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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PART IV

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

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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, 2010

Commission File Number 333-68630

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

Registrant's telephone number, including area code: (714) 513-8000

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

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

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        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):

        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, 2010: $0. Number of shares outstanding of the registrant's Common Stock as of February 28, 2011: 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

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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 Edison Mission Energy's (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:

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

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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;

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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;

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the cost and availability of fuel, sorbents, and other commodities used for power generation and emission controls, and of related transportation services;

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the cost and availability of emission credits or allowances;

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

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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;

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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;

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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 independent system operators and regional transmission organizations;

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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;

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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;

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

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weather conditions, natural disasters and other unforeseen events;

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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;

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

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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;

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

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general political, economic and business conditions; and

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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.

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GLOSSARY

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

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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. Some of the facilities are operated on a merchant basis, with energy being sold into the marketplace, and others are operated under contracts calling for the delivery of energy to specific purchasers. EME also engages in hedging and energy trading activities in power markets through its EMMT 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 generation facilities 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, which include wind projects and one biomass project. As of December 31, 2010, EME's subsidiaries and affiliates owned or leased interests in 39 operating projects with an aggregate net physical capacity of 10,979 MW of which EME's pro rata share was 9,852 MW. At December 31, 2010, EME's subsidiaries and affiliates also owned four wind projects under construction totaling 480 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 3 MacArthur Place, Suite 100, Santa Ana, California 92707, and EME's telephone number is (714) 513-8000. 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."

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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 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 addition, capacity markets in various regional wholesale power markets compensate supply resources for the capability to supply electricity when needed, and demand resources for the electricity they avoid using.

Wholesale Markets

EME's largest power plants are its coal power plants located in Illinois, which are collectively referred to as the Midwest Generation plants in this annual report, and the Homer City plant located in Pennsylvania. Collectively, EME refers to both the Midwest Generation plants and the Homer City plant as the coal plants. The coal plants 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. Sales may also be made from PJM into the Midwest Independent Transmission System Operator (MISO) RTO, which includes all or 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.

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 requires all load-serving entities and generators, such as Midwest Generation and Homer City, to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM's capacity markets have a single market-clearing price for each capacity zone. In May of every year, PJM conducts an annual capacity auction (RPM) to commit generation, energy efficiency and demand side resources three years forward, and to provide a long-term pricing signal for capacity resources.

Competition

EME is subject to competition from energy marketers, public utilities, government-owned power agencies, industrial companies, financial institutions, and other independent power producers. These companies may have competitive advantages as a result of scale, the location of their generation facilities or other factors. 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.

State and local environmental regulations, particularly those that impose stringent state specific emission limits, could put EME's coal plants at a disadvantage compared with competing power plants operating in nearby states and subject to less stringent state emission limits or to federal emission limits alone, and the CPS could put the Midwest Generation plants at a disadvantage compared with competing plants not subject to similar regulations. Potential future climate change regulations could also put EME's coal plants at a

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disadvantage compared to both power plants utilizing other fuels and utilities that may be able to recover climate change compliance costs through rate-base mechanisms. In addition, the ability of these 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, which is located in the Republic of Turkey. Operating revenues are primarily derived from the sale of energy and capacity generated from the coal plants. EME is headquartered in Santa Ana, California, and its subsidiaries have offices located in Bolingbrook and Chicago, Illinois, and Boston, Massachusetts.

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Overview of Facilities

As of December 31, 2010, EME's operations consisted of ownership or leasehold interests in the following operating projects:

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At December 31, 2010, the fuel sources for these projects were as follows:

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

Seasonality

Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally 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, income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be 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 Coal Plants."

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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.

Merchant Power Plants

Midwest Generation Plants

The Midwest Generation plants consist of the following:

 

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 power

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marketing and trading activities, with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Thus, EME is subject to market risks related to the price of energy and capacity from the Midwest Generation plants. Power generated at the Midwest Generation plants is primarily sold into the PJM market.

Fuel Supply

The Midwest Generation plants purchase coal from several suppliers located 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. Midwest Generation's long-term rail transportation contract with Union Pacific Railroad expires at the end of 2011. For additional information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Coal and Transportation Price Risk." As of December 31, 2010, Midwest Generation leased approximately 3,900 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 nine years, with options to extend the leases or purchase some railcars at the end of the lease terms.

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 Plant

The Homer City plant is leased and consists 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 plant 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. Thus, EME is subject to market risks related to the price of energy and capacity from the Homer City plant. The Homer City plant is situated in the PJM control area and has direct, high voltage interconnections to PJM and also to the NYISO. Electric power generated at the Homer City plant is primarily sold into the PJM market.

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Fuel Supply

Homer City's Units 1 and 2 collectively consume approximately 3.3 million to 3.5 million tons of mid-range sulfur coal per year. Two types of coal are purchased, ready—to-burn and raw coal. Ready—to-burn coal is of the 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 and can consume either raw or ready-to-burn coal. A wet scrubber flue gas desulfurization system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control. In general, the coal purchased for all three units is acquired locally. Homer City purchases the majority of its coal under term contracts with the balance purchased in the spot market as needed. For additional information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Coal and Transportation Price Risk."

Emission Allowances for the Coal Plants

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, the coal plants are required to hold seasonal and annual NO_x allowances. As part of the acquisition of the coal plants, EME obtained emission allowance rights that have been or are allocated to these facilities. 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. Future regulations, including the Transport Rule, may impact future emission allowance allocations and may require EME to purchase additional allowances in amounts that could be significant.

Merchant Wind Projects

EME owns two merchant wind projects as follows:

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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 in the table below. Because these projects have similar economic characteristics, EME views these projects collectively and refers to them as the Big 4 projects. On December 16, 2010, the CPUC approved a comprehensive settlement of various issues related to power sales from cogeneration facilities (including the Big 4 projects) that implements a mechanism to foster new power purchase agreements for such facilities, and provides transition power purchase agreements during implementation. The settlement will become effective if FERC approves a related filing.

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. EME expects that these arrangements will be replaced by new power and steam purchase agreements, but cannot predict whether or when this will occur. The Kern River project may also operate as a merchant generator selling into the California ISO market.

Midway-Sunset Project

Midway-Sunset sells electricity to PG&E under a power purchase agreement that expires in 2016. Midway-Sunset also sells electricity and steam to Aera Energy LLC under agreements that expire concurrently with the PG&E power purchase agreement.

Sycamore Project

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 pursuant to the settlement referred to above,

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but cannot predict whether or when this will occur. Sycamore Cogeneration sells steam to Chevron North America Exploration and Production Company under an agreement that expires in 2013.

Watson Project

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, but cannot predict 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 the 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 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. Currently, these projects sell electricity to PG&E under agreements that provide for sales at "as available" rates. On October 6, 2010, each of the Westside projects entered into power purchase agreements with PG&E that expire in 2016. The new power purchase agreements will become effective after CPUC approval, which is pending.

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 sells electricity under a long-term power purchase agreement with the California Department of Water Resources that 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, for each contracted wind project, the project's power purchase agreement expiration, either the expiration of the project's production tax credits or

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an indication that EME elected to receive a U.S. Treasury grant, and the project's commercial operation or acquisition date.

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. In 2010, the Town of Huntington exercised its renewal option to extend the disposal services agreement to 2019. The Huntington 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

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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 in the Republic of 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.

Renewable Development Activities

At December 31, 2010, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW and had four projects totaling 480 MW under construction. Projects under construction at December 31, 2010 were as follows:

Laredo Ridge and Big Sky achieved commercial operation on February 1, 2011 and February 18, 2011, respectively. EME anticipates that the remaining projects under construction will also achieve commercial operation in 2011. In addition to the projects under construction at December 31, 2010, EME expects the 55 MW Pinnacle project in West Virginia will commence construction in 2011 with anticipated commercial operation in 2011. For more information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview."

Asset Management and Trading Activities

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

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Asset Management—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 EME's facilities. EME uses derivative instruments to

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reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. The objective of these activities is to sell the output of the facilities on a forward basis or to hedge the risk of future changes in prices. Hedging activities include on-peak and off-peak periods and may include load service requirements contracts with local utilities. Transactions related to hedging activities are designated separately from EMMT's trading activities. Not all contracts entered into by EMMT for hedging purposes qualify as hedges for accounting purposes.

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Trading—As an extension of its asset management 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.

Significant Customers

For a discussion of EME's significant customers, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities—Credit Risk."

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.

Discontinued Operations

For a discussion of discontinued operations, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 14. 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.

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Federal Power Act

The FERC has 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. 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. Previously approved rates may also be revoked or modified by the FERC after notice and opportunity for hearing.

The FERC also has 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 and certain types of financing arrangements may require FERC approval.

Each of EME's domestic generating facilities is either a qualifying facility, as determined by the FERC, or the subsidiary owning the facility is an EWG. Most qualifying facilities are exempt from the ratemaking and several other provisions of the FPA. EME's EWGs are subject to the FERC's ratemaking jurisdiction under the FPA, but have been authorized 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. 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.

If one of the projects in which EME has an interest were to lose its qualifying facility or EWG status, the project would no longer be entitled to the related exemptions from regulation and could become subject to rate regulation by the FERC and state authorities. Loss of status could also trigger defaults under covenants contained in the project's power sales agreements and financing agreements.

Reliability Standards

NERC establishes and enforces reliability standards for the bulk power system. 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 may be 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.

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Dodd-Frank Act

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides the Commodity Futures Trading Commission and the Securities and Exchange Commission with jurisdiction to regulate financial derivative products, including swaps, options and other derivative products, collectively referred to in this annual report as "swaps." These agencies are required to issue rules and regulations that implement regulation of swaps markets by July 2011.

The Dodd-Frank Act subjects swaps to new mandatory clearing and trading requirements, if no exemption applies. It may also impose capital requirements on non-exempt market participants. The clearing and trading requirements could result in increased margining requirements which may increase the costs of hedging activity. EME and its subsidiaries, particularly EMMT, use swaps to hedge commercial risks associated with the generation, purchase and sale of electricity and fuel to wholesale customers. In addition, EMMT utilizes swaps as part of its proprietary trading business.

If new clearing, trading or other requirements are applicable to EME under the Dodd-Frank Act rules and regulations, the potential impact will depend on the content of those rules and regulations, which remains uncertain.

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 and requirements with respect to 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. In addition, as discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies," the US EPA and others have from time to time sought to involve EME in litigation related to facilities owned by EME's subsidiaries. The facilities of EME's subsidiaries which are most affected by environmental regulation are located in Illinois and Pennsylvania. EME continues to monitor legislative and regulatory developments and to evaluate possible strategies for compliance with environmental regulations. 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" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Merchant Coal-Fired Power Plants."

Climate Change

There have been a number of federal and state legislative and regulatory initiatives 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

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for the emission of GHGs could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, which could adversely affect EME.

Federal Legislative/Regulatory Developments

Efforts to pass comprehensive federal climate change legislation have not yet been successful. The timing, contents, and potential effects on EME of federal legislation imposing limits on GHG emissions remain uncertain. However, the US EPA has begun to issue federal GHG regulations that are likely to impact EME's operations.

In June 2010, the US EPA issued the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG emissions and newly modified existing major sources to the PSD air permitting program beginning in January 2011 (and later, to the Title V permitting program under the CAA); however, the GHG tailoring rule significantly increases the emissions thresholds that apply before facilities are subjected to these programs. The emissions thresholds for CO₂ equivalents in the final rule vary from 75,000 tons per year to 100,000 tons per year depending on the date and whether the sources are new or modified.

A challenge to the GHG tailoring rule (along with other GHG regulations and determinations issued by the US EPA) is pending before the U.S. Court of Appeals for the D.C. Circuit. Regulation of GHG emissions pursuant to the PSD program could affect efforts to modify EME's facilities in the future, and could subject new capital projects to additional permitting and pollution control requirements that could delay such projects. If EME is required to install controls in the future or otherwise modify its operations in order to reduce GHG emissions, the potential impact of the GHG tailoring rule will depend on the nature and timing of the controls or modifications, which remain uncertain.

In December 2010, the US EPA announced that it had entered into a settlement with various states and environmental groups to resolve a long-standing dispute over regulation of GHGs from electrical generating units pursuant to the New Source Performance Standards in the CAA. Under the pending settlement, the US EPA will propose performance standards for GHG emissions from new and modified power plants and emissions guidelines for existing power plants in July 2011, and will finalize such regulations by May 2012, with compliance dates for existing power plants expected to be in 2015 or 2016. The specific requirements will not be known until the regulations are finalized.

Since January 2010, the US EPA's Final Mandatory Greenhouse Gas Reporting Rule has required all sources within specified categories, including electric generation facilities, to monitor emissions 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's 2010 GHG emissions were approximately 50.2 million metric tons.

Regional Initiatives and State Legislation

Regional initiatives and state legislation may also require reductions of GHG emissions, and it is not yet clear whether or to what extent any federal legislation would preempt them. If state

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and/or regional initiatives remain in effect after federal legislation is enacted, generators could be required to satisfy them in addition to federal standards.

EME's operations in California are subject to two laws governing 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, effective in 2012, that would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In December 2010, the CARB finalized regulations establishing a California cap-and-trade program, which include revisions to the CARB's mandatory GHG emissions reporting regulation. The regulations and the cap-and-trade program itself are being challenged by various citizens' groups under the California Environmental Quality Act.

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

EME's operations in California may be also affected by the Western Climate Initiative, an agreement entered into by California, other western states and certain Canadian provinces, to develop strategies to reduce GHG emissions in the region to 15% below 2005 levels by 2020. In July 2010, the Initiative partners released a comprehensive strategy for a regional cap-and-trade program, with a planned start date of January 2012, to help achieve their reduction goal. Recent political developments make it uncertain whether this regional program will proceed and what form it might take. As noted above, California is implementing its own program to reduce GHG emissions.

EME's operations in Illinois may be affected by the Midwestern Greenhouse Gas Reduction Accord, by which six Midwestern states, including Illinois, and the Canadian province of Manitoba agreed to develop regional GHG emission reduction goals using a multi-sector cap-and-trade program. In May 2010, the Midwestern Greenhouse Gas Reduction Accord Advisory Group finalized recommendations and a model rule for emissions reduction targets and the design of a regional cap-and-trade program to serve as a basis for individual state legislative or regulatory action. However, there is substantial uncertainty as to whether the parties to the Midwestern Greenhouse Gas Reduction Accord intend to continue their efforts to develop or implement such a program, especially in light of the failure to pass a federal cap-and-trade program in the 111th Congress.

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Litigation Developments

Litigation alleging that GHG is a public and private nuisance may affect EME and its subsidiaries whether or not they are named as defendants. The law is unsettled on whether or not this litigation presents questions capable of judicial resolution or political questions that should be resolved by the legislative or executive branches.

In December 2010, the Supreme Court agreed to review a case in which an appellate panel had endorsed the availability of judicial remedies for nuisance allegedly caused by GHG emissions associated with climate change. Oral argument before the Supreme Court is scheduled for April 2011. Currently pending while the Supreme Court considers the matter before it is an appeal before the Ninth Circuit of a federal district order dismissing a case against EME's parent company, Edison International, and other defendants brought by the Alaskan Native Village of Kivalina in which the plaintiffs seek damages of up to $400 million for the cost of relocating the village, which the plaintiffs claim is no longer protected from storms because the Arctic sea ice has melted as the result of climate change. Edison International and the other defendants in the lawsuit recently requested the Ninth Circuit to defer oral argument on the appeal pending the Supreme Court's decision on related issues.

EME cannot predict whether the legal principles emerging from the U.S. Supreme Court or any of the cases in the appellate courts 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, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of the coal plants. The CAA requires the US EPA to establish concentration levels in the ambient air for six criteria pollutants 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.

Federal environmental regulations require states to adopt state implementation plans, known as SIPs, for certain pollutants, which detail how the state will attain the standards that are mandated by the relevant law or regulation. The SIPs must be equal to or more stringent than the federal requirements and must be submitted to the US EPA for approval. 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. If the attainment status of areas changes, states may be required to develop new SIPs that address the changes. Many of EME's facilities are located in areas that have not attained NAAQS for ozone (affected by NO_x emissions from power plants) and fine particulate matter (affected by SO₂ and NO_x emissions from power plants).

As described further below, on December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA, which was subsequently embodied in an Illinois rule called Combined Pollutant Standard or CPS, to reduce mercury, NO_x and SO₂ emissions at the

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Midwest Generation plants. The CPS requires Midwest Generation to achieve air emission 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 the CPS.

Nitrogen Oxide and Sulfur Dioxide

Clean Air Interstate and Transport Rules

The CAIR, issued by the US EPA on March 10, 2005, mandated significant reductions in NO_x and SO₂ emission allowance caps under the CAA in 28 eastern states and the District of Columbia. In 2008, the U.S. Court of Appeals for the D.C. Circuit initially vacated the CAIR, but later remanded the CAIR to the US EPA for the issuance of a revised rule. The CAIR remains in effect until the US EPA finalizes a revised regulation.

In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to reduce power plant emissions of NO_x and SO₂ substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the CAIR.

The US EPA has proposed allocating emission allowances based on historic and projected emissions data from power plants, along with three possible approaches to emission allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading of allowances would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state, an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units. In January 2011, the US EPA proposed two other possible approaches to emission allowance allocation. Both approaches would allocate allowances among units within each state based on each unit's proportional share of the state's total historic heat input, and the second approach would add a constraint based on a unit's reasonably foreseeable maximum emissions under the proposed Transport Rule trading programs.

The Transport Rule is scheduled to be finalized in 2011. The CAIR will remain in place until that time. Depending on the approach adopted, the Transport Rule may provide allowance allocations for the Midwest Generation plants which are adequate for the plants' needs or may require the Midwest Generation plants to procure additional allowances, based on projected emissions using the Illinois CPS allowable emission rates. The Transport Rule may require the installation of additional environmental equipment on Units 1 and 2 at the Homer City plant to reduce SO₂ emissions and, depending on the approach adopted, may also require Homer City to procure a significant number of additional allowances pending such installation or curtail operations if it is unable to do so on acceptable terms. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and

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Results of Operations—Management's Overview—Environmental Developments—Homer City Environmental Issues and Capital Resource Limitations."

Proposed NAAQS for SO₂

In June 2010, the US EPA finalized the primary NAAQS for SO₂ by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is being taken into account in EME's environmental compliance strategy. Revisions to SIPs to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014, with a compliance deadline of August 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 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 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.

The CPS also specifies the control technologies that 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 required Midwest Generation to shut down Unit 6 at the Waukegan Station by December 31, 2007, and Units 1 and 2 at the Will County Station by December 31, 2010, which it has done.

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 $109 million in 2011.

Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO₂ emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time than the use of spray dryer absorber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs. For additional discussion, see "Item 7. Management's

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Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Environmental Developments—Midwest Generation Compliance Plans and Costs."

Pennsylvania

The Homer City plant was subject to the federal CAIR during 2010 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/Hazardous Air Pollutants

Clean Air Mercury Rule/Hazardous Air Pollutant 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. In February 2007, the U.S. Court of Appeals for the D.C. Circuit vacated both the CAMR and the related US EPA decision to remove oil- and coal-fired power plants from the list of sources to be regulated under the provisions of the CAA governing emissions of HAPs.

In accordance with a consent decree entered in April 2010, the US EPA committed to proposing regulations by March 16, 2011 limiting emissions of HAPs from coal- and oil-fired electrical generating units that are major sources of HAPs, and to finalizing such regulations by November 2011. The emissions standards must be designed to achieve the maximum degree of emission reduction that the US EPA determines is achievable for the affected units, taking into account costs and non-air quality environmental and health benefits (also referred to as maximum achievable control technology, or MACT standard). Unlike the CAMR, the US EPA must regulate all of the HAPs emitted by these generating units. Compliance with the MACT standards will be required three years after the effective date of the final regulations. Until the US EPA's regulations are finalized, EME cannot determine whether the actions it is taking to comply with other legal requirements (including the CPS) will be sufficient to address its obligations under the new regulations.

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 will be included in calendar year 2016).

Midwest Generation installed required carbon injection equipment on all operating units in 2009 to achieve the necessary mercury reductions. 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. The

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Illinois EPA granted Midwest Generation a construction permit to install a cold-side electrostatic precipitator on Unit 7 at the Waukegan Station in November 2010.

Pennsylvania

Until Pennsylvania passes new legislation authorizing the adoption of mercury regulations or the US EPA finalizes a revised HAPs regulation that includes mercury limits, the Homer City plant 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 the continued implementation and enforcement of the rule.

Ozone and Particulates

National Ambient Air Quality Standards

In January 2010, the US EPA proposed a revision to the primary and secondary NAAQS for 8-hour ozone that it had finalized in 2008. The 8-hour ozone standard established in 2008 was 0.075 parts per million. In January 2010, the US EPA proposed establishing a primary 8-hour ozone NAAQS between 0.060 and 0.070 parts per million and a distinct secondary standard to protect sensitive vegetation and ecosystems. The US EPA is expected to finalize the revision to the ozone NAAQS by July 2011. It is expected that once the US EPA finalizes the revised ozone NAAQS, it will propose a second Transport Rule that may further affect electric power generating units. The US EPA is also expected to propose revised fine particulate matter NAAQS in 2011, which could result in further emission reduction requirements in future years.

Illinois

The Illinois SIP for compliance with the 1997 8-hour ozone standard was submitted to the US EPA in March 2009. The SIP for fine particulates was submitted to the US EPA in June 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 1997 8-hour ozone standard. However, in March 2009, the PADEP recommended to the US EPA that Indiana County (where the Homer City plant is 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 requirements it will

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have to meet. However, EME expects that its currently installed selective catalytic reduction (SCR) equipment 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 plant 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 2010.

With respect to fine particulates, in November 2009, the US EPA indicated that Indiana County (where the Homer City plant is located) had not attained applicable standards. The PADEP must submit an updated SIP by November 13, 2012. EME cannot predict the potential effects on the Homer City plant of changes to the SIP.

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 SO₂, NO_x and particulate matter emissions, and then to set BART emissions limits for those facilities. Failure to do so would result in the imposition of a Federal Implementation Plan.

Beginning on December 31, 2009, Illinois and Pennsylvania became subject to a two-year deadline after which a Federal Implementation Plan (which has not yet been proposed) will govern related emission issues. Pennsylvania submitted its proposed SIP revisions to the US EPA in December 2010 and Illinois has prepared proposed revisions to its SIP and is expected to submit them to the US EPA in 2011. Illinois proposes that the emission reductions that the Midwest Generation plants will be required to make pursuant to the CPS, discussed above in "—Nitrogen Oxide and Sulfur Dioxide—Illinois," satisfy the BART requirement. Pennsylvania also proposes that the existing particulate matter emission limits on the Homer City plant, as well as the plant's participation in the CAIR, will satisfy the BART requirement in that 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 EPA has pursued a coordinated compliance and enforcement strategy to address NSR 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

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Notice of Violations to a number of power plant owners alleging NSR violations. The US EPA has filed enforcement actions against Homer City and Midwest Generation alleging NSR violations. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."

Water Quality

Clean Water Act

Regulations under the federal Clean Water Act govern critical operating parameters at generating facilities, such as the temperature of effluent discharges and the location, design and construction of cooling water intake structures at generating facilities. The US EPA is rewriting these regulations following a 2009 decision by the U.S. Supreme Court holding that it may consider, but is not required to use, a cost-benefit analysis for this purpose. The Supreme Court set a deadline of March 2011 for draft regulations, which are to be finalized by July 2011. Because there are no defined compliance targets absent a new rule, EME is reviewing a wide range of possible control technologies. A new rule could have a material impact on EME's operations, but EME cannot determine the financial impact until the final compliance criteria have been published.

Illinois

Midwest Generation is a party to an administrative proceeding before the Illinois Pollution Control Board to determine whether more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River, which supply cooling water to Midwest Generation's Fisk, Crawford, Will County, and Joliet Stations, will be implemented. The rule, if implemented, is expected to affect the manner in which those stations use water for station cooling. 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.

Coal Combustion Wastes

US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from hazardous waste requirements. This classification enables beneficial uses of coal combustion residuals, such as for cement production and fill materials. Midwest Generation currently provides a portion of its coal combustion residuals for beneficial uses. Midwest Generation is also examining the impact of current and proposed emission control technologies on ash quality for beneficial use.

In June 2010, the US EPA published proposed regulations relating to coal combustion residuals. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these residuals as special wastes subject to regulation as hazardous wastes, could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these residuals as nonhazardous wastes, would establish minimum technical standards for units that are used for the disposal of coal combustion residuals, but would allow procedural and enforcement mechanisms (such

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as permit requirements) to be exclusively a matter of state law. Many of the proposed technical standards are similar under both proposed options (for example, surface impoundments may need to be retrofitted, depending on which standard is finally adopted), but the second approach would not require the retrofitting of landfills used for the disposal of coal combustion residuals.

Employees

At December 31, 2010, EME and its subsidiaries employed 1,828 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 expires on December 31, 2011. Midwest Generation also has a separate collective bargaining agreement governing retirement, health care, disability and insurance benefits that expires on March 31, 2015; and

•

approximately 192 employees at the Homer City plant covered by a collective bargaining agreement governing wages, benefits and working conditions. This collective bargaining agreement expires 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

Liquidity Risks

EME and its subsidiaries have significant cash requirements and limited sources of capital.

At December 31, 2010, EME had corporate cash and cash equivalents of $615 million and $484 million of available borrowing capacity under its $564 million credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $295 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012.

As of December 31, 2010, EME's consolidated debt was approximately $4.5 billion. EME's subsidiaries had $2.9 billion of long-term, power plant lease obligations that are due over a period ranging up to 24 years. Compliance with current and forthcoming environmental requirements will add to EME's near-term liquidity needs.

EME's and Midwest Generation's below-investment grade credit status may limit their ability to extend or replace credit facilities, including those maturing in 2012, should they choose to do so, and the terms and conditions of any refinancing could be substantially less favorable than those in the current credit facilities, depending on market conditions. In the case of a further downgrade, EME expects that these negative effects would become more pronounced. If EME's credit facilities are not extended or replaced, or if cash flow and other means for

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assuring liquidity are unavailable or insufficient, EME may be unable to complete environmental improvements at its coal plants (which in turn could lead to unit shutdowns) or to provide credit support for contracts for power and fuel related to merchant activities. The terms of EME's and its subsidiaries' debt instruments may restrict EME's ability to sell assets or incur secured indebtedness, and EME's subsidiaries' debt instruments may limit EME's ability to seek additional capital, or restructure or refinance debt to satisfy liquidity needs. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

EME is a holding company and may be limited in its ability to access funds from its subsidiaries to meet its obligations.

EME has no material assets other than the stock of its subsidiaries and depends to a large degree upon dividends and other transfers of funds from its subsidiaries to meet its obligations. EME's subsidiaries are separate and distinct legal entities and have no obligation to provide EME with funds. 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 restrictions contained in 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 obligations. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—EME's Liquidity as a Holding Company" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividend Restrictions in Major Financings.

EME depends upon tax-allocation payments from Edison International to meet its obligations. EME receives these payments only if, and only to the extent that, Edison International is able to utilize tax losses and credits generated by EME.

EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income to be able to utilize EME's consolidated tax losses and credits in the consolidated income tax returns for Edison International and its subsidiaries. The timing of certain tax-allocation payments was delayed in 2010, as a result of the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act, because Edison International was not able to fully utilize EME's consolidated tax losses and credits. Tax-allocation payments to EME may be further delayed until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years as a result of these new tax laws. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Available Liquidity—Bonus Depreciation Impact on EME."

These arrangements are subject to the terms of the tax-allocation and payment agreements among Edison International, Mission Energy Holding Company, EME and other Edison International subsidiaries. The agreements under which EME receives tax-allocation payments may be terminated by the immediate parent company at any time, by notice given before the first day of the first year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year

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beginning prior to the notice. For further discussion, see "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement."

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. 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. 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 and its subsidiaries' 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 and its subsidiaries' 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.

Regulatory and Environmental 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 and frequently changing environmental regulations with respect to, among other things, air quality, water quality and waste disposal, which involve significant and increasing costs and substantial uncertainty. 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. EME may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to off-site waste disposal sites that have been used in its operations.

EME devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. EME believes that it is currently in substantial compliance with environmental regulatory requirements. However, the US EPA has filed enforcement actions against Midwest Generation and Homer City alleging violations of the CAA and other regulations at the Midwest Generation plants and the Homer City plant. For more detail with respect to these matters, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

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The current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The adoption of laws and regulations to implement CO₂ controls could adversely affect coal-fired power plants. Other environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge and cooling water systems, are also generally becoming more stringent. The continued operation of EME's facilities, particularly its coal plants, is expected to require substantial capital expenditures for environmental controls. 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. 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.

All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. Capital expenditures relating to controls contemplated by the CPS are expected to 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. Unit shutdowns could have an adverse effect on EME's business, results of operation and financial condition. 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 operation of generation facilities, and access to transmission. 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. 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. RTOs and ISOs 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. EME's facilities are also subject to mandatory reliability standards promulgated by NERC, compliance with which can increase the facilities' operating costs or capital expenditures.

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This extensive governmental regulation creates significant risks and uncertainties for EME's business. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to EME or its facilities or operations in a manner that may have a detrimental effect on its business or result in significant additional costs.

Market Risks

EME has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices because they operate without long-term power purchase agreements. Wholesale energy prices have substantially declined in recent years.

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. 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 coal plants, EME has concentrated exposure to market conditions and fluctuations in PJM. Prices for power have declined significantly in recent years as a result of increased use of demand response technology, changes in final demand for power during the economic slowdown, and technological developments that have permitted the exploitation of natural gas shale reserves in a way that has resulted in substantial declines in market prices for natural gas which supplies power plants that compete with EME's coal plants.

Market prices of energy, capacity and ancillary services sold from these power plants are influenced by multiple factors beyond EME's control, and thus there is considerable uncertainty whether or when current depressed prices will recover or whether EME can effectively hedge the risks involved on economic terms. 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. 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 cash margin, and liquidity requirements may be greater than EME anticipates or will be able to meet. EME cannot provide assurance that its hedging strategies will successfully mitigate market risks. For more detail with respect to these matters, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk."

EME's financial results can be affected by changes in prices, transportation cost, and supply interruptions related to fuel, sorbents, and other commodities used for power generation and emission controls.

In addition to volatile power prices, EME's business is subject to changes in the cost of fuel, sorbents, and other commodities used for power generation and emission controls, and in the cost of transportation. These costs can be volatile and are influenced by many factors outside EME's control. 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 commodity costs. Operations at the coal plants are

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dependent upon the availability and affordability of coal which is available only from a limited number of suppliers and which, in the case of Midwest Generation, is transported by rail under a long-term transportation contract that will expire in 2011. All of these factors may have an adverse effect on EME's financial condition and results of operations.

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, greater ability to withstand losses, larger staffs or more experience 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.

Operating Risks

EME's development projects 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. EME may be required to spend significant amounts for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses before it can determine whether a project is feasible, economically attractive, or capable of being built. 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 equipment is ready for installation, in which case EME may be required to incur material equipment and/or material costs with no deployment plan at delivery. Projects under development may also be adversely affected by delays in construction or equipment deliveries, commissioning delays or performance issues, and agreements with off-takers may contain damages and termination provisions related to failures to meet specified milestones. Due to competing capital needs, EME's further development of its renewable business will depend upon the availability of third-party equity capital.

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 is a potentially dangerous activity that involves many operating risks, including transmission disruptions and constraints, equipment failures or shortages, and system limitations, degradation and interruption. EME's operations are also subject to risks of human performance and workforce capabilities. There can be no assurance that EME's insurance will be sufficient or effective under all circumstances or protect against all hazards to which EME may be subject or that insurance coverage will continue to be available on terms similar to those presently available, or at all. EME has a number of older

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facilities with potentially higher risks of failure or outage than an average plant, and EME has in the past experienced serial defects in certain models of wind turbines deployed at its wind projects.

Uncertainties in EME's future operations could affect its ability to attract and retain skilled people.

Uncertainties concerning EME's future operations could affect its ability to attract and retain qualified personnel with experience in the energy industry. If EME is unable to successfully attract and retain an appropriately qualified workforce, its results of operations will be negatively affected.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Inapplicable.

ITEM 2. PROPERTIES

EME leases its principal office in Santa Ana, California. The office lease is currently for approximately 85,000 square feet and expires on December 31, 2020. EME also leases office space in Chicago, Illinois; Bolingbrook, Illinois; and Boston, Massachusetts. The Chicago lease is for approximately 41,000 square feet and expires on November 30, 2011. A portion of the Chicago office facility, representing approximately 15,000 square feet, is subleased through November 30, 2011. The Bolingbrook lease is for approximately 20,000 square feet and expires on March 31, 2014. The Boston lease is for approximately 41,000 square feet and expires on September 30, 2017.

The following table shows, as of December 31, 2010, 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

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ITEM 3. LEGAL PROCEEDINGS

For a discussion of the material legal proceedings specifically affecting EME, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

ITEM 4. RESERVED

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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 Mission Energy Holding Company, 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 2010, 2009 and 2008. 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."

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data was derived from EME's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report. EME's international operations, which were sold in 2004, are accounted for as discontinued operations, except the Doga project located in the Republic of Turkey, which EME still owns.

 

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

MANAGEMENT'S OVERVIEW

EME's competitive power generation business primarily consists of the generation and sale into the PJM market of energy and capacity from its approximately 7,000 megawatts of coal-fired power plants. The profitability of these operations is expected to decline significantly in 2011 as a result of lower realized energy prices (largely driven by the expiration of hedge contracts) and higher fuel costs. In addition, the profitability of EME's Midwest Generation plants is expected to be adversely affected in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract). For discussion of energy and fuel price risks, see "Market Risk Exposures—Commodity Price Risk" and "Item 1A. Risk Factors—Market Risks." As a result of the projected decrease in profitability of EME's merchant activities, EME may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.

Highlights of Operating Results

Net income attributable to EME common shareholder is comprised of the following components:

EME's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as net income attributable to EME's shareholder excluding income from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, sale of assets, early debt extinguishment costs, other activities that are no longer continuing, asset impairments, and certain tax, regulatory or legal proceedings.

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EME's 2010 core earnings were lower than 2009 core earnings primarily due to the following pre-tax items:

•

$108 million decreased income from Midwest Generation and Homer City primarily as a result of unrealized losses in 2010 compared to unrealized gains in 2009, and higher plant maintenance costs in 2010, partially offset by higher capacity revenues and a $24 million gain on the sale of bankruptcy claims against Lehman Brothers. Energy and fuel related unrealized losses in 2010 were $33 million compared to unrealized gains of $60 million in 2009. Results in 2010 included the benefit of power hedge contracts entered into during earlier periods at higher prices than current energy prices. For additional information about market conditions, see "Market Risk Exposures."

The decrease was partially offset by the following pre-tax items:

•

$61 million increased energy trading revenues due to congestion and power trading.

•

$28 million decreased interest expense, net of interest income, primarily due to the increase in the capitalization of interest on projects under construction.

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$18 million decreased corporate expenses due primarily to lower renewable energy development expenses.

•

$13 million increased income from distributions received from the March Point and Doga projects.

In addition to the preceding pre-tax items, core earnings in 2010 were lower due to $15 million of increased tax expenses that resulted from the recapture of Section 199 deductions realized in prior years resulting from the carryback of net operating tax losses.

Non-core items for EME included:

•

An earnings benefit of $16 million in 2010 related to the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002 as part of the federal settlement of tax disputes and a revision to the interest on federal disputed tax items.

•

An after-tax earnings charge of $24 million ($40 million pre-tax) recorded in the fourth quarter of 2010 resulting from the write-off of capitalized engineering and other costs for air emissions control technology that is not currently being pursued for use at the Powerton Station. These activities were previously suspended as Midwest Generation pursued testing and evaluation of the use of a dry sorbent injection system using Trona or similar sorbents, which is expected to require lower capital costs. The Illinois EPA recently issued construction permits to authorize installation of a dry sorbent injection system, which Midwest Generation currently expects to use if this project is undertaken. For further discussion, see "—Environmental Developments—Midwest Generation Environmental Compliance Plans and Costs" below.

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

•

Lower wholesale energy prices reduced revenues from EME's coal plants 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

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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.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During 2010, Midwest Generation continued its permitting and planning activities for NO_x and SO₂ controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois EPA to allow the installation of SNCR technology on multiple units to meet the NO_x portion of the CPS. In November 2010 and February 2011, the Illinois EPA issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or its equivalent at the Waukegan generating station's Unit 7 and Units 5 and 6 at the Powerton Station. The permit for Unit 7 at the Waukegan Station also authorizes Midwest Generation to convert the existing electrostatic precipitator to a cold-side design which will improve removal efficiency of particulate matter to satisfy the particulate control requirements of the CPS.

Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO₂ emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time than the use of spray dryer absorber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs.

Based on work to date, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO₂ emissions, and the associated upgrading of existing particulate removal systems, would be approximately $1.2 billion in 2010 dollars. If these projects are undertaken, these expenditures would be incurred through 2018.

Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs

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applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project.

Homer City Environmental Issues and Capital Resource Limitations

Homer City may be required to install additional environmental equipment on Units 1 and 2 to comply with environmental regulations under the Transport Rule. Homer City projects that if SO₂ reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO₂ and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. The installation of environmental compliance equipment will be dependent on lessor decisions regarding the funding of these expenditures. 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. EME has no legal obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made.

US EPA Developments

For information regarding recent developments in environmental regulations, see "Item 1. Business—Environmental Matters and Regulations."

EME's Renewable Program

At December 31, 2010, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW and had four projects totaling 480 MW under construction. EME anticipates that these projects will achieve commercial operation in 2011. In addition to the projects under construction at December 31, 2010, EME expects the 55 MW Pinnacle project in West Virginia will commence construction in 2011 with anticipated commercial operation in 2011. The pace of additional growth in EME's renewable program will be subject to the availability of third-party capital.

EME's Liquidity

At December 31, 2010, EME, as a holding company, had cash and cash equivalents of $427 million to meet liquidity needs as well as $484 million of capacity under its credit facility. EME's subsidiary, EMMT, also had cash and cash equivalents of $168 million at

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December 31, 2010, which can be loaned or distributed to EME subject to applicable corporate and other laws. In addition, at December 31, 2010, Midwest Generation had cash and cash equivalents of $295 million to meet liquidity needs.

Midwest Generation has not yet committed to the completion of environmental compliance activities for all of its plants. Expenditures for NO_x and SO₂ controls through 2013 are estimated at $481 million based on an assumption that Midwest Generation would retrofit all units over the compliance period, which extends to 2018. Depending upon the facilities selected to be retrofitted, the cost of such retrofitting, and the timing of funding requirements beyond the near term, Midwest Generation may utilize operating cash flow, draw on its credit facilities, when available, or seek debt financing to fund capital expenditures.

Capital expenditures to complete renewable energy projects through 2011 are projected to be $279 million at December 31, 2010. EME anticipates that capital investment for renewable energy projects under or pending construction will be funded using a combination of construction and term financings, U.S. Treasury grants and third-party capital. EME has available secured project financing of $48 million. In addition, U.S. Treasury grants of $346 million are anticipated based on estimated eligible construction costs for renewable projects completed in 2010 and scheduled to be completed in 2011.

Edison International's utilization of net operating losses and production tax credits from EME in its consolidated return impacts EME's liquidity. The bonus depreciation extension enacted in the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act is expected to result in delays in EME's receipt of future tax-allocation payments. For more information, see "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement," "Liquidity and Capital Resources—Available Liquidity—Bonus Depreciation Impact on EME" and "Item 1A. Risk Factors—Liquidity Risks."

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RESULTS OF OPERATIONS

Results of Continuing Operations

Overview

EME operates in one line of business, independent power production. 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, 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

The following table shows the adjusted operating income (AOI) of EME's projects:

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

Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

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

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AOI from the Midwest Generation plants decreased $76 million in 2010 compared to 2009, and decreased $348 million in 2009 compared to 2008. Excluding the $40 million pre-tax charge related to the Powerton Station, the 2010 decrease in AOI was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009 related to hedge contracts and an increase in plant maintenance costs, partially offset by higher capacity revenues, a gain from the sale of the bankruptcy claims against Lehman Brothers, and lower average realized fuel costs. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Average realized fuel costs per megawatt-hour were lower in 2010 as compared to 2009 primarily due to lower emission allowance costs partially offset by higher costs for activated carbon, which is used to reduce mercury emissions.

The 2009 decrease in AOI as compared to 2008 was primarily attributable to lower realized energy prices and higher average realized fuel costs, partially offset by higher capacity revenues, unrealized gains in 2009 compared to unrealized losses in 2008 related to hedge contracts, and lower plant operations expense. The 2009 increase in average realized fuel costs was due to higher emission allowance costs to comply with the CAIR annual NO_x emission program that began in 2009 and higher costs for activated carbon to implement new mercury emission controls. The 2009 decline in plant operations expense was due to cost containment efforts and the deferral of plant overhaul activities.

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Included in operating revenues were unrealized gains (losses) of $(6) million, $30 million and $(6) million in 2010, 2009 and 2008, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily due to economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of income. In addition, $10 million and $14 million were reversed from accumulated other comprehensive income and recognized in 2010 and 2009, respectively, related to the power contracts with Lehman Brothers. Unrealized losses in 2008 included a $24 million write-down of power contracts with Lehman Brothers for 2009 and 2010 forecasted 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 the Northern Illinois Hub (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.

Included in fuel costs were unrealized gains (losses) of $(7) million and $15 million for the year ended December 31, 2010 and 2009, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.

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Homer City

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

On February 10, 2011, a steam pipe ruptured at Unit 1 of the Homer City plant, taking the unit off line. As a precautionary measure, Homer City has taken Unit 2 (which has the same design) off line in order to further evaluate the equipment and perform any necessary corrective work. Work has commenced to inspect the piping that failed and planning activities to install replacement piping on both units are underway. Homer City is in the process of modifying its scheduled maintenance plans to incorporate this outage. It is expected that both units will return to service during the second quarter of 2011.

AOI from the Homer City plant decreased $72 million in 2010 compared to 2009 and decreased $16 million in 2009 compared to 2008. The 2010 decrease in AOI was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009 related to

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hedge contracts, higher coal costs, lower generation, and higher plant operations costs related to scheduled plant outages, partially offset by an increase in capacity revenues. The Homer City plant experienced increased forced outages in 2010 compared to 2009 due to deratings to comply with opacity restrictions and unscheduled outages. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Coal costs increased due to higher coal prices and changes in the mix of ready-to-burn coal and raw coal consumed.

The 2009 decrease in AOI as compared to 2008 was primarily attributable to lower realized energy prices, partially offset by an increase in capacity revenues, lower plant operations expense and lower coal costs. The decline in plant operations expense was attributable to cost containment efforts and the deferral of plant overhaul activities.

Included in operating revenues were unrealized gains (losses) from hedge activities of $(20) million, $15 million and $21 million in 2010, 2009 and 2008, 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 plant is delivered into the transmission system).

Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions

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 revenues less unrealized gains (losses) and other non-energy related revenues by (ii) generation as shown in the table below. Revenues related to capacity sales are excluded from the calculation of average realized energy price.

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