity and capacity from, and the procurement of fuel for, its merchant power plants. These market risks arise from fluctuations in the prices of electricity, capacity, fuel, 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 instruments in accordance with established policies and procedures.

Commodity Price Risk

Introduction

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

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

       EME uses estimates of the variability in gross margin to help identify, measure, monitor and control its overall market risk exposure and earnings volatility with respect to hedge positions at the fossil-fueled facilities, and the merchant wind projects, and uses "value at risk" metrics to help identify, measure, monitor and control its overall risk exposure with respect to its trading positions. These measures allow management to aggregate overall commodity risk, compare risk on a consistent basis and identify changes in risk factors. Value at risk measures the possible loss, and variability in gross margin 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 volumetric exposure limits.

Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities

       Energy and capacity from the fossil-fueled facilities are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot

90

market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City facilities. These trading hubs have been the most liquid locations for hedging purposes. See "—Basis Risk" below for further discussion.

       The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated:

		24-Hour Average Historical Market Prices1
		2009		2008		2007
Midwest Generation plants
	Northern Illinois Hub	$	28.86	$	49.01	$	45.53
Homer City facilities
	PJM West Hub	$	38.31		68.56		59.87
	Homer City Busbar		34.91		57.72		51.03

¹

Energy prices were calculated at the respective delivery points using historical hourly real-time prices as published by PJM or provided on the PJM web-site.

       The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at December 31, 2009:

	24-Hour Forward Energy Prices1
	Northern Illinois Hub		PJM West Hub
2010 calendar "strip"2	$	33.87	$	48.04
2011 calendar "strip"2	$	34.73	$	49.43

¹

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



²

Market price for energy purchases for the entire calendar year.

       Forward market prices at the Northern Illinois Hub and 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 fossil-fueled facilities into these markets may vary materially from the forward market prices set forth in the preceding table.

91

       EMMT engages in hedging activities for the fossil-fueled facilities to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions as of December 31, 2009 for electricity expected to be generated in 2010 and 2011:

		2010				2011
		MWh (in thousands)		Average price/ MWh1		MWh (in thousands)		Average price/ MWh1
Midwest Generation plants
	Northern Illinois and AEP/Dayton Hubs		19,717	$	42.66		1,428	$	59.64
Homer City facilities
	PJM West Hub		3,673		79.25		29		54.47
Total			23,390				1,457

¹

The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above. Furthermore, the average price/MWh for 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.

       In addition, as of December 31, 2009, EMMT has entered into 3.3 billion cubic feet of natural gas futures contracts (equivalent to approximately 557 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks during 2010 at an average price of $38.40/MWh.

Capacity Price Risk

       On June 1, 2007, PJM implemented the RPM for capacity. Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for capacity resources. The RPM is intended to provide a mechanism for PJM to meet the region's need for generation capacity, while allocating the cost to load-serving entities through a locational reliability charge.

92

       The following table summarizes the status of capacity sales for Midwest Generation and Homer City at December 31, 2009:

									RPM Capacity Sold in Base Residual Auction				Other Capacity Sales, Net of Purchases2
		Installed Capacity MW		Unsold Capacity1 MW			Capacity Sold MW		MW		Price per MW-day		MW			Average Price per MW-day		Aggregate Average Price per MW-day
January 1, 2010 to May 31, 2010
	Midwest Generation		5,776		(878	)		4,898		5,329	$	102.04		(431	)	$	99.23	$	102.29
	Homer City		1,884		(206	)		1,678		1,670		191.32		8			191.32		191.32
June 1, 2010 to May 31, 2011
	Midwest Generation		5,477		(548	)		4,929		4,929	$	174.29		—			—		174.29
	Homer City		1,884		(71	)		1,813		1,813		174.29		—			—		174.29
June 1, 2011 to May 31, 2012
	Midwest Generation		5,477		(495	)		4,982		4,582	$	110.00		400			85.00		107.99
	Homer City		1,884		(113	)		1,771		1,771		110.00		—			—		110.00
June 1, 2012 to May 31, 2013
	Midwest Generation		5,477		(773	)		4,704		4,704	$	16.46		—			—		16.46
	Homer City		1,884		(148	)		1,736		1,736		133.37		—			—		133.37

¹

Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.

²

Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.

       The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $16.46 per MW-day was substantially lower than previous capacity prices. The decrease in forward capacity prices was attributable to a substantial increase in demand side management resources. The impact of lower capacity prices for this period will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices, which is uncertain.

       Revenues from the sale of capacity from Midwest Generation and 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, demand side management activities and the cost of new entry.

Basis Risk

       Sales made from the fossil-fueled 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

93

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 Midwest Generation plants. EME's hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. 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 2009, 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 9%, compared to 16% during 2008 and 15% during 2007. During 2009, transmission congestion in PJM has resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 14% and less than 1%, respectively, compared to 10% and 2%, respectively, during 2008.

       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 Homer City and Midwest Generation. A financial transmission right is a financial instrument that entitles the holder to receive the difference between 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.

Coal and Transportation Price Risk

       The Midwest Generation plants and 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. The following table summarizes the amount of coal under contract at December 31, 2009 for the following three years:

	Amount of Coal Under Contract in Millions of Equivalent Tons1
	2010		2011		2012
Midwest Generation plants2		17.3		9.8		9.8
Homer City facilities3		4.6		2.3		1.2

¹

The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the Homer City facilities.

²

In January and February 2010, Midwest Generation entered into additional contractual agreements for the purchase of 1 million tons for 2010 and 2 million tons for 2011.

³

In January 2010, Homer City exercised options under existing contractual agreements for the purchase of 0.3 million tons for 2011, 0.5 million tons for 2012 and 0.5 million tons for 2013. In February 2010, Homer City entered into additional contractual agreements for the purchase of 0.4 million tons for 2011.

94

       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, decreased during 2009 from 2008 and increased substantially during 2008 from 2007. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) decreased to a price of $52.50 per ton at December 31, 2009, compared to a price of $76 per ton at January 9, 2009, as reported by the EIA. In 2009, the price of NAPP coal ranged from $43.50 per ton to $76 per ton, as reported by the EIA. The 2009 decrease in NAPP coal prices was due in part to current global economic conditions that have lessened demand for coal, high levels of inventories and fuel switching. In 2008, the price of NAPP coal ranged from $61.75 per ton to $150 per ton, as reported by the EIA. 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.

       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 Midwest Generation plants declined during 2009 from 2008 year-end prices and increased during 2008 from 2007 year-end prices. The price of PRB coal fluctuated between $8.25 per ton and $13 per ton during 2009, with a price of $9.25 per ton at December 31, 2009, as reported by the EIA. The 2009 decrease in PRB coal prices was due to lower demand and higher levels of inventory. In 2008, the price of PRB coal fluctuated between $11 per ton to $14.50 per ton, 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, 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 short-haul 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 approximately half of the delivered cost of PRB coal to the Midwest Generation plants).

       Based on EME's anticipated coal requirements in 2010 in excess of the amount under contract, EME expects that a 10% change in the price of coal at December 31, 2009 would increase or decrease pre-tax income in 2010 by approximately $6 million.

Emission Allowances Price Risk

       The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, electric generating stations also are required to hold seasonal and annual NO_x allowances beginning January 1, 2009. As part of the acquisition of the fossil-fueled facilities, EME obtained emission allowance rights 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. For further discussion of the CAIR, see "Item 1. Business—Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide."

       In the event that actual emissions required are greater than allownces held, EME is subject to price risk for purchases of emission allowances. The market price for emission

95

allowances may vary significantly. The average purchase price of SO₂ allowances was $65 per ton in 2009, $315 per ton in 2008 and $512 per ton in 2007. The average purchase price of annual NO_x allowances was $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_x allowances was $60 per ton and $665 per ton, respectively, at December 31, 2009.

       Based on EME's anticipated annual and seasonal NO_x requirements for 2010 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, 2009 would increase or decrease pre-tax income in 2010 by approximately $0.7 million.

Credit Risk

       In conducting EME's hedging and trading activities, EME enters into transactions with 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 market price changes occurring since the original contract was executed if the nonperforming 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 evaluates the risk of potential defaults by counterparties. Credit risk is measured as 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.

       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,

96

2009, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

		December 31, 2009
(in millions)		Exposure2		Collateral			Net Exposure
Credit Rating1
	A or higher	$	267	$	(102	)	$	165
	A-		53		—			53
	BBB+		54		—			54
	BBB		57		—			57
	BBB-		35		—			35
	Below investment grade		12		(12	)		—
Total		$	478	$	(114	)	$	364

¹

EME assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

²

Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable.

       The credit risk exposure set forth in the above table is comprised of $160 million of net accounts receivable and payables and $318 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $120 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

       The majority of EME's consolidated wind projects and unconsolidated affiliates that own power plants sell power under power purchase agreements. Generally, each project or plant sells its output to one counterparty. A default by the counterparty, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of the project or plant.

       Coal for the fossil-fueled facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the fossil-fueled 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.

       The fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 48% of EME's consolidated

97

operating revenues for the year ended December 31, 2009. 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. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At December 31, 2009, EME's account receivable due from PJM was $50 million.

       For the year ended December 31, 2009, a second customer, Constellation Energy Commodities Group, Inc., accounted for 16% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from the fossil-fueled facilities and consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which at December 31, 2009 had a senior unsecured debt rating of BBB- by S&P and Baa3 by Moody's. At December 31, 2009, EME's account receivable due from Constellation was $36 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 EME's turbine suppliers may have a material impact on EME's wind projects and development efforts.

Interest Rate Risk

       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. In June 2009, EME's subsidiary, Viento Funding II, Inc., entered into interest rate swap agreements in connection with the non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For details, see "Liquidity and Capital Resources—Viento Funding II Wind Financing." A 10% change in market interest rates at December 31, 2009 would increase or decrease the fair value of the interest rate swap agreements by approximately $2 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 $3.2 billion at December 31, 2009, compared to the carrying value of $4.0 billion. A 10% increase in market interest rates at December 31, 2009 would result in a decrease in the fair value of total long-term obligations by approximately $174 million. A 10% decrease in market interest rates at December 31, 2009 would result in an increase in the fair value of total long-term obligations by approximately $192 million.

98

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Introduction

       The accounting policies described below are considered critical to obtaining an understanding of EME's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing EME's consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or if different estimates that could have been selected had been used could have a material impact on EME's results of operations or financial position.

Derivatives

       Nature of Estimates Required.    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. Certain 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.

       EME uses derivative instruments for hedging activities and trading purposes. Derivative instruments are mainly utilized by EME to manage exposure to changes in electricity and fuel prices and interest rates. Derivative commodity instruments include forward sales transactions entered into on a bilateral basis with third parties, futures contracts, full requirements services contracts or load requirements services contracts, and capacity transactions. Financial derivative instruments include interest rate swaps entered into on a bilateral basis with counterparties. EME follows authoritative guidance on derivatives and hedging, which requires derivative instruments to be recorded at fair value unless an exception applies. Authoritative guidance 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.

       EME records derivative instruments used for trading utilizing the fair value model. EME's derivative instruments with a short-term duration (less than one year) are normally valued using quoted market prices. In the absence of quoted market prices, derivative instruments with a short-term duration 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 on the accompanying consolidated income statements.

       Derivative assets include open derivative positions recorded at fair value, including cash flow hedges, that are "in-the-money" and the present value of net amounts receivable from

99

structured transactions. Derivative liabilities include open derivative positions, including cash flow hedges, that are "out-of-the-money." Where 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 on the balance sheet.

       Key Assumptions and Approach Used.    EME determines the fair value of its derivatives based on forward market prices in active markets adjusted for nonperformance risk. If quoted market prices are not available, internally developed models are used to determine the fair value. 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 nonperformance 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 nonperformance.

       In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. For further information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Fair Value Measurements."

       Effect if Different Assumptions Used.    As described above, fair value is determined using a combination of market information or observable data and unobservable inputs which reflect management's assumptions. Changes in observable data would impact results. In addition, unobservable inputs could have an impact on results. Fair value for Level 3 derivatives is derived using observable and unobservable inputs. As of December 31, 2009, Level 3 derivatives had a net fair value of $173 million. While it is difficult to determine the impact of a change in any one input, if the fair value of Level 3 derivatives were increased or decreased by 10%, the impact would be a $17 million increase or decrease to operating revenues.

       For EME's derivative instruments that are measured at fair value using quantitative pricing models, a significant change in estimate could affect EME's results of operations. For further sensitivities in EME's assumptions used to calculate fair value, see "Results of Operations—Fair Value of Derivative Instruments." For further information on derivative instruments, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Derivative Instruments and Risk Management."

Impairment of Long-Lived Assets

       Nature of Estimates Required.    EME evaluates its long-lived assets, including intangible assets, for impairment in accordance with applicable authoritative guidance. The amount of the impairment charges, if applicable, are calculated as the excess of the asset's carrying value over its fair value, which represents the discounted expected future cash flows attributable to the asset or, in the case of assets expected to be sold, at fair value less costs to sell. Authoritative guidance requires that if the undiscounted expected future cash flow from a

100

company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be recognized on the financial statements. EME evaluates its long-lived assets for impairment whenever indicators of impairment exist or when EME commits to sell the asset. These evaluations may result from significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as economic or operational analyses. If the carrying amount is not recoverable, an impairment charge is recorded.

       Key Assumptions and Approach Used.    The assessment of impairment requires significant management judgment 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 determination of fair value requires management to apply judgment in: (1) estimating future prices of energy and capacity in wholesale energy markets and fuel prices that are susceptible to significant change, (2) environmental and maintenance expenditures, and (3) the time period due to the length of the estimated remaining useful lives.

       Effect if Different Assumptions Used.    The estimates and assumptions used to determine whether an impairment exists are subject to a high degree of uncertainty. The estimated fair value of an asset would change materially if different estimates and assumptions were used to determine the amounts or timing of future revenues, environmental compliance costs or operating expenditures. If actual results are not consistent with the assumptions used in estimating future cash flows and asset fair values, EME may be exposed to additional losses that could be material to EME's results of operations.

Merchant Coal-Fired Power Plants

       Weak commodity prices and heightened public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants similar to EME's, which may require significant capital and increased operating costs to meet environmental requirements. Management has reviewed long-term cash flow forecasts that included assumptions about future electricity and fuel prices, future capacity payments under the PJM RPM, and future capital expenditure requirements under different scenarios. Assumptions included in the long-term cash flow forecasts included:

•

Observable market prices for electricity and fuel to the extent available and long-term prices developed based on a fundamental price model;

•

Long-term capacity prices based on the assumption that the PJM RPM capacity market would continue consistent with its current structure, with expected increases in revenue as a result of declines in reserve margins beyond the price of the latest auctions; and

•

Multiple plans for compliance with environmental regulations.

101

       If commodity prices do not increase consistent with the fundamental forecast or if EME decides not to install additional environmental control equipment and, instead, shuts down one or more coal-fired power plants, the forecasted cash flow would be less than expected. If the undiscounted expected cash flow measured at a plant level were less than the net book value of the asset group, an impairment charge would be recognized. The amount of an impairment charge would be calculated as the excess of the net book value of the asset group over its fair value, which generally represents the discounted future cash flows attributable to the asset group.

       If EME decides to implement an environmental compliance plan that results in shutting down one or more coal-fired power plants or results in a shorter useful life, in addition to preparing an impairment analysis and possibly recording a related impairment of the plant, the remaining useful life of the plant would need to be adjusted to reflect the revised shorter life. The impact on annual depreciation could be significant.

       EME includes allocated acquired emission allowances as part of each power plant asset group. In the case of the Powerton and Joliet Stations, EME also includes prepaid rent in the respective 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.

Accounting for Contingencies, Guarantees and Indemnities

       Nature of Estimates Required.    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. When a guarantee or indemnification subject to authoritative guidance is entered into, EME records a liability for the estimated fair value of the underlying guarantee or indemnification. Gain contingencies are recognized in the financial statements when they are realized.

       Key Assumptions and Approach Used.    The determination of a reserve for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, EME may consider the following factors, among others: the nature of the litigation, claim or assessment, available information, opinions or views of legal counsel and other advisors, and the experience gained from similar cases. EME provides disclosures for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred. Some guarantees and indemnifications could have a significant financial impact under certain circumstances, and management also considers the probability of such circumstances occurring when estimating the fair value.

       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, 2009, EME had recorded an

102

estimated liability of $96 million (of which $56 million is classified as a current liability) related to these matters.

       In addition, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation Company LLC 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. 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, the distribution of exposure sites and that the filing date of asbestos claims will not be after 2044. At December 31, 2009, Midwest Generation had recorded a liability of $50 million related to this contract indemnity.

       Effect if Different Assumptions Used.    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. In addition, for guarantees and indemnities actual results may differ from the amounts recorded and disclosed and could have a significant impact on EME's consolidated financial statements. For a discussion of contingencies, guarantees and indemnities, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies—Guarantees and Indemnities," "—Contingencies" and "Item 1. Business—Environmental Matters and Regulations."

Income Taxes

       Nature of Estimates Required.    As part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes for each jurisdiction in which it operates. This process involves estimating actual current period 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.

       EME takes certain tax positions it believes are applied in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the Internal Revenue Service, state tax authorities and the courts. EME determines its uncertain tax positions in accordance with the authoritative guidance.

       Key Assumptions and Approach Used.    Accounting for tax obligations requires management judgment. Management uses judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing its uncertain tax positions, EME considers, among others, the following factors: the facts and circumstances of the position, regulations, rulings, and case law, opinions or views of legal counsel and other advisers, and the experience gained from similar tax

103

positions. Management evaluates uncertain tax positions at the end of each reporting period and makes adjustments when warranted based on changes in fact or law.

       Effect if Different Assumptions Used.    Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenue and expenses recorded in the financial statements. EME continues to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. A tax liability has been recorded with respect to tax positions in which the outcome is uncertain and the effect is estimable. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 11. Income Taxes."

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

104

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm	107
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007	108
Consolidated Balance Sheets at December 31, 2009 and 2008	109
Consolidated Statements of Total Equity for the years ended December 31, 2009, 2008 and 2007	111
Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 and 2007	112
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	113
Notes to Consolidated Financial Statements	114

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

       None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

       EME's management, 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.

Management's Report on Internal Control over Financial Reporting

       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 controls over financial reporting were effective as of December 31, 2009.

Internal Control Over Financial Reporting

       There were no changes 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.

105

ITEM 9A(T). CONTROLS AND PROCEDURES

       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.

ITEM 9B. OTHER INFORMATION

       None.

106

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

To the Board of Directors and Shareholder of Edison Mission Energy:

In our opinion, the consolidated financial statements listed in the index appearing under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Edison Mission Energy and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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) of the Form 10-K 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 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 and 11 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests and the amount of consolidated net income attributable to the parent and to the noncontrolling interests effective January 1, 2009, fair value measurement and disclosure accounting principles as of January 1, 2008 and uncertain tax positions as of January 1, 2007.

/s/ PricewaterhouseCoopers LLP
Los Angeles, California
March 1, 2010

107

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(in millions)

			Years Ended December 31,
			2009			2008			2007
Operating Revenues			$	2,377		$	2,811		$	2,580
Operating Expenses
	Fuel			796			747			684
	Plant operations			579			621			584
	Plant operating leases			177			176			176
	Depreciation and amortization			236			194			162
	Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits, net (Notes 1, 5 and 13)			4			14			6
	Administrative and general			196			207			204
		Total operating expenses		1,988			1,959			1,816
	Operating income			389			852			764
Other Income (Expense)
	Equity in income from unconsolidated affiliates			100			122			200
	Dividend income			12			10			12
	Interest income			7			26			85
	Interest expense			(296	)		(279	)		(273	)
	Loss on early extinguishment of debt			—			—			(160	)
	Other income (expense), net			5			12			6
		Total other income (expense)		(172	)		(109	)		(130	)
	Income from continuing operations before income taxes			217			743			634
	Provision for income taxes			16			243			219
Income From Continuing Operations				201			500			415
Income (loss) from operations of discontinued subsidiaries, net of tax (Note 7)				(7	)		1			(2	)
Net Income				194			501			413
Net Loss Attributable to Noncontrolling Interests				3			—			1
Net Income Attributable to EME Common Shareholders			$	197		$	501		$	414
Amounts Attributable to EME Common Shareholders
Income from continuing operations, net of tax			$	204		$	500		$	416
Income (loss) from discontinued operations, net of tax				(7	)		1			(2	)
Net Income Attributable to EME Common Shareholders			$	197		$	501		$	414

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

108

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in millions)

			December 31,
			2009		2008
Assets
Current Assets
	Cash and cash equivalents		$	796	$	1,807
	Accounts receivable—trade			201		241
	Receivables from affiliates			93		18
	Inventory			196		189
	Derivative assets			197		170
	Restricted cash			69		—
	Margin and collateral deposits			120		88
	Prepaid expenses and other			190		148
		Total current assets		1,862		2,661
Investments in Unconsolidated Affiliates				361		362
Property, Plant and Equipment				6,279		5,643
	Less accumulated depreciation and amortization			1,474		1,241
		Net property, plant and equipment		4,805		4,402
Other Assets
	Deferred financing costs			43		36
	Long-term derivative assets			81		170
	Restricted deposits			40		43
	Rent payments in excess of levelized rent expense under plant operating leases			1,038		878
	Other long-term assets			403		528
		Total other assets		1,605		1,655
Total Assets			$	8,633	$	9,080

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

109

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in millions)

			December 31,
			2009		2008
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	97	$	95
	Payables to affiliates			14		18
	Accrued liabilities			247		380
	Derivative liabilities			5		22
	Interest payable			30		30
	Deferred taxes			119		66
	Current maturities of long-term obligations			37		24
		Total current liabilities		549		635
Long-term obligations net of current maturities				3,929		4,638
Deferred taxes and tax credits				672		541
Deferred revenues				153		63
Long-term derivative liabilities				15		5
Other long-term liabilities				478		434
Total Liabilities				5,796		6,316
Commitments and Contingencies (Notes 3, 10 and 13)
Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of December 31, 2009 and 2008			64		64
	Additional paid-in capital			1,339		1,335
	Retained earnings			1,280		1,085
	Accumulated other comprehensive income			78		200
		Total EME common shareholder's equity		2,761		2,684
Noncontrolling Interests				76		80
Total Equity				2,837		2,764
Total Liabilities and Equity			$	8,633	$	9,080

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

110

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF TOTAL EQUITY
(in millions)

					EME Shareholder's Equity
		Total Equity			Common Stock		Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests
Balance at December 31, 2006		$	2,629		$	64	$	2,174		$	243		$	101		$	47
	Net income (loss)		413								414						(1	)
	Impact of accounting for uncertainty in income taxes		(1	)							(1	)
	Other comprehensive loss		(164	)										(164	)
	Cash contribution from parent		36					36
	Cash dividends to parent		(925	)				(899	)		(26	)
	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
	Cash contributions from noncontrolling interests		1														1
	Cash distributions to noncontrolling interests and other		(5	)													(5	)
Balance at December 31, 2007			1,965			64		1,326			596			(63	)		42
	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		3					3
	Other stock transactions, net		6					6
	Sale of membership interest in noncontrolling interests		28														28
	Cash contributions from noncontrolling interests		12														12
	Cash distributions to noncontrolling interests		(2	)													(2	)
Balance at December 31, 2008			2,764			64		1,335			1,085			200			80
	Net income (loss)		194								197						(3	)
	Other comprehensive loss		(122	)										(122	)
	Payments to Edison International for stock purchases related to stock-based compensation		(2	)							(2	)
	Other stock transactions, net		4					4
	Cash contributions from noncontrolling interests		2														2
	Cash distributions to noncontrolling interests		(3	)													(3	)
Balance at December 31, 2009		$	2,837		$	64	$	1,339		$	1,280		$	78		$	76

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

111

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

			Years Ended December 31,
			2009			2008			2007
Net Income			$	194		$	501		$	413
Other comprehensive income (loss), net of tax
	Pension and postretirement benefits other than pensions:
		Prior service adjustment, net of tax		1			3			(1	)
		Net gain (loss) adjustment, net of tax expense (benefit) of $6, $(26) and $4 for 2009, 2008 and 2007, respectively		10			(41	)		7
		Amortization of net loss and prior service adjustment included in expense, net of tax		2			1			1
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $36, $138 and $(160) for 2009, 2008 and 2007, respectively		43			211			(235	)
		Reclassification adjustments included in net income, net of income tax expense (benefit) of $124, $(58) and $(45) for 2009, 2008 and 2007, respectively		(178	)		89			64
Other comprehensive income (loss)				(122	)		263			(164	)
Comprehensive Income				72			764			249
Comprehensive Loss Attributable to Noncontrolling Interests				3			—			1
Comprehensive Income Attributable to EME Common Shareholders			$	75		$	764		$	250

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

112

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

			Years Ended December 31,
			2009			2008			2007
Cash Flows From Operating Activities
	Net income		$	194		$	501		$	413
	(Income) loss from discontinued operations			7			(1	)		2
	Income from continuing operations, net			201			500			415
	Adjustments to reconcile income to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(100	)		(121	)		(199	)
		Distributions from unconsolidated affiliates		76			108			137
		Depreciation and amortization		246			202			172
		Deferred taxes and tax credits		275			104			41
		Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits		4			14			1
		Loss on early extinguishment of debt		—			—			160
	Changes in operating assets and liabilities:
		(Increase) decrease in margin and collateral deposits		(32	)		(3	)		69
		Increase in accounts receivables		(35	)		(1	)		(29	)
		(Increase) decrease in inventory		(8	)		(40	)		9
		Decrease (increase) in prepaid expenses and other		53			(9	)		6
		Increase in restricted cash		(69	)		—			—
		Increase in rent payments in excess of levelized rent expense		(160	)		(162	)		(160	)
		(Decrease) increase in accounts payable and other current liabilities		(109	)		(7	)		6
		Increase in interest payable		—			—			2
		(Increase) decrease in derivative assets and liabilities		(168	)		215			(106	)
		Other operating—assets		16			(53	)		(18	)
		Other operating—liabilities		68			(19	)		13
	Operating cash flow from continuing operations			258			728			519
	Operating cash flow from discontinued operations			(7	)		1			(2	)
		Net cash provided by operating activities		251			729			517
Cash Flows From Financing Activities
	Borrowings on long-term debt			189			1,130			2,930
	Payments on long-term debt agreements			(886	)		(292	)		(2,276	)
	Cash contributions from noncontrolling interests			2			12			—
	Cash dividends to noncontrolling interests			(3	)		—			—
	Cash contribution from parent			—			—			36
	Cash dividends to parent			—			—			(925	)
	Payments to affiliates related to stock-based awards			(2	)		(8	)		(34	)
	Excess tax benefits related to stock-based awards			—			3			14
	Premium paid on extinguishment of debt and financing costs			(14	)		(1	)		(162	)
		Net cash provided by (used in) financing activities		(714	)		844			(417	)
Cash Flows From Investing Activities
	Capital expenditures			(283	)		(552	)		(540	)
	Proceeds from return of capital and loan repayments and sale of assets			30			39			32
	Proceeds from sale of membership interest			—			28			—
	Purchase of interest of acquired companies			(22	)		(19	)		(33	)
	Purchase of short-term investments			—			(19	)		(20	)
	Maturities of short-term investments			3			96			497
	Decrease in restricted deposits			3			4			43
	Investments in other assets			(279	)		(337	)		(298	)
		Net cash used in investing activities		(548	)		(760	)		(319	)
Net increase (decrease) in cash and cash equivalents				(1,011	)		813			(219	)
Cash and cash equivalents at beginning of period				1,807			994			1,213
Cash and cash equivalents at end of period			$	796		$	1,807		$	994

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

113

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

       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. EME is a holding company whose subsidiaries and affiliates are 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 competitive power markets.

Basis of Presentation

       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. For a discussion of EME's variable interest entities, see Note 5—Acquisitions and 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 December 31, 2009 consolidated financial statement presentation mostly pertaining to noncontrolling interests, which were immaterial. 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.

       EME has performed an evaluation of subsequent events through the date the financial statements were issued.

114

Cash and Cash Equivalents

       Cash and cash equivalents as of December 31, 2009 and 2008 consisted of the following:

(in millions)		December 31, 2009		December 31, 2008
Cash		$	106	$	31
Money market funds		$	690	$	1,581
U.S. government agency securities			—		165
Commercial paper			—		30
	Total cash equivalents	$	690	$	1,776
Total cash and cash equivalents		$	796	$	1,807

       Cash equivalents, with the exception of money market funds, were stated at amortized cost plus accrued interest. The carrying value of cash equivalents equals the fair value as all investments have 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 and deposits, see "—Restricted Cash and Deposits."

       At December 31, 2009 and 2008, EME had classified all marketable debt securities as held-to-maturity. The securities were carried at amortized cost plus accrued interest, which was equal to its fair value. Held-to-maturity securities all mature within one year.

Derivative Instruments

       Authoritative guidance on derivatives and hedging establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). EME is required to record derivatives on its balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as a normal sale and purchase. All changes in the fair value of derivative instruments are recognized currently in earnings, unless specific hedge criteria are met, which requires that EME formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

       The accounting guidance for cash flow hedges provides that the effective portion of gains or losses on derivative instruments designated and qualifying as cash flow hedges 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 gains or losses on the derivative instruments, if any, must be recognized currently in earnings. Derivative and hedging accounting policies are discussed further in Note 3—Derivative Instruments and Risk Management.

Deferred Financing Costs

       Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense using a method that approximates the effective interest rate method over the term of the related debt. Accumulated amortization of these

115

costs at December 31, 2009 and 2008 amounted to $22 million and $20 million, respectively. Amortization of deferred financing costs charged to interest expense was $3 million, $1 million and $3 million in 2009, 2008 and 2007, respectively.

Impairment of Investments and Long-Lived Assets

       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. If the carrying amount of a long-lived asset exceeds the amount of the expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized.

Income Taxes

       EME is included in the consolidated federal and state income tax returns of Edison International and participates in tax-allocation and payment agreements with other subsidiaries of Edison International. EME calculates its tax provision in accordance with these tax agreements. EME's current tax liability or benefit is determined on a "with and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding EME's taxable income or loss and state apportionment factors. This method is similar to a separate company return, except that EME recognizes, without regard to separate company limitations, additional tax liabilities or benefits based on the impact to the combined group including EME's taxable income or losses and state apportionment factors. At December 31, 2009 and 2008, amounts included in receivables from affiliates associated with the tax-allocation agreements totaled $80 million and $4 million, respectively.

       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 11—Income Taxes.

Intangible Assets

       Acquired intangible assets with indefinite lives are not amortized; rather they are tested at least annually for impairment or when events or changes in circumstances indicate that the asset might be impaired. Intangible assets are periodically reviewed when impairment

116

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 $51 million and $88 million at December 31, 2009 and 2008, respectively.

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

	December 31,
(in millions)	2009		2008
Project development rights	$	10	$	10
Option rights		17		22
Purchased emission allowances1		21		41
Total unamortized intangible assets	$	48	$	73

¹

Emission allowances do not have a pre-determined contractual term or expiration date. Emission allowances are stated at weighted average cost.

       In 2009 and 2008, project development rights relate to the consolidation of a development stage enterprise. For further discussion, see Note 5—Acquisitions and Variable Interest Entities. In 2007, EME 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 during 2007 to acquire an option to purchase specific projects. In 2009, EME recorded a write-down of $3 million reflected in "Gain on buyout of contract, loss on termination of contract, asset write-down and other charges and credits, net" in connection with options unused in 2009 under the joint development agreement. The remaining projects are in development with target completion dates of 2011 and beyond. EME is required to fund ongoing development expenses for each project.

       Emission allowances at EME's fossil-fueled facilities decreased in 2009 due to a decline in market prices of purchased emission allowances in 2009, compared to 2008, and usage of existing emission allowances. In 2008, EME also purchased emission allowances related to thermal projects under development.

117

Inventory

       Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2009 and December 31, 2008 consisted of the following:

	December 31,
(in millions)	2009		2008
Coal, fuel oil and other raw materials	$	132	$	131
Spare parts, materials and supplies		64		58
Total	$	196	$	189

New Accounting Guidance

Accounting Guidance Adopted in 2009

General Principles

       The FASB issued an accounting standard establishing the FASB Accounting Standards Codification (Codification) as the source of authoritative, nongovernmental U.S. GAAP superseding existing FASB, American Institute of Certified Public Accountants (AICPA), Emerging Issues Task Force (EITF) and related literature. Following this action, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, the FASB will issue Accounting Standards Updates. Two levels of U.S. GAAP will exist: authoritative and non-authoritative. The Codification is not intended to change U.S. GAAP or guidance issued by the U.S. Securities and Exchange Commission. EME adopted the Codification effective July 1, 2009.

Subsequent Events

       The FASB issued authoritative guidance that sets forth the period subsequent to the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize these events or transactions; and the disclosures that an entity should make. EME adopted this guidance effective April 1, 2009. EME also adopted revised disclosure requirements prescribed by an accounting standards update issued in February 2010. The adoption had no impact on EME's consolidated results of operations, financial position or cash flows.

Fair Value Measurements and Disclosures

       The FASB issued an accounting standards update that provides additional guidance on how companies should measure liabilities at fair value. While reaffirming the existing definition of fair value, the update reintroduced the concept of entry value into the determination of fair value. Entry value is the amount an entity would receive to enter into an identical liability. Under the new guidance, the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer. If the quoted price of a liability when traded as an asset includes the effect of a credit enhancement (i.e., a

118

guarantee), this effect should be excluded from the measurement of the liability. EME adopted this guidance effective October 1, 2009. The adoption had no impact on EME's consolidated results of operations, financial position or cash flows.

       The FASB issued authoritative guidance affirming the objective of a fair value measurement, which is to identify the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction at the measurement date between market participants ("exit price") under current market conditions. This includes guidance on identifying circumstances that indicate when there is no active market or transactions where the price inputs being used represent distressed or forced sales. If either of these conditions exists, this guidance provides additional direction for estimating fair value and requires disclosure of a change in valuation technique (and the related inputs) resulting from the application of this position and to quantify its effects, if practicable. This guidance also requires disclosures on a more disaggregated basis for investments in debt and equity securities measured at fair value. EME adopted this guidance effective April 1, 2009. The adoption had no impact on EME's consolidated results of operations, financial position or cash flows.

       The FASB issued authoritative guidance requiring disclosures about the fair value of all financial instruments, for which it is practicable to estimate that fair value, for interim reporting periods as well as annual statements. EME adopted this guidance effective April 1, 2009. Since this guidance impacted disclosures only, the adoption did not have an impact on EME's consolidated results of operations, financial position or cash flows.

       Effective January 1, 2009, EME adopted authoritative guidance on nonrecurring fair value measurements of nonfinancial assets and liabilities. The adoption did not have a material impact on EME's consolidated results of operations, financial position or cash flows.

Investments—Equity Method and Joint Ventures

       The FASB clarified the accounting for certain transactions and impairment considerations involving equity method investments. Effective January 1, 2009, EME adopted this guidance prospectively. The adoption had no impact on EME's consolidated financial statements.

Business Combinations

       The FASB issued authoritative guidance establishing 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 interests in the acquiree at the acquisition date fair value. This guidance determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This guidance applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. The initial adoption had no impact on EME's consolidated results of operations, financial position or cash flows.

119

Compensation—Retirement Benefits

       The FASB issued authoritative guidance requiring additional postretirement benefit plan asset disclosures by employers 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. EME adopted this guidance effective December 31, 2009. Since this guidance impacted disclosures only, the adoption did not have an impact on EME's consolidated results of operations, financial position or cash flows.

Consolidation

       The FASB issued authoritative guidance requiring an entity to present noncontrolling interests that reflect 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 interests to be clearly identified and presented on the face of the consolidated balance sheets and statements of income; changes in ownership interests to 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 to be measured at fair value. EME adopted this guidance effective January 1, 2009. In accordance with this guidance, EME reclassified noncontrolling interests of $80 million at December 31, 2008 to a component of equity on EME's consolidated balance sheet.

Derivatives and Hedging

       The FASB issued authoritative guidance requiring 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. EME adopted this guidance effective January 1, 2009. Since this guidance impacted disclosures only, the adoption did not have an impact on EME's consolidated results of operations, financial position or cash flows.

Intangibles—Goodwill and Other

       The FASB issued authoritative guidance amending the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of the guidance is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset under business combinations and other GAAP. EME adopted this guidance effective January 1, 2009. The adoption had no impact on EME's consolidated results of operations, financial position or cash flows.

120

Accounting Guidance Not Yet Adopted

Consolidation—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

       In December 2009, the FASB issued an accounting standards update that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity had the obligation to absorb losses. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. EME will adopt this guidance effective January 1, 2010. EME estimates the impact of adopting this guidance to result in the deconsolidation of certain wind assets totaling $253 million and the consolidation of coal assets totaling $99 million at January 1, 2010. Deconsolidation will not result in a gain or loss.

Fair Value Measurements and Disclosures

       In January 2010, the FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. New requirements include the separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. In addition, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The update clarified existing disclosure requirements for the level of disaggregation and inputs and valuations techniques. This guidance is effective January 1, 2010, except for the requirement to provide gross Level 3 activity, which will be effective January 1, 2011. Since the guidance impacts disclosures only, the adoption will have no impact on EME's consolidated results of operations, financial position or cash flows.

Planned Major Maintenance

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

Project Development Costs

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

121

Property, Plant and Equipment

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

       As part of the acquisition of the fossil-fueled 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.

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

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

       The remaining estimated useful life or lease term at December 31, 2009 for the Midwest Generation plants with respect to its coal-fired plants is as follows:

Crawford Station	15 years
Fisk Station	15 years
Joliet Unit 6	20 years
Joliet Units 7 and 81	21 years
Powerton Station1	24 years
Waukegan Station	15 years
Will County Station	20 years

¹

Represents leased facilities. The leases may be renewed based on criteria outlined in their respective agreements.

       Power plant facilities are assigned estimated useful lives based on the anticipated life of the facility. The estimated life of an individual facility could be impacted by decisions related to the installation of environmental remediation equipment. If environmental compliance equipment is not installed, the useful life of the facility may be shortened.

       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.

122

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

	Years Ended December 31,
(in millions)	2009			2008			2007
Interest incurred	$	315		$	311		$	297
Interest capitalized		(19	)		(32	)		(24	)
	$	296		$	279		$	273

Rent Expense

       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. For additional information on these sale-leaseback transactions, see Note 13—Commitments and Contingencies—Lease Commitments.

Restricted Cash and Deposits

       Cash balances that are restricted under margining agreements are classified as restricted cash included in current assets, as such amounts change frequently based on forward market prices. Restricted deposits consisted of cash balances that are restricted to pay amounts required for lease payments, debt service or to provide collateral. Included in restricted deposits was $20 million and $30 million at December 31, 2009 and 2008, respectively, related to lease payments and $20 million and $13 million at December 31, 2009 and 2008, respectively, related to debt service or collateral reserves.

Revenue Recognition

       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. EME's subsidiaries record settlement of non-trading physical forward contracts on a gross basis. 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. Risks managed 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 the transaction is accounted for as a derivative and does not qualify for the normal sales and purchases exception.

123

       Revenues under certain 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.

       EME accounts for grant income on the deferred method and, accordingly, will recognize operating revenues related to such income over the estimated useful life of the projects. At December 31, 2009, EME had $92 million in U.S. Treasury grants receivable with respect to Phase II of the Goat Wind and High Lonesome wind projects included in prepaid expenses and other on its consolidated balance sheet.

Stock-Based Compensation

       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.

       EME adopted fair value accounting for stock-based compensation on a prospective basis in 2006. Fair value accounting is applied to any vested award outstanding as of January 1, 2006 and to all awards granted thereafter. Fair value accounting for stock-based compensation results 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.

Note 2. Fair Value Measurements

       Fair value is defined 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"). Fair value for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize inputs to

124

valuation models. 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 are:

•

Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;

•

Level 2—Pricing inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument; and

•

Level 3—Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.

       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 peak and AEP/Dayton) adjusted for nonperformance 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.

       Financial transmission rights and over-the-counter derivatives that trade infrequently at illiquid locations, 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

125

value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

       Derivatives with counterparties that have significant nonperformance risks are classified as Level 3. In assessing nonperformance 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 nonperformance. The fair value of derivative assets nonperformance risk was $2 million and $6 million at December 31, 2009 and 2008, respectively.

       Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices (unadjusted) in active markets.

       The following table sets forth EME's assets and liabilities that were accounted for at fair value by level within the fair value hierarchy as of December 31, 2009 and 2008:

		As of December 31, 2009
(in millions)		Level 1			Level 2			Level 3			Netting and Collateral2			Total
Assets at Fair Value
	Money market funds1	$	758		$	—		$	—		$	—		$	758
	Derivative contracts		17			235			179			(153	)		278
Liabilities at Fair Value
	Derivative contracts	$	(3	)	$	(88	)	$	(6	)	$	77		$	(20	)

		As of December 31, 2008
(in millions)		Level 1		Level 2			Level 3			Netting and Collateral2			Total
Assets at Fair Value
	Money market funds1	$	1,581	$	—		$	3		$	—		$	1,584
	Derivative contracts		2		417			221			(300	)		340
Liabilities at Fair Value
	Derivative contracts	$	—	$	(145	)	$	(8	)	$	126		$	(27	)

¹

Included in cash and cash equivalents, restricted cash and prepaid expenses and other on EME's consolidated balance sheet.

²

Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

126

       The following table sets forth a summary of changes in the fair value of assets and liabilities, net categorized as Level 3 for the periods ended December 31, 2009 and 2008:

(in millions)		2009			2008
Fair value at beginning of periods		$	216		$	120
Total realized/unrealized gains (losses):
	Included in earnings1		7			297
	Included in accumulated other comprehensive income (loss)		3			(2	)
Purchases and settlements, net			(43	)		(219	)
Transfers in or out of Level 3			(10	)		20
Fair value at December 31		$	173		$	216
Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at December 311		$	64		$	125

¹

Reported in operating revenues on EME's consolidated statements of income.

Long-term Obligations

       The carrying amounts and fair values of EME's long-term obligations as of December 31, 2009 and 2008 were as follows:

	December 31, 2009				December 31, 2008
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term obligations, including current portion	$	3,966	$	3,150	$	4,662	$	4,006

       In assessing the fair value of EME's long-term obligations, EME primarily uses quoted market prices, except for floating-rate debt for which the carrying amounts were considered a reasonable estimate of fair value.

Note 3. Derivative Instruments and Risk Management

       EME uses derivative instruments to reduce EME's exposure to market risks that arise from fluctuations in prices of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. To the extent that EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily entered into using derivative instruments including:

•

futures contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange or executed bilaterally with counterparties,

•

forward sales transactions entered into on a bilateral basis with third parties, including electric utilities, power marketing companies and financial institutions,

•

full requirements services contracts or load requirements services contracts for the procurement of power for electric utilities' customers, with such services providing for

127

the delivery of a bundled product including, but not limited to, energy, transmission, capacity, and ancillary services, generally for a fixed unit price,

•

capacity transactions, and

•

interest rate swaps entered into on a bilateral basis with counterparties.

       The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine if forward market prices are sufficiently attractive compared to the risks associated with the fluctuating spot market. Second, EME evaluates the sufficiency of its credit capacity at EME and Midwest Generation and whether the forward sales markets have sufficient liquidity to enable EME to identify appropriate counterparties for hedge transactions.

       Many of the derivative instruments entered into for risk management purposes (also referred to as non-trading purposes) meet the requirements for hedge accounting. However, not all derivative instruments entered into for risk management purposes will qualify for hedge accounting treatment. Furthermore, EME utilizes derivative contracts to adjust financial and/or physical positions that reduce costs or increase gross margin. Accordingly, risk management positions may not be designated as cash flow hedges and are thus marked to market through current period earnings (derivatives that are entered into for risk management, but which are not designated as cash flow hedges, are referred to as economic hedges).

       Authoritative guidance on derivatives and hedging affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies from accrual accounting (i.e., revenue recognition based on the settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from commodity contracts in operating revenues or fuel expenses based on the item being hedged. In addition, the results of derivative activities are recorded in cash flows from operating activities in the consolidated statements of cash flows.

       Derivative 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, derivative instruments are valued at fair value as determined through the methodology outlined in Note 2—Fair Value Measurements. Resulting gains and losses are recognized in operating revenues in the accompanying consolidated statements of income in the period of change.

       Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis on its consolidated balance sheet.

128

Notional Volumes of Derivative Instruments

       The following table summarizes the notional volumes of derivatives used for hedging and trading activities at December 31, 2009:

				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities
Electricity	Forwards/Futures	Sales	GWh		24,355	1		26,838	3		23,306
Electricity	Forwards/Futures	Purchases	GWh		106	1		25,971	3		23,404
Electricity	Capacity	Sales	MW-Day (in thousands)		254	2		1	2		597	2
Electricity	Capacity	Purchases	MW-Day (in thousands)		11	2		2	2		736	2
Electricity	Congestion	Sales	GWh		—			136	4		10,212	4
Electricity	Congestion	Purchases	GWh		—			1,576	4		181,930	4
Natural gas	Forwards/Futures	Sales	billion cubic feet		—			3.3			30.8
Natural gas	Forwards/Futures	Purchases	billion cubic feet		—			—			30.6
Fuel oil	Forwards/Futures	Sales	Barrels		—			250,000			120,000
Fuel oil	Forwards/Futures	Purchases	Barrels		—			625,000			120,000

¹

EME's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the Midwest Generation plants which meet the normal sales and purchase exception and are accounted for on the accrual method.

²

EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM RPM auction is not accounted for as a derivative.

³

EME also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.

⁴

Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

       Included in trading activities in the preceding table, EME shows net the volume of energy trading activities that are physically settled. Gross purchases and sales totaled 3,791 GWh, 4,080 GWh and 4,130 GWh during 2009, 2008 and 2007, respectively.

Interest Rate Swaps

       Viento Funding II, Inc., an EME subsidiary, in conjunction with its wind financing, entered into seven-year amortizing interest rate swaps accounted for as cash flow hedges with a total notional amount of approximately $160 million at December 31, 2009. The interest rate swaps entitle Viento Funding II to receive a floating (six-month LIBOR) rate and pay a fixed rate of 3.175%. The interest rate swap agreements expire in June 2016.

129

Fair Value of Derivative Instruments

       The following table summarizes the gross fair value of derivative instruments at December 31, 2009:

		Derivative Assets									Derivative Liabilities
																				Net Assets
(in millions)		Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal
Non-trading activities
	Cash flow hedges	$	240		$	17		$	257		$	69		$	6		$	75		$	182
	Economic hedges		202			8			210			180			—			180			30
Trading activities			234			111			345			182			41			223			122
		$	676		$	136		$	812		$	431		$	47		$	478		$	334
Netting and collateral received			(479	)		(55	)		(534	)		(426	)		(32	)		(458	)		(76	)
Total		$	197		$	81		$	278		$	5		$	15		$	20		$	258

Income Statement Impact of Derivative Instruments

       The following table provides the activity of accumulated other comprehensive income for the year ended December 31, 2009, containing the information about the changes in the fair value of cash flow hedges and reclassification from accumulated other comprehensive income into results of operations:

(in millions)	Cash Flow Hedge Activity1			Income Statement Location
Accumulated other comprehensive income derivative gain at December 31, 2008	$	398
Effective portion of changes in fair value		79
Reclassification from accumulated other comprehensive income to net income		(302	)	Operating revenues
Accumulated other comprehensive income derivative gain at December 31, 2009	$	175

¹

Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at December 31, 2009 and December 31, 2008 were $105 million and $240 million, respectively.

       The portion of a cash flow hedge that does not offset the change in the 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 $24 million, $7 million and $(41) million in 2009, 2008 and 2007, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues on the consolidated statements of income.

130

       The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of income for the year ended December 31, 2009 is presented below:

(in millions)	Income Statement Location	December 31, 2009
Economic hedges	Operating revenue	$	34
	Fuel expense		18
Trading activities	Operating revenue		47

Contingent Features/Credit Related Exposure

       Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related 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 may 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 margin, but provide that each party can 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 all derivative instruments with credit-risk-related contingent features is in an asset position on December 31, 2009 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 additional collateral postings under the contingent features described above.

Margin and Collateral Deposits

       Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. EME presents a portion of its margin and cash collateral deposits net with its derivative positions on EME's consolidated balance sheets. Cash collateral provided to others offset against derivative liabilities totaled $49 million and $51 million at December 31, 2009 and 2008, respectively. Cash collateral received from others offset against derivative assets totaled $124 million and $225 million at December 31, 2009 and 2008, respectively.

131

Commodity Price Risk Management

       EME's merchant operations create exposure to commodity price risk, which reflects the potential impact of a change in the market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided 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 estimates of the variability in gross margin to help identify, measure, monitor and control its overall market risk exposure and earnings volatility with respect to hedge positions at the fossil-fueled facilities and the merchant wind projects, and uses "value at risk" metrics to help identify, measure, monitor and control its overall risk exposure in respect to its trading positions. These measures allow management to aggregate overall commodity risk, compare risk on a consistent basis and identify changes in risk factors. Value at risk measures the possible loss, and variability in gross margin 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 volumetric 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 Risk Management

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

Credit Risk

       In conducting EME's hedging and trading activities, EME enters into transactions with 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 market price changes occurring since the original contract was executed if the nonperforming 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 evaluates the risk of potential defaults by counterparties. Credit risk is measured as 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

132

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.

       The majority of EME's consolidated wind projects and unconsolidated affiliates that own power plants sell power under power purchase agreements. Generally, each project or plant sells its output to one counterparty. A default by the counterparty, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of the project or plant.

       Coal for the fossil-fueled facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the fossil-fueled 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.

       The fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 48%, 50% and 51% of EME's consolidated operating revenues for the years ended December 31, 2009, 2008 and 2007, 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. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At December 31, 2009 and 2008, EME's account receivable due from PJM was $50 million and $61 million, respectively.

       For the years ended December 31, 2009 and 2008, a second customer, Constellation Energy Commodities Group, Inc. accounted for 16% and 10%, respectively, of EME's consolidated operating revenues. Sales to Constellation are primarily generated from the fossil-fueled facilities and 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, 2009 and 2008, EME's account receivable due from Constellation was $36 million and $22 million, respectively.

       For the years ended December 31, 2008 and 2007, EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Midwest Generation plants to Commonwealth Edison under load requirements services contracts. By May 2009, all these contracts had expired. 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.

133

       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 EME's turbine suppliers may have a material impact on EME's wind projects and development efforts.

Note 4. Accumulated Other Comprehensive Income

       Accumulated other comprehensive income consisted of the following:

(in millions)		Unrealized Gains (Losses) on Cash Flow Hedges			Unrecognized Gains (Losses) and Prior Service Adjustments, Net1			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2007		$	(60	)	$	(3	)	$	(63	)
	Change for 2008		300			(37	)		263
Balance at December 31, 2008			240			(40	)		200
	Change for 2009		(135	)		13			(122	)
Balance at December 31, 2009		$	105		$	(27	)	$	78

¹

For further detail, see Note 12—Compensation and Benefit Plans.

       The amount of commodity hedges included in unrealized gains on cash flow hedges, net of tax, at December 31, 2009 was a gain of $106 million. The amount of interest rate hedges included in unrealized gains on cash flow hedges, net of tax, at December 31, 2009 was a loss of $1 million.

       Unrealized gains on commodity hedges consist primarily of Midwest Generation and 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, $99 million, after tax, of the net unrealized gains on cash flow hedges at December 31, 2009 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.

       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 were guaranteed by Lehman Brothers Holdings. These contracts qualified as cash flow hedges 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

134

recorded in accumulated comprehensive income related to 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 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. In 2009, $14 million of the pre-tax amount recorded in accumulated other comprehensive income was reclassified to operating revenues. The remaining amount will be reclassified in 2010, 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.

Note 5. Acquisitions and Variable Interest Entities

Acquisition of Cedro Hill Wind Project

       In October 2009, EME completed a transaction with Cedro Hill Wind, LLC to acquire 100% of the membership interests and ownership rights in the Cedro Hill wind project, a 150 MW wind development project in Texas which has a 20-year power purchase agreement with the City of San Antonio. To construct this project, EME plans to install 100 turbines (150 MW) to be purchased under its turbine supply agreement with General Electric Company. This project started construction in October 2009 and is scheduled for completion during the fourth quarter of 2010. The fair value of the Cedro Hill wind project was allocated to property, plant and equipment on EME's consolidated balance sheet. The impact of the Cedro Hill wind project acquisition on EME's consolidated financial statements was not material. EME plans to obtain project financing for this project prior to completion of construction.

Variable Interest Entities

       As of December 31, 2009, the FASB authoritative guidance 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. This guidance identifies the primary beneficiary as 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.

Description of Use of Variable Interest Entities

       EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own all or some of the interests in one or more

135

power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project.

       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 Midwest Generation 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.

       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.

       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.

Projects or Entities that are Consolidated

       EME has purchased a majority interest in a number of wind projects under joint development agreements with third-party developers. At December 31, 2009 and 2008, EME had majority interests in 15 wind projects with a total generating capacity of 700 MW and 630 MW, respectively, that have 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 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

136

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 are operating leases and do not absorb expected losses. Based on the allocation of income and losses, EME expects to earn a majority of the expected gains or absorb the majority of the expected losses from these entities and, therefore, determined that it is the primary beneficiary.

       The following table presents summarized financial information of the wind projects that had minority interests held by others consolidated by EME at December 31, 2009 and 2008:

		December 31,
(in millions)		2009		2008
Current assets		$	73	$	31
Net property, plant and equipment			944		957
Other long-term assets			2		2
	Total assets	$	1,019	$	990
Current liabilities		$	17	$	29
Long-term obligations net of current maturities			20		25
Deferred revenues			58		15
Other long-term liabilities			21		18
	Total liabilities	$	116	$	87
Noncontrolling interests		$	76	$	77

       Assets serving as collateral for the debt obligations had a carrying value of $81 million and $85 million at December 31, 2009 and 2008, respectively, and primarily consist of property, plant and equipment. The consolidated statements of income and cash flow for the years ended December 31, 2009 and 2008 includes $12 million and $4 million of pre-tax loss, respectively, and $37 million and $30 million of operating cash flow, respectively, related to variable interest entities that are consolidated.

Consolidation of Wind Development Company

       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 authoritative guidance on consolidation, 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, 2009 and 2008, the assets consolidated included $3 million each of intangible assets, 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

137

contract, loss on termination of contract, asset write-down and other charges and credits" on EME's consolidated statements of income.

Projects that are not Consolidated

       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.

       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 long-term debt that is 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 not require EME to contribute additional capital. At December 31, 2009, entities which EME has accounted for under the equity method had indebtedness of $245 million, of which $104 million is proportionate to EME's ownership interest in these projects. 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, 2009 and 2008, EME had 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, consequently, EME was not the primary beneficiary of these entities. Accordingly, EME continues to account for its variable interests under the equity method. EME's maximum exposure to loss in these variable interest entities is limited to its investment in these entities, which totaled $333 million and $326 million as of December 31, 2009 and 2008, respectively, and is classified as investments in unconsolidated affiliates on EME's consolidated balance sheets.

       As of December 31, 2009 and 2008, EME had 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 guarantee as of December 31, 2009 and 2008, if payment were required, would be $36 million and $56 million, respectively. EME has not recorded a liability related to the guarantee. EME's maximum exposure to loss

138

at December 31, 2009 and 2008 was $37 million and $56 million, respectively. During the first quarter of 2009, EME commenced recording its share of equity in income from the March Point project. EME recorded $11 million for the year ended December 31, 2009. To the extent that cash is received from the project in excess of EME's investment, such amount will be included in equity in income from unconsolidated affiliates on EME's consolidated statements of income. In February 2010, EME received an $18 million equity distribution from the March Point project. EME subsequently sold its ownership interest in the March Point project to its partner. The purchaser of EME's interest in March Point has agreed to indemnify EME for claims under the guarantee arising after the sale.

       As of December 31, 2009 and 2008, EME had 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. For additional information on the Doga project, see Note 8—Investments in Unconsolidated Affiliates.

Note 6. Restructuring Costs

       EME reduced approximately 75 positions in its regional and corporate offices in April 2009 and recorded charges of approximately $5 million (pre-tax) during the second quarter of 2009 included in administrative and general expense on EME's consolidated statements of income.

Note 7. Divestitures

Discontinued Operations

       Summarized financial information for discontinued operations is as follows:

	Years Ended December 31,
(in millions)	2009			2008		2007
Income (loss) before income taxes	$	(9	)	$	6	$	3
Provision (benefit) for income taxes		(2	)		5		5
Income (loss) from operations of discontinued foreign subsidiaries	$	(7	)	$	1	$	(2	)

       During the second quarter of 2009, EME increased its estimated liability for a tax indemnity related to EME's previous sale of an international project by $6 million and recognized foreign exchange losses and interest related to such tax indemnity.

Note 8. Investments in Unconsolidated Affiliates

       Investments in unconsolidated affiliates, generally 50% or less owned partnerships and corporations, are accounted for by the equity method. These investments are primarily in energy projects. 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, 2009. The

139

differences are being amortized over the life of the energy projects. The following table presents summarized financial information of the investments in unconsolidated affiliates:

(in millions)		2009		2008
Investments in Unconsolidated Affiliates
	Equity investment	$	351	$	351
	Cost investment		10		11
Total		$	361	$	362

       At December 31, 2009 and 2008, 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, 2009 and 2008 was not impaired. The undistributed earnings of equity method investments were $30 million in 2009 and $37 million in 2008.

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

	Years Ended December 31,
(in millions)	2009		2008		2007
Revenues	$	936	$	1,434	$	1,464
Expenses		734		1,193		1,070
Net income	$	202	$	241	$	394

		December 31,
(in millions)		2009		2008
Current assets		$	387	$	338
Noncurrent assets			715		758
	Total assets	$	1,102	$	1,096
Current liabilities		$	198	$	193
Noncurrent liabilities			198		249
Equity			706		654
	Total liabilities and equity	$	1,102	$	1,096

       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 only included in the balances for 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.

140

       The following table presents, as of December 31, 2009, the investments in unconsolidated affiliates accounted for by the equity method that represent at least five percent (5%) of EME's income before tax or in which EME has an investment balance greater than $50 million:

Unconsolidated Affiliates	Location	Investment at December 31, 2009 (in millions)		Ownership Interest at December 31, 2009			Operating Status
Sunrise	Fellows, CA	$	160		50	%	Operating gas-fired facility
Sycamore	Bakersfield, CA		43		50	%	Operating cogeneration facility
Watson	Carson, CA		60		49	%	Operating cogeneration facility

Note 9. Property, Plant and Equipment

       Property, plant and equipment consist of the following:

	December 31,
(in millions)	2009		2008
Power plant facilities	$	4,133	$	3,590
Leasehold improvements		156		132
Emission allowances		1,305		1,305
Construction in progress1		616		541
Equipment, furniture and fixtures		69		75
		6,279		5,643
Less accumulated depreciation and amortization		1,474		1,241
Net property, plant and equipment	$	4,805	$	4,402

¹

Construction in progress consisted of $451 million and $276 million at December 31, 2009 and 2008, respectively, related to wind projects including those under construction.

       The power sales agreements of certain wind projects qualify as operating leases pursuant to authoritative guidance on leases. The carrying amount and related accumulated depreciation of the property of these wind projects totaled $1.3 billion and $123 million, respectively, at December 31, 2009. 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 $83 million, $46 million and $24 million in 2009, 2008 and 2007.

       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 total amount of assets pledged or mortgaged was approximately $2.8 billion at December 31, 2009. 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.

141

Asset Retirement Obligations

       Authoritative guidance on AROs 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.

       Midwest Generation 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:

(in millions)	2009		2008			2007
Beginning balance	$	34	$	16		$	11
Obligation incurred		6		21			7
Liabilities settled during the period		—		—			(3	)
Accretion expense		3		1			1
Change in estimates		—		(4	)		—
Ending balance	$	43	$	34		$	16

142

Note 10. Financial Instruments

Long-Term Obligations

       Long-term obligations include both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay such obligations. At December 31, 2009, recourse debt to EME totaled $3.7 billion and non-recourse project debt totaled $266 million. Long-term obligations consist of the following:

			December 31,
(in millions)			2009		2008
Recourse
EME (parent only)
	Senior Notes, net
		due 2009 (7.73%)	$	—	$	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
EME CP Holdings Co. Note Purchase Agreement due 2015 (7.31%)				61		67
Midwest Generation $500 million Credit Facility (weighted average rate of 2.34% at 12/31/08)				—		475
Viento Funding II, Inc. Term Loan due 2016 (LIBOR plus 3.875%) (4.315% at 12/31/09)				178		—
Other				27		31
Subtotal			$	3,966	$	4,662
Less current maturities of long-term obligations				37		24
Total			$	3,929	$	4,638

Senior Notes

       EME has $3.7 billion of senior notes due 2013 through 2027. 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

143

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.

       EME recorded a total pre-tax loss of $160 million ($98 million after tax) on early extinguishment of debt 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.

Credit Agreements

       During 2007, EME amended its existing $500 million secured credit facility maturing in June 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, 2009, EME had no borrowings outstanding and $101 million of letters of credit outstanding under this credit facility. The credit facility contains financial covenants which require EME to maintain an interest coverage ratio not less than 1.20 and a corporate debt to corporate capital ratio not more than 0.75. A failure to meet a ratio threshold could trigger other provisions, such as mandatory prepayment provisions or restrictions on dividends. At December 31, 2009, the interest coverage ratio was 1.72 for the year ended December 31, 2009 and the corporate debt to corporate capital ratio was 0.54.

       EME's corporate credit agreement contains covenants that restrict its ability and the ability of several of its subsidiaries to make distributions. This restriction impacts the subsidiaries that own interests in the Westside projects, the Sunrise project, the fossil-fueled facilities, and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME's shareholder if an event of default were to occur and be continuing under EME's secured credit agreement after giving effect to the distribution.

       During 2007, Midwest Generation also amended and restated its existing $500 million senior secured working capital facility. Borrowings made under this credit facility currently bear interest at LIBOR plus 0.875%, except if average utilized commitments during a period exceed $250 million, in which case the margin increases to 1%. The working capital facility matures in June 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, 2009, the debt to capitalization ratio was 0.18 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, 2009, Midwest Generation had no borrowings outstanding and $3 million of letters of credit had been utilized under the working capital facility.

144

Viento Funding II Wind Financing

       In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The financing included a $189 million seven-year term loan and a $13 million letter of credit facility which replaced project letters of credit previously issued under the EME corporate credit facility. Interest under the term loan accrues at LIBOR plus 3.875% initially, with the rate increasing 0.25% on the third and sixth anniversaries of the closing date. Viento Funding II entered into interest rate swap agreements to hedge the majority of the variable interest rate under the term loan. For further details regarding the interest rate swap agreements, see Note 3—Derivative Instruments and Risk Management.

       In July 2009, Viento Funding II amended the credit agreement to add a working capital facility. Availability under the working capital facility is initially $3.8 million and increases semi-annually to $5.2 million by maturity. The agreement restricts the use of proceeds from the working capital facility to operation and maintenance expenditures at these three wind projects.

       Distributions from Viento Funding II are subject to compliance with the terms and conditions of its credit facilities, including a covenant to meet a 12-month historic debt service coverage ratio as specified in the agreements of 1.20 to 1.0. Viento Funding II's payment obligations are secured by pledges of its direct and indirect ownership interests in the three wind projects.

Big Sky Turbine Financing

       In October 2009, EME, through its subsidiary, Big Sky, entered into turbine financing arrangements totaling approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project with the following principal terms:

•

Big Sky's repayment obligations are guaranteed by EME until the commercial operations date of the Big Sky wind project (or shortly thereafter);

•

interest under the loan accrues at six-month LIBOR plus 2.5% prior to the release of the EME guarantee, and at six-month LIBOR plus 3.5% thereafter; and

•

the loan has a five-year final maturity. However, specific events, including project performance, may trigger earlier repayment. The loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if any, of the Big Sky wind project is to be deposited on a monthly basis.

       As of December 31, 2009, no amounts were outstanding under this loan.

145

Annual Maturities on Long-Term Obligations

       Annual maturities on long-term debt at December 31, 2009, for the next five years are summarized as follows: $37 million in 2010, $36 million in 2011, $40 million in 2012, $545 million in 2013, and $48 million in 2014.

Standby Letters of Credit

       As of December 31, 2009, standby letters of credit under EME and its subsidiaries' credit facilities aggregated $119 million and were scheduled to expire as follows: $111 million in 2010 and $8 million in 2011.

Note 11. Income Taxes

Current and Deferred Taxes

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

			Years Ended December 31,
(in millions)			2009			2008		2007
Continuing Operations
	Current
		Federal	$	(176	)	$	95	$	138
		State		(35	)		33		14
		Total current		(211	)		128		152
	Deferred
		Federal	$	187		$	96	$	60
		State		40			19		7
		Total deferred		227			115		67
	Provision for income taxes from continuing operations			16			243		219
Discontinued operations				(2	)		5		5
Total			$	14		$	248	$	224

       Accrued income taxes reflected in accrued liabilities on EME's consolidated balance sheet totaled $93 million and $128 million at December 31, 2009 and 2008, respectively.

       The components of income (loss) before income taxes applicable to continuing operations and discontinued operations are as follows:

	Years Ended December 31,
(in millions)	2009			2008		2007
Continuing operations	$	217		$	743	$	634
Discontinued operations		(9	)		6		3
Total	$	208		$	749	$	637

146

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

		Years Ended December 31,
(in millions)		2009			2008			2007
Provision for federal income taxes at statutory rate		$	76		$	260		$	222
Increase (decrease) in taxes from:
	State tax, net of federal benefit		7			33			26
	Taxes on foreign operations at different rates		—			—			2
	Federal production tax credits		(55	)		(43	)		(27	)
	Qualified production deduction		(2	)		(13	)		—
	Other		(10	)		6			(4	)
Total provision for income taxes from continuing operations		$	16		$	243		$	219
Effective tax rate			7%			33%			34%

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

			December 31,
(in millions)			2009		2008
Deferred tax assets
	Accrued charges and liabilities		$	156	$	122
	Deferred income			5		5
	State taxes			—		4
	Other			—		7
		Total		161		138
Deferred tax liabilities
	Basis differences		$	821	$	592
	Derivative instruments			93		141
	Deferred investment tax credit			5		7
	State taxes			27		—
	Other			6		5
		Total		952		745
Deferred tax liabilities and tax credits, net			$	791	$	607
Classification of accumulated deferred income taxes:
	Included in current liabilities		$	119	$	66
	Included in non-current liabilities		$	672	$	541

       EME's investments in wind-powered electric generation qualify for federal production tax credits under Section 45 of the Internal Revenue Code. Certain of these investments may also be eligible for an option to claim investment tax credits (30% of eligible property) or obtain U.S. Treasury grants for specified renewable energy projects in lieu of tax credits (also 30% of eligible property). These options would be in lieu of the production tax credits for wind projects which may otherwise be claimed at an annually indexed rate per megawatt-hour (currently 2.1 cents per kilowatt hour) on actual production during the first 10 years of operation. The election to claim production tax credits or investment tax credits is made at

147

the time a tax return is filed for the first year in which the property is placed in service. Payment in lieu of tax credits (sometimes referred to as U.S. Treasury grants) would be obtained separate from the tax return under rules and regulations published by the U.S. Treasury Department. EME placed Phase II of the Goat Wind and High Lonesome wind projects in service during 2009. EME applied for U.S. Treasury grants in January 2010 for Phase II of the Goat Wind and High Lonesome wind projects in lieu of investment tax credits and plans to claim production tax credits for its Elkhorn Ridge wind project.

Accounting for Uncertainty in Income Taxes

       The following table provides a reconciliation of unrecognized tax benefits from January 1 to December 31:

(in millions)		2009		2008		2007
Beginning balance		$	144	$	136	$	140
Tax positions taken during the current year
	Increases		—		8		6
	Decreases		—		—		—
Tax positions taken during a prior year
	Increases		11		—		—
	Decreases		—		—		8
Decreases for settlements during the period			40		—		2
Decreases resulting from a lapse in statute of limitations			—		—		—
Ending balance		$	115	$	144	$	136

       The total amount of unrecognized tax benefits as of December 31, 2009 that, if recognized, would affect the effective tax rate was $114 million. The total amount of accrued interest and penalties was $12 million and $57 million as of December 31, 2009 and 2008, respectively. The total amount of interest expense and penalties recognized in income tax expense was $(45) million, $8 million and $8 million for 2009, 2008 and 2007, respectively. EME believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $16 million within the next 12 months.

       EME is included in the federal consolidated income tax return filed by Edison International. In May 2009, Edison International and the Internal Revenue Service completed a settlement of federal tax disputes and affirmative claims for open tax years 1986 through 2002. As a result, state tax years for the same periods are now open pending review by state taxing authorities of agreed final federal adjustments. The settlement includes the resolution of issues pertaining to EME which were largely timing in nature. During the second quarter of 2009, EME recorded an income tax benefit of $6 million due to the settlement and related estimated impact of interest and state income taxes. The amount recorded is subject to change based on the final determination of interest and state taxes and items affected under the tax-allocation agreement. During 2008, the Internal Revenue Service commenced an examination of Edison International's consolidated federal income tax return for the years 2003 through 2006.

148

Note 12. Compensation and Benefit Plans

Employee Savings Plan

       A 401(k) plan is maintained to supplement eligible employees' retirement income. The plan received contributions from EME of $13 million in 2009 and $15 million in 2008 and $12 million in 2007.

Pension Plans and Postretirement Benefits Other than Pensions

Pension Plans

       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 $22 million for the year ended December 31, 2010.

       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. This reduction in the value of plan assets will result in increased future expense and increased future contributions. Improved market conditions in 2009 partially offset the impacts of the 2008 market conditions. 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.

149

       Information on plan assets and benefit obligations is shown below:

		Years Ended December 31,
(in millions)		2009			2008
Change in projected benefit obligation
	Projected benefit obligation at beginning of year	$	211		$	196
	Service cost		15			13
	Interest cost		13			12
	Actuarial (gain) loss		10			(3	)
	Benefits paid		(6	)		(7	)
Projected benefit obligation at end of year		$	243		$	211
Change in plan assets
	Fair value of plan assets at beginning of year	$	99		$	134
	Actual return (loss) on plan assets		25			(44	)
	Employer contributions		10			16
	Benefits paid		(6	)		(7	)
Fair value of plan assets at end of year		$	128		$	99
Funded status at end of year		$	(115	)	$	(112	)
Amounts recognized in consolidated balance sheets:
Long-term liabilities		$	(115	)	$	(112	)
Amounts recognized in accumulated other comprehensive income:
Prior service cost		$	1		$	1
Net loss			37			48
Accumulated benefit obligation at end of year		$	204		$	180
Pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation		$	243		$	211
Accumulated benefit obligation			204			180
Fair value of plan assets			128			99
Weighted-average assumptions used to determine obligations at end of year:
Discount rate			6.0% to 6.25%			6.25%
Rate of compensation increase			5.0% to 6.0%			5.0%

150

Expense components and other amounts recognized in other comprehensive (income) loss

Expense components:

	Years Ended December 31,
(in millions)	2009			2008			2007
Service cost	$	15		$	13		$	16
Interest cost		13			12			11
Expected return on plan assets		(8	)		(10	)		(9	)
Net amortization		4			1			1
Total expense	$	24		$	16		$	19

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

	Years Ended December 31,
(in millions)	2009			2008
Net (gain) loss	$	(7	)	$	49
Prior service cost		—			1
Amortization of net loss		(4	)		(1	)
Total in other comprehensive (income) loss	$	(11	)	$	49
Total in expense and other comprehensive (income) loss	$	13		$	65

       The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2010 are $0.1 million for prior service costs and $2.6 million for net loss.

       The following are weighted-average assumptions used to determine expense:

	Years Ended December 31,
	2009		2008		2007
Weighted-average assumptions:
Discount rate		6.25%		6.25%		5.75%
Rate of compensation increase		5.0% to 6.0%		5.0%		5.0%
Expected long-term return on plan assets		7.5%		7.5%		7.5%

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

Years Ending December 31, (in millions)
2010	$	9
2011		10
2012		12
2013		14
2014		16
2015-2019		110

151

Postretirement Benefits Other Than Pensions

       Non-union employees retiring at or after age 55 with at least 10 years of service may be eligible for postretirement medical, dental, vision, and life insurance coverage. Eligibility for a company contribution toward the cost of these benefits in retirement 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 are $2 million for the year ended December 31, 2010.

       Information on plan assets and benefit obligations is shown below:

	Years Ended December 31,
(in millions)	2009			2008
Change in benefit obligation
Benefit obligation at beginning of year	$	99		$	83
Service cost		2			3
Interest cost		5			6
Amendments		(2	)		3
Actuarial (gain) loss		(8	)		6
Benefits paid		(2	)		(2	)
Benefit obligation at end of year	$	94		$	99
Change in plan assets
Fair value of plan assets at beginning of year	$	—		$	—
Employer contributions		2			2
Benefits paid		(2	)		(2	)
Fair value of plan assets at end of year	$	—		$	—
Funded status at end of year	$	(94	)	$	(99	)
Amounts recognized in consolidated balance sheets:
Long-term liabilities	$	(94	)	$	(99	)
Amounts recognized in accumulated other comprehensive income:
Prior service credit	$	(4	)	$	(3	)
Net loss		11			21
Weighted-average assumptions used to determine obligations at end of year:
Discount rate		6.0%			6.25%
Assumed health care cost trend rates:
Rate assumed for following year		8.25%			8.75%
Ultimate rate		5.5%			5.5%
Year ultimate rate reached		2016			2016

152

Expense components and other amounts recognized in other comprehensive (income) loss

Expense components:

	Years Ended December 31,
(in millions)	2009			2008			2007
Service cost	$	2		$	3		$	2
Interest cost		5			6			5
Amortization of prior service credit		(1	)		(2	)		(2	)
Amortization of net loss		1			1			2
Total expense	$	7		$	8		$	7

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

	Years Ended December 31,
(in millions)	2009			2008
Net (gain) loss	$	(8	)	$	18
Prior service credit		(2	)		(6	)
Amortization of prior service credit		1			3
Amortization of net loss		(1	)		(3	)
Total in other comprehensive (income) loss	$	(10	)	$	12
Total in expense and other comprehensive (income) loss	$	(3	)	$	20

       The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2010 are $1.6 million for prior service credit and $0.6 million for net loss.

       The following are weighted-average assumptions used to determine expense:

	Years Ended December 31,
	2009		2008		2007
Weighted-average assumptions used to determine expense:
Discount rate		6.25%		6.25%		5.75%
Assumed health care cost trend rates:
Current year		8.75%		9.25%		9.25%
Ultimate rate		5.5%		5.0%		5.0%
Year ultimate rate reached		2016		2015		2015

       Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of December 31, 2009, by $14 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, 2009, by $12 million and annual aggregate service and interest costs by $1 million.

153

       The following benefit payments are expected to be paid:

Years Ending December 31, (in millions)	Before Subsidy1		Net
2010	$	2	$	2
2011		3		2
2012		3		3
2013		4		4
2014		4		4
2015-2019		31		30

¹

Medicare Part D prescription drug benefits.

Discount Rate

       The discount rate enables EME to state expected future cash flows at a present value on the measurement date. EME selects its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. Two corporate yield curves were considered, Citigroup and AON.

Plan Assets

Description of Pension and Postretirement Benefits Other Than Pensions Investment Strategies

       The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active and passive investment strategies within asset classes. In 2009, the trusts' investment committee approved changes in target asset allocations. Target allocations for pension plan assets are 34% for United States equities, 17% for non-United States equities, 9% for alternative investments, and 40% for fixed income. 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 are measured against targets. EME also monitors the stability of its investments managers' organizations.

       Allowable investment types include:

•

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

•

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

•

Alternative Investments:

•

Private Equities: Limited partnerships that invest in non-publicly traded entities. The pension target allocation is 6%.

154

•

Hedge Funds: Funds that have target return and risk characteristics that are diversified among global equity, fixed income and currency markets. There is no systematic exposure to any market, and investments are made in liquid instruments according to relative opportunities within and across markets. The pension target allocation is 3%.

•

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

       Asset class portfolio weights are permitted to range within plus or minus 3%. Where approved by the fiduciary investment committee, futures contracts are used for portfolio rebalancing and to reallocate portfolio cash positions. Where authorized, a few of the plans' investment managers employ limited use of derivatives, including futures contracts, options, options on futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.

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

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

Capital Markets Return Forecasts

       Capital markets return forecasts are based on long-term strategic planning assumptions from an independent firm which uses its research, modeling and judgment to forecast rates of return for global asset classes. In addition, a separate analysis of expected returns is conducted. The estimated total return for fixed income is based on historic long-term United States government bonds data. The estimated total return for intermediate United States government bonds is based on historic and projected data. The estimated rate of return for United States and non-United States equity includes a 3% premium over the estimated total return for intermediate United States government bonds. The rate of return for private equity and hedge funds is estimated to be a 3% premium over public equity, reflecting a premium for higher volatility and illiquidity.

Fair Value of Plan Assets

       The plan assets for EME pension are included in the Southern California Edison Company Retirement Plan Trust (Master Trust) assets which include investments in equity securities, U.S. treasury securities, other fixed-income securities, common/collective funds, mutual funds, other investment entities, foreign exchange and interest rate contracts, and partnership/joint ventures. Equity securities, U.S. treasury securities, mutual and money market funds are classified as Level 1 as fair value is determined by observable, unadjusted quoted market prices in active or highly liquid and transparent markets. Common/collective funds are valued at the net asset value (NAV) of shares held. Although common/collective

155

funds are determined by observable prices, they are classified as Level 2 because they trade in markets that are less active and transparent. The fair value of the underlying investments in equity mutual funds and equity common/collective funds are based upon stock-exchange prices. The fair value of the underlying investments in fixed-income common/collective funds, fixed-income mutual funds and other fixed income securities including municipal bonds are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. Foreign exchange and interest rate contracts are classified as Level 2 because the values are based on observable prices but are not traded on an exchange. Future contracts trade on an exchange and therefore classified as Level 1. One of the partnerships is classified as Level 2 since this investment can be readily redeemed at NAV and the underlying investments are liquid publicly traded fixed-income securities which have observable prices. The remaining partnerships/joint ventures are classified as Level 3 because fair value is determined primarily based upon management estimates of future cash flows. Other investment entities are valued similarly to common collective funds and are, therefore, classified as Level 2. Substantially all of the registered investment companies are either mutual or money market funds and are, therefore, classified as Level 1 for the reasons noted previously. The remaining fund in this category is readily redeemable at NAV, classified as Level 2, and discussed further in footnote 7 of the following pension master trust table.

156

Pension Plan

       The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2009 by asset class and level within the fair value hierarchy:

	As of December 31, 2009
(in millions)	Level 1		Level 2		Level 3		Total
Corporate stocks1	$	678	$	—	$	—	$	678
Common/collective funds2		—		612		—		612
Corporate bonds3		—		469		—		469
U.S. government and agency securities4		104		352		—		456
Partnerships/joint ventures5		—		101		240		341
Other investment entities6		—		135		—		135
Registered investment companies7		73		58		—		131
Interest-bearing cash		5		—		—		5
Foreign exchange contracts		—		6		—		6
Other		—		7		—		7
Total	$	860	$	1,740	$	240	$	2,840
Receivables and payables, net								17
Master Trust net plan assets available for benefits								2,857
EME's share of pension Master Trust net plan assets							$	128

¹

Corporate stocks are diversified. Performance is primarily benchmarked against the Russell Indexes (61%) and Morgan Stanley Capital International (MSCI) indexes (39%).

²

At December 31, 2009, 69% of the common/collective funds' assets were invested in equity index funds that seek to track performance of the Standard and Poor's (S&P 500) Index (33%), Russell 200 and Russell 1000 (26%) and the Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index (10%). A non-index fund representing 20% of this category as of December 31, 2009, invests in equity securities the Trustee believes are undervalued. Another fund representing the remaining 7% of this category is a global hedge fund that invests in short-term fixed income securities and seeks to exceed the performance of the Citigroup One-Month U.S. Treasury Bill Index.

³

Corporate bonds are diversified. At December 31, 2009, this category includes $52 million for collateralized mortgage obligations and other asset backed securities of which $12 million are below investment grade.

⁴

Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relate to the Federal Home Loan Mortgage Corporation and the Federal National Mortgage Association.

⁵

Partnership/joint venture Level 2 consists of a partnership which invests in publicly traded fixed income securities, primarily from the banking and finance industry and U.S. government agencies. Approximately 60% of the Level 3 partnerships are invested in asset backed securities including distressed mortgages. The remaining Level 3 partnerships are invested in several small private equity and venture capital funds. Investment strategies for these funds include branded consumer products, early stage technology, California geographic focus, and diversified U.S. and non-U.S. fund-of-funds.

157

⁶

At December 31, 2009, 64% of the other investment entity balance is invested in emerging market equity securities. About 17% of the assets in this category are invested in domestic mortgage backed securities. Most of the remaining funds invest in below grade fixed-income securities including foreign issuers.

⁷

At December 31, 2009, Level 1 registered investment companies consists of a global equity fund which seeks to outperform the Morgan Stanley Capital International Inc. World Total Return Index. Level 2 of this category is a hedge fund that invests through liquid instruments in a global diversified portfolio of equity, fixed income, interest rate, foreign currency and commodities.

       At December 31, 2009, approximately 67% of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.

       The following table sets forth a summary of changes in the fair value of Level 3 investments for the year ended December 31, 2009:

(in millions)		2009
Fair value, net at January 1, 2009		$	111
Actual return on plan assets:
	Relating to assets still held at end of period		34
	Relating to assets sold during the period		6
Purchases and dispositions, net			89
Transfers in or out of Level 3			—
Fair value, net at December 31, 2009		$	240

Stock-Based Compensation

       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, with all subsequent issuances being made under the new plan. The maximum number of shares of Edison International's common stock authorized to be issued or transferred pursuant to awards under the incentive plan as adopted was 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 (carry-over shares). On April 23, 2009, Edison International's shareholders approved certain amendments to the 2007 Performance Plan increasing such authorization by 13 million shares, resulting in an aggregate share limit of 21.5 million shares, plus the carry-over shares. As of December 31, 2009, Edison International had approximately 13 million shares remaining for future issuance under its stock-based compensation plans.

       Total stock-based compensation expense (reflected in administrative and general on the consolidated statements of income) was $8 million, $7 million and $10 million for 2009, 2008 and 2007, respectively. The income tax benefit recognized in the consolidated statements of income was $3 million, $3 million and $4 million for 2009, 2008 and 2007, respectively. Excess tax benefits included in "excess tax benefits related to stock-based awards" in the financing

158

section of the consolidated statements of cash flows were less than a million, $3 million and $14 million in 2009, 2008 and 2007, respectively.

Stock Options

       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 $3 million, $6 million and $6 million in 2009, 2008 and 2007, respectively.

       Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the option term. Stock options granted in 2007 and later have no dividend equivalent rights except for options granted to Edison International's Board of Directors in 2007. Unless transferred to nonqualified deferral plan accounts, dividend equivalents accumulate without interest. 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.

	Years Ended December 31,
	2009		2008		2007
Expected terms (in years)		7.4		7.4		7.5
Risk-free interest rate		2.8% to 3.5%		2.6% to 3.8%		4.6% to 4.8%
Expected dividend yield		3.6% to 5.0%		2.3% to 3.9%		2.1% to 2.4%
Weighted-average expected dividend yield		5.0%		2.5%		2.4%
Expected volatility		20% to 21%		17% to 19%		16% to 17%
Weighted-average volatility		20.6%		17.4%		16.5%

       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. Expected volatility is based on the historical volatility of Edison International's common stock for the lesser of 1) the period from January 1, 2003 through the last month-end prior to the grant date, or 2) the length of the options expected term. The volatility period used was 84 months, 72 months and 36 months at December 31, 2009, 2008 and 2007, respectively.

159

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

				Weighted-Average
	Stock Options			Exercise Price		Remaining Contractual Term (Years)		Aggregate Intrinsic Value
Outstanding, December 31, 2008		2,134,457		$	34.86
Granted		1,056,202		$	24.96
Expired		(18,425	)	$	46.93
Transferred from affiliates		18,871		$	64.34
Forfeited		(18,074	)	$	30.32
Exercised		(28,500	)	$	20.02
Outstanding, December 31, 2009		3,144,531		$	31.49		6.59
Vested and expected to vest at December 31, 2009		2,995,476		$	31.44		6.50	$	12,982,365
Exercisable at December 31, 2009		1,583,269		$	30.27		4.72	$	8,061,590

       The weighted-average grant-date fair value of options granted during 2009, 2008 and 2007 was $3.00, $9.88 and $11.36, respectively. The total intrinsic value of options exercised was $0.4 million, $6 million and $32 million during 2009, 2008 and 2007, respectively. At December 31, 2009, there was $4 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 2009, 2008 and 2007 was $3 million, $4 million and $6 million, respectively.

       Cash outflows to purchase Edison International shares in the open market to settle stock option exercises by EME employees were $1 million, $11 million and $49 million for 2009, 2008 and 2007, respectively. Cash inflows from EME employees to exercise stock options was $1 million, $5 million and $19 million for 2009, 2008 and 2007, respectively. The tax benefit realized from options exercised was $0.2 million, $2 million and $11 million for 2009, 2008 and 2007, respectively.

Performance Shares

       A target number of contingent performance shares were awarded to executives in March 2007, March 2008 and March 2009, and vest at the end of December 2009, 2010 and 2011, respectively. Performance shares awarded 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 peer

160

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. 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. Edison International also has discretion to pay certain dividend equivalents in Edison International common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares that can be 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 share expense is recognized ratably over the requisite service period based on the fair values determined, except for awards granted to retirement-eligible participants. Stock-based compensation expense (benefit) associated with performance shares was $1 million, $(3) million and $3 million for 2009, 2008 and 2007, respectively.

       Cash outflows to purchase Edison International shares in the open market to settle performance shares classified as equity awards were $2 million and $5 million for 2008 and 2007, respectively. There were no performance shares settled in 2009. In 2007 Edison International changed the classification of the cash paid for the settlement of performance shares from common stock to retained earnings to conform with the classification for settlement of stock option exercises. The tax benefit realized from settlement of performance shares classified as equity awards for 2008 and 2007 was $1 million and $2 million, 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 the daily spot rate on the grant or valuation date on U.S. Treasury zero coupon issue or STRIPS (separate trading of registered interest and principal of securities) with terms equal to the remaining term of the performance shares and is used as proxy for the expected return for the specified group of companies. Expected volatility is based on the historical volatility of Edison International's (and the specified group of companies') common stock for the most recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data services provider.

       The risk-free interest rate used to determine the grant date fair values for the 2009, 2008 and 2007 performance shares classified as share-based equity awards was 1.3%, 3.9% and 4.8%, respectively. Edison International's expected volatility used to determine the grant date fair values for the 2009, 2008 and 2007 performance shares classified as share-based equity awards was 21.4%, 17.4% and 16.5%, respectively. The portion of performance shares classified as share-based liability awards are revalued at each reporting period. The risk-free interest rate used to determine the fair value as of December 31, 2009 was 1.1% and 0.5%, respectively, for the 2009 and 2008 performance shares. The expected volatility rate used to determine the fair value as of December 31, 2009 was 21.9%. The risk-free interest rate used to determine the fair value as of December 31, 2008 was 0.8% and 0.4%, respectively, for the

161

2008 and 2007 performance shares. The expected volatility rate used to determine the fair value as of December 31, 2008 was 19.2%. 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 2007 and 2006 performance shares. The total intrinsic value of performance shares settled during 2008 and 2007 was $5 million and $12 million, respectively, which included cash paid to settle the performance shares classified as liability awards for 2008 and 2007 of $2 million and $4 million, respectively. There were no performance shares settled in 2009. At December 31, 2009, there was $0.3 million (based on the December 31, 2009 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 approximately one year. The fair value of performance shares that vested during 2009, 2008 and 2007 was $0.2 million, $0.7 million and $4 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:

	Performance Shares			Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2008		33,371		$	46.53
Granted		37,628			21.06
Forfeited		(484	)		26.33
Transferred to affiliates		(107	)		57.76
Nonvested at December 31, 2009		70,408		$	33.04

       The weighted-average grant-date fair value of performance shares classified as equity awards granted during 2009, 2008 and 2007 was $21.06, $41.25 and $58.01, 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:

	Performance Shares			Weighted-Average Fair Value
Nonvested at December 31, 2008		33,371
Granted		37,628
Forfeited		(484	)
Transferred to affiliates		(107	)
Nonvested at December 31, 2009		70,408		$	18.50

162

Note 13. Commitments and Contingencies

Lease Commitments

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

       Future minimum payments for operating leases at December 31, 2009 are:

Years Ending December 31, (in millions)	Operating Leases
2010	$	353
2011		334
2012		331
2013		324
2014		303
Thereafter		1,803
Total future commitments	$	3,448

       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 $209 million, $208 million and $203 million in 2009, 2008 and 2007, respectively.

Sale-Leaseback Transactions

       On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City facilities to third-party lessors for an aggregate purchase price of $1.6 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809 million). Under the terms of the 33.67-year leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $155 million in 2010, $160 million in 2011, $160 million in 2012, $149 million in 2013, and $138 million in 2014, and the total remaining minimum lease payments are $1.4 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 $170 million in 2010, $151 million in each of 2011, 2012, 2013 and 2014.

163

The total remaining minimum lease payments are $337 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, 2009, 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.

Other Commitments

Capital Improvements

       At December 31, 2009, EME's subsidiaries had firm commitments to spend approximately $441 million in 2010 on capital and construction expenditures. The majority of these expenditures primarily relate to the construction of wind projects and non-environmental improvements at the fossil-fueled facilities. These expenditures are planned to be financed by cash on hand, cash generated from operations, and project level and turbine vendor financing. EME has secured $206 million in wind project financing. For further discussion, see Note 10—Financial Instruments.

Turbine Commitments

       EME has entered into various turbine supply agreements with vendors to support its wind development efforts. As of December 31, 2009, EME had commitments to purchase 183 wind turbines (349 MW) and had 67 wind turbines (163 MW) in storage to be used for future wind projects. EME has commitments on the turbines under purchase contracts and in storage of $463 million due in 2010 and $22 million due in 2011. As of December 31, 2009 and 2008, EME had $123 million and $318 million, respectively, in wind turbine deposits and $191 million and $9 million, respectively, related to wind turbines in storage included in other long-term assets on its consolidated balance sheet. EME continues to actively negotiate with its turbine suppliers to match turbine delivery and payment dates to the deployment of turbines at individual wind projects.

       In February 2010, EME commenced construction of a 130 MW wind project in Oklahoma, which EME refers to as the Taloga wind project. EME plans to use 54 wind turbines currently in storage to complete the Taloga wind project. The project is scheduled for completion in late 2010. In February 2010, EME allocated turbines under one of its existing turbine supply agreements for 53 wind turbines (80 MW) to be used for the Laredo Ridge wind project located in Nebraska, which reduces the remaining turbines available for future projects to 302 MW. The Laredo Ridge wind project is being developed under a joint development agreement. EME intends to purchase the project in the second quarter of 2010. The project has contracted to sell power to the Nebraska Public Power District under a 20-year power sales contract and is expected to be completed in late 2010.

164

       One of EME's existing turbine supply agreements can be terminated for convenience. Termination of this agreement in its entirety would further reduce turbine commitments by $84 million during 2010. In the event of such termination by EME, a write-off of approximately $21 million would be recognized.

Fuel Supply Contracts

       At December 31, 2009, Midwest Generation and Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are estimated to aggregate $932 million, summarized as follows: $457 million in 2010, $263 million in 2011, and $212 million in 2012.

       In January and February 2010, Midwest Generation and Homer City entered into additional contractual agreements for the purchase of coal. These commitments, together with estimated transportation costs under existing agreements through 2011, are estimated to be $22 million in 2010, $94 million in 2011, $33 million in 2012 and $33 million in 2013.

       In connection with the acquisition of the Midwest Generation plants, Midwest Generation 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 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, net" on EME's consolidated statements of income.

Gas Transportation Agreements

       At December 31, 2009, 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 eight years, is estimated to aggregate $41 million in the next five years, $8 million each year, 2010 through 2013, and $9 million in 2014. EME has entered into agreements to re-sell the transportation under this agreement which aggregates $50 million over the same period.

Coal Transportation Agreements

       At December 31, 2009, Midwest Generation and Homer City had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. The minimum commitments under these contracts are estimated to aggregate $388 million, summarized as $244 million in 2010 and $144 million in 2011.

165

Other Contractual Obligations

       At December 31, 2009, 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 used while operating environmental controls equipment. The minimum commitments under these contracts are estimated to aggregate $236 million in the next four years: $84 million in 2010, $69 million in 2011, $58 million in 2012, and $25 million in 2013.

Guarantees and Indemnities

       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.

Tax Indemnity Agreements

       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.

Environmental Indemnities Related to the Midwest Generation Plants

       In connection with the acquisition of the Midwest Generation 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. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligation under these indemnities, a maximum potential liability cannot be determined. 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 litigation discussed below under "—Contingencies—Midwest Generation New Source Review Lawsuit." The sale-leaseback participants have requested similar indemnification. Except as discussed below, EME has not recorded a liability related to these environmental indemnities.

166

       Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC 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 2011. There were approximately 217 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2009. Midwest Generation had recorded a $50 million and $52 million liability at December 31, 2009 and 2008, respectively, 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.

Environmental Indemnity Related to the Homer City Facilities

       In connection with the acquisition of the Homer City facilities, Homer City agreed to indemnify the sellers with respect to specified 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 Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City facilities, Homer City agreed to indemnify the lessors for specified environmental liabilities. 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. For discussion of the NOV received by Homer City and associated indemnity claims, see "—Contingencies—Homer City New Source Review Notice of Violation." EME has not recorded a liability related to this indemnity.

167

Indemnities Provided under Asset Sale Agreements

       The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. 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, 2009 and 2008, EME had recorded a liability of $96 million (of which $56 million is classified as a current liability) and $95 million, respectively, related to these matters.

       In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, 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, 2009, EME had recorded a liability of $2 million related to these matters.

Contingencies

Midwest Generation New Source Review Lawsuit

       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 PSD requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install controls sufficient to meet BACT emissions rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.

       On August 27, 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or NSR permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies

168

sought by the plaintiffs in the lawsuit could go well beyond those required under the CPS. By order dated January 19, 2010, the court allowed a group of Chicago-based environmental action groups to intervene in the case.

       The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by undertaking the indemnity obligation and defense of the claims.

       An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Homer City New Source Review Notice of Violation

       On June 12, 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, 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 PSD requirements of the CAA. The US EPA also alleges that 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. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. 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 cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

       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 Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.

       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 Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by undertaking the indemnity obligation and defense of the claims.

Environmental Remediation

       With respect to 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 had accrued approximately $4 million at December 31, 2009 for estimated environmental investigation and remediation costs for the Midwest Generation plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where

169

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.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

       Midwest Generation is subject to various requirements with respect to environmental compliance for the Midwest Generation plants. In 2006, Midwest Generation entered into an agreement with the Illinois EPA, which has been embodied in an Illinois rule called the CPS, to control emission of mercury, NO_x and SO₂ from its coal-fired plants. During 2008 and 2009, Midwest Generation installed equipment to reduce its mercury emissions. During 2009, Midwest Generation also conducted tests of NO_x removal technology based on SNCR and SO₂ removal using FGD technology based on dry sodium sorbent injection that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NO_x portion of the CPS. Capital expenditures for installation of SNCR technology are expected to be approximately $88 million in 2010 and $70 million in 2011.

       Testing of FGD technology based on injection of dry sodium sorbent demonstrated significant reductions in SO₂ emissions when using the low-sulfur coal employed by Midwest Generation; however, further analysis and evaluation is required to determine the appropriate method to comply with the SO₂ portion of the CPS. Use of FGD technology based on injection of dry sodium sorbent in combination with Midwest Generation's use of low-sulfur coal is expected to require substantially less capital and installation time than dry scrubber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of the plants. Midwest Generation may also combine the use of dry sorbent injection technology with upgrades to its particulate removal systems to meet environmental regulations.

       Midwest Generation does not yet know what specific method of SO₂ removal will be used or the total costs that will be incurred to comply with the CPS. Any decision regarding whether or not to proceed with the above or other approaches to compliance remains subject to further analysis and the evaluation of several factors, including market conditions, regulatory and legislative developments, and forecasted capital and operating costs. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, the particular controls that will be installed, and the resulting capital commitments may not occur for up to two years for some of the units and potentially further out for others. Midwest Generation could elect to shut down units when required to comply with the SO₂ removal requirements of the CPS. Midwest Generation continues to evaluate

170

various scenarios and cannot predict the extent of shutdowns and retrofits or the particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS.

Homer City Environmental Issues and Capital Resource Limitations

       Homer City operates SCR equipment on all three units to reduce NO_x emissions, operates FGD equipment on Unit 3 to reduce SO₂ emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations under the CAIR and Pennsylvania mercury regulations. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual obligation to provide funding to Homer City.

Greenhouse Gas Regulation Developments

       The nature of future environmental regulation and legislation will have a substantial impact on EME. EME believes that resolution of current uncertainties about the future, through well-balanced and appropriately flexible regulation and legislation, is needed to support the necessary evolution of the electric industry into using cleaner, more efficient infrastructure and to attract the capital ultimately needed for this effort. Legislative, regulatory, and legal developments related to potential controls over GHG emissions in the United States are ongoing. Actions to limit or reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels. EME may not be able to recover these costs through market prices for electricity.

Insurance

       At December 31, 2009 and 2008, EME's subsidiaries had a $10 million and $9 million receivable, respectively, recorded primarily related to insurance claims from unplanned outages. During 2009, 2008 and 2007, $2 million, $6 million and $5 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 $9 million and $7 million in cash payments related to insurance claims during 2009 and 2008, respectively.

Note 14. Related-Party Transactions

       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

171

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 $55 million, $66 million and $76 million in 2009, 2008 and 2007, respectively. At December 31, 2009 and 2008, the amount due to Edison International was $14 million and $15 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.

       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 $26 million for 2009, $28 million for 2008 and $30 million for 2007. Receivables from affiliates for Edison Mission Operation & Maintenance totaled $6 million and $7 million at December 31, 2009 and 2008, respectively.

       EME owns interests in partnerships that sold electricity generated by their project facilities to SCE and others under the terms of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $366 million, $686 million and $747 million in 2009, 2008 and 2007, respectively.

       During the first quarter of 2008, a subsidiary of EME was awarded by SCE, through a competitive bidding process, a 10-year power sales contract starting in 2013 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. 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 a November 2008 decision, the Los Angeles Superior Court enjoined SCAQMD from issuing Priority Reserve emission credits to Walnut Creek and other projects. Legal challenges related to the Priority Reserve emission credits are continuing. Legislation that passed the State Assembly and is currently pending in the Senate would provide access to the credits for Walnut Creek, subject to further regulatory steps and litigation risk. 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 qualifying credits. Construction on the Walnut Creek project will not begin until its access to the Priority Reserve emission credits is restored or another source of credits is identified. The capital costs to construct this project, excluding interest, are estimated in the range of $500 million to $600 million.

172

Note 15. Supplemental Cash Flows Information

		Years Ended December 31,
(in millions)		2009			2008		2007
Cash paid (received)
	Interest (net of amount capitalized1)	$	301		$	295	$	320
	Income taxes		(131	)		120		120
	Cash payments under plant operating leases		336			337		336
Details of assets acquired
	Fair value of assets acquired	$	14		$	—	$	41
	Liabilities assumed		3			—		—
	Net assets acquired	$	11		$	—	$	41
Non-cash activities from consolidation of variable interest entities
	Assets	$	3		$	3	$	12
	Liabilities		4			4		5

¹

Interest capitalized for the years ended December 31, 2009, 2008 and 2007 was $19 million, $32 million and $24 million, 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 2010.

Note 16. Quarterly Financial Data (unaudited)

(in millions)		First			Second			Third			Fourth			Total
2009
	Operating revenues	$	612		$	557		$	593		$	615		$	2,377
	Operating income		131			88			80			90			389
	Income from continuing operations		53			46			53			49			201
	Discontinued operations, net		3			(7	)		(1	)		(2	)		(7	)
	Net income		56			39			52			47			194
2008
	Operating revenues	$	719		$	613		$	814		$	665		$	2,811
	Operating income		276			121			308			147			852
	Income from continuing operations		150			73			202			75			500
	Discontinued operations, net		(5	)		(1	)		6			1			1
	Net income		145			72			208			76			501

173

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

       Omitted pursuant to General Instruction I.(2)(c).

ITEM 11. EXECUTIVE COMPENSATION

       Omitted pursuant to General Instruction I.(2)(c).

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

       Omitted pursuant to General Instruction I.(2)(c).

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

       Omitted pursuant to General Instruction I.(2)(c).

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

INDEPENDENT ACCOUNTANT FEES

       The following table sets forth the aggregate fees billed to EME (consolidated total including EME and its subsidiaries), for the fiscal years ended December 31, 2009 and December 31, 2008, by PricewaterhouseCoopers LLP:

	EME and Subsidiaries
($000)	2009		2008
Audit fees	$	2,962	$	3,097
Audit related fees1		197		223
Tax fees2		385		1,380
All other fees		—		—
Total	$	3,544	$	4,700

¹

The nature of the services comprising these fees were assurance and related services related to the performance of the audit or review of the financial statements and not reported under "Audit Fees" above.

²

The nature of the services comprising these fees were to support compliance with federal, state and foreign tax reporting and payment requirements, including tax return review and review of tax laws, regulations or cases.

       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)

174

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, 2009, 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.

175

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

       The following documents have been filed as part of this report or, where noted, incorporated by reference:

(a)

(1) List of Financial Statements

       See Index to Consolidated Financial Statements at Item 8 of this report.

(2)

List of Financial Statement Schedules

       The following financial statement schedules are included in this report:

	Page
Schedule I—Condensed Financial Information of Parent	183
Schedule II—Valuation and Qualifying Accounts	187

       All other schedules have been omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

(3)

List of Exhibits

       The exhibit list below is incorporated herein by reference as the list of exhibits required as part of this report.

       The agreements included or incorporated by reference as exhibits to this report contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of "materiality" that are different from "materiality" under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.

       EME acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this report not misleading.

176

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.
	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.

177

Exhibit No.		Description
	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.
	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.

178

Exhibit No.		Description
	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.
	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.

179

Exhibit No.		Description
	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.
	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.

180

Exhibit No.		Description
	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.
	10.12	Administrative Agreement Re Tax Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.
	31.1*	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
	31.2*	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
	32*	Statement Pursuant to 18 U.S.C. Section 1350.
	101**	Financial statements from the annual report on Form 10-K of Edison Mission Energy for the year ended December 31, 2009, filed on March 1, 2010, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Total Equity, (iv) the Consolidated Statements of Comprehensive Income, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements tagged as blocks of text.

*

Filed herewith.

**

Furnished, not filed, pursuant to Rule 406T of SEC Regulation S-T.

†

Confidential treatment granted.

181

SIGNATURES

       Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EDISON MISSION ENERGY (REGISTRANT)
By:	/s/ John P. Finneran, Jr. John P. Finneran, Jr. Senior Vice President and Chief Financial Officer
Date:	March 1, 2010

       Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ronald L. Litzinger
Ronald L. Litzinger	Director, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)	March 1, 2010
/s/ John P. Finneran, Jr.
John P. Finneran, Jr.	Senior Vice President and Financial Officer (Principal Financial Officer)	March 1, 2010
/s/ Joanne M. Collins
Joanne M. Collins	Vice President and Controller (Controller or Principal Accounting Officer)	March 1, 2010
/s/ W. James Scilacci
W. James Scilacci	Director	March 1, 2010
/s/ Robert L. Adler
Robert L. Adler	Director	March 1, 2010

182

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED BALANCE SHEETS (in millions)
		December 31,
		2009		2008
Assets
Cash and cash equivalents		$	180	$	749
Affiliate receivables			22		36
Other current assets			1		10
	Total current assets		203		795
Investments in subsidiaries			7,756		7,363
Other long-term assets			469		657
Total Assets		$	8,428	$	8,815
Liabilities and Shareholder's Equity
Accounts payable and accrued liabilities		$	58	$	77
Affiliate payables			417		498
Current maturities of long-term debt			—		13
	Total current liabilities		475		588
Long-term obligations			3,700		4,076
Long-term affiliate debt			1,348		1,352
Deferred taxes and other			144		115
Total Liabilities			5,667		6,131
Total EME Common Shareholder's Equity			2,761		2,684
Total Liabilities and Shareholder's Equity		$	8,428	$	8,815

183

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME (in millions)
	Years Ended December 31,
	2009			2008			2007
Operating revenues	$	6		$	9		$	7
Operating expenses		(121	)		(124	)		(121	)
Operating loss		(115	)		(115	)		(114	)
Equity in income from continuing operations of subsidiaries		488			809			1,069
Interest expense and other		(393	)		(398	)		(356	)
Income (loss) before income taxes		(20	)		296			599
Provision for income taxes		217			205			185
Net income attributable to EME common shareholders	$	197		$	501		$	414

184

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF CASH FLOWS (in millions)
	Years Ended December 31,
	2009			2008			2007
Net cash provided by operating activities	$	100		$	215		$	327
Net cash provided by (used in) financing activities		(517	)		219			(525	)
Net cash (used in) provided by investing activities		(152	)		(349	)		49
Net increase (decrease) in cash and cash equivalents		(569	)		85			(149	)
Cash and cash equivalents at beginning of period		749			664			813
Cash and cash equivalents at end of period	$	180		$	749		$	664
Cash dividends received from subsidiaries	$	367		$	206		$	660

185

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT

Note 1. Basis of Presentation

       EME (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements" of this report.

Note 2. Long-term Obligations

       For a description and details of long-term obligations of EME including the parent company only, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Financial Instruments" of this report.

Note 3. Commitments and Contingencies

       For a description of all material contingencies and guarantees of EME including the parent company only, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Commitment and Contingencies" of this report.

186

SCHEDULE II

EDISON MISSION ENERGY AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS (in millions)
				Additions
Description		Balance at Beginning of Year		Charged to Costs and Expenses		Charged to Other Accounts			Deductions		Balance at End of Year
Year Ended December 31, 2009
Uncollectible accounts
	Customers	$	2	$	—	$	—		$	—	$	2
	All others		48		—		—			—		48
Total		$	50	$	—	$	—		$	—	$	50
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

¹

For more information, see Note 4. Accumulated Other Comprehensive Income.

187

EX-31.1

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 31.1

CERTIFICATIONS

I, Ronald L. Litzinger, certify that:

1.

I have reviewed this annual report on Form 10-K for the year ended December 31, 2009, of Edison Mission Energy;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2010 /s/ Ronald L. Litzinger
Ronald L. Litzinger
Chairman of the Board, President and
Chief Executive Officer

QuickLinks

Exhibit 31.1

CERTIFICATIONS

EX-31.2

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 31.2

CERTIFICATIONS

I, John P. Finneran, Jr., certify that:

1.

I have reviewed this annual report on Form 10-K for the year ended December 31, 2009, of Edison Mission Energy;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2010 /s/ John P. Finneran, Jr.
John P. Finneran, Jr.
Senior Vice President and Chief
Financial Officer

QuickLinks

Exhibit 31.2

CERTIFICATIONS

EX-32

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 32

STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350,
AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the accompanying Annual Report on Form 10-K for the year ended December 31, 2009 (the "Annual Report") of Edison Mission Energy (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his knowledge, that:

1.

The Annual Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

2.

The information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 1, 2010
	/s/ Ronald L. Litzinger Ronald L. Litzinger Chief Executive Officer Edison Mission Energy
	/s/ John P. Finneran, Jr. John P. Finneran, Jr. Chief Financial Officer Edison Mission Energy

        This statement accompanies the Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

        A signed original of this written statement has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

QuickLinks

Exhibit 32

STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350, AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002