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

Table of Contents

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



FORM 10-K

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

For the fiscal year ended December 31, 2010

Commission File Number 333-68630



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

Delaware
(State or other jurisdiction of incorporation
or organization)
  95-4031807
(I.R.S. Employer Identification No.)

3 MacArthur Place, Suite 100
Santa Ana, California
(Address of principal executive offices)

 

92707
(Zip Code)

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

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

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

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

    Common Stock, par value $0.01 per share     
    (Title of Class)
   



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

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

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

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

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

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

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

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

        Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 30, 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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TABLE OF CONTENTS

  FORWARD-LOOKING STATEMENTS   1
 
GLOSSARY

 

3

PART I

 

5
 
ITEM 1.

 

BUSINESS

 

5
 
Overview

 

5
    Location and Available Information   5
 
Electric Power Industry

 

5
 
Wholesale Markets

 

6
 
Competition

 

6
 
Operating Segments

 

7
 
Overview of Facilities

 

8
 
Seasonality

 

9
 
Merchant Power Plants

 

10
    Midwest Generation Plants   10
      Power Sales   10
      Fuel Supply   11
    Homer City Plant   11
      Power Sales   11
      Fuel Supply   12
    Emission Allowances for the Coal Plants   12
    Merchant Wind Projects   12
 
Contracted Power Plants—Domestic

 

13
    Natural Gas   13
      Big 4 Projects   13
        Kern River Project   13
        Midway-Sunset Project   13
        Sycamore Project   13
        Watson Project   14
      Westside Projects   14
      Sunrise Project   14
    Renewable Energy   14
      Wind   14
      Biomass   15
        Huntington Waste-to-Energy Project   15
    Coal   15
      American Bituminous Project   15
 
Contracted Power Plants—International

 

16
    Doga Project   16
 
Renewable Development Activities

 

16
 
Asset Management and Trading Activities

 

16
 
Significant Customers

 

17
 
Insurance

 

17

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Discontinued Operations

 

17
 
Regulatory Matters

 

17
    General   17
    Federal Power Act   18
    Reliability Standards   18
    Transmission of Wholesale Power   18
    Dodd-Frank Act   19
 
Environmental Matters and Regulations

 

19
    Climate Change   19
      Federal Legislative/Regulatory Developments   20
      Regional Initiatives and State Legislation   20
      Litigation Developments   22
    Air Quality   22
      Nitrogen Oxide and Sulfur Dioxide   23
        Clean Air Interstate and Transport Rules   23
        Proposed NAAQS for SO2   24
        Illinois   24
        Pennsylvania   25
      Mercury/Hazardous Air Pollutants   25
        Clean Air Mercury Rule/Hazardous Air Pollutant Regulations   25
        Illinois   25
        Pennsylvania   26
      Ozone and Particulates   26
        National Ambient Air Quality Standards   26
        Illinois   26
        Pennsylvania   26
      Regional Haze   27
      New Source Review Requirements   27
    Water Quality   28
      Clean Water Act   28
      Illinois   28
    Coal Combustion Wastes   28
 
Employees

 

29
 
EME's Relationship with Certain Affiliated Companies

 

29
 
ITEM 1A.

 

RISK FACTORS

 

29
 
Liquidity Risks

 

29
 
Regulatory and Environmental Risks

 

31
 
Market Risks

 

33
 
Operating Risks

 

34
 
ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

 

35
 
ITEM 2.

 

PROPERTIES

 

35
 
Description of Properties

 

35
 
ITEM 3.

 

LEGAL PROCEEDINGS

 

36
 
ITEM 4.

 

RESERVED

 

36

PART II

 

37

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ITEM 5.

 

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

 

37
 
ITEM 6.

 

SELECTED FINANCIAL DATA

 

38
 
ITEM 7.

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

39
 
MANAGEMENT'S OVERVIEW

 

39
 
Highlights of Operating Results

 

39
 
Environmental Developments

 

41
    Midwest Generation Environmental Compliance Plans and Costs   41
    Homer City Environmental Issues and Capital Resource Limitations   42
    US EPA Developments   42
 
EME's Renewable Program

 

42
 
EME's Liquidity

 

42
 
RESULTS OF OPERATIONS

 

44
 
Results of Continuing Operations

 

44
    Overview   44
    Adjusted Operating Income from Consolidated Operations   45
      Midwest Generation Plants   45
      Homer City   48
      Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions   49
        Average Realized Energy Price   49
        Average Realized Fuel Costs   50
        Statistical Definitions   51
      Renewable Energy Projects   52
      Energy Trading   53
    Adjusted Operating Income from Unconsolidated Affiliates   53
    Other Operating Income (Expense)   54
    Corporate Administrative and General Expenses   54
    Interest Income (Expense)   54
    Income Taxes   54
 
Results of Discontinued Operations

 

55
 
Related-Party Transactions

 

55
 
New Accounting Guidance

 

55
 
LIQUIDITY AND CAPITAL RESOURCES

 

56
 
Available Liquidity

 

56
    Bonus Depreciation Impact on EME   57
 
Capital Investment Plan

 

57
    Environmental Capital Expenditures   57
    Non-Environmental Capital Expenditures   58
    Future Projects   58
 
EME's Historical Consolidated Cash Flow

 

58
    Condensed Consolidated Statement of Cash Flows   59
      Consolidated Cash Flows from Operating Activities   59
      Consolidated Cash Flows from Financing Activities   59

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      Consolidated Cash Flows from Investing Activities   59
 
Credit Ratings

 

60
    Overview   60
    Credit Rating of EMMT   60
 
Margin, Collateral Deposits and Other Credit Support for Energy Contracts

 

61
 
EME's Liquidity as a Holding Company

 

61
    Intercompany Tax-Allocation Agreement   61
    EME's Credit Facility Financial Ratios   62
 
Dividend Restrictions in Major Financings

 

64
    General   64
    Key Ratios of EME's Principal Subsidiaries Affecting Dividends   64
    Midwest Generation Financing Restrictions on Distributions   65
    Homer City Sale-Leaseback Restrictions on Distributions   65
    EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries   65
    EME's Senior Notes and Guaranty of Powerton-Joliet Leases   65
 
Contractual Obligations, Commercial Commitments and Contingencies

 

67
    Contractual Obligations   67
    Commercial Commitments   67
      Standby Letters of Credit   67
    Contingencies   68
 
Off-Balance Sheet Transactions

 

68
    Introduction   68
    Investments Accounted for under the Equity Method   68
    Sale-Leaseback Transactions   68
    EME's Obligations to Midwest Generation   70
 
MARKET RISK EXPOSURES

 

71
 
Introduction

 

71
 
Derivative Instruments

 

71
    Unrealized Gains and Losses   71
    Fair Value Disclosures   71
 
Commodity Price Risk

 

72
    Introduction   72
    Energy Price Risk Affecting Sales from the Coal Plants   72
    Capacity Price Risk   74
    Basis Risk   76
    Coal and Transportation Price Risk   77
    Emission Allowances Price Risk   78
 
Credit Risk

 

78
 
Interest Rate Risk

 

79
 
CRITICAL ACCOUNTING ESTIMATES AND POLICIES

 

80
 
Introduction

 

80
 
Derivatives

 

80
 
Impairment of Long-Lived Assets

 

81
    Application to Merchant Coal-Fired Power Plants   82
 
Accounting for Contingencies, Guarantees and Indemnities

 

83

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Income Taxes

 

84
 
ITEM 7A.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

85
 
ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

86
 
ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

86
 
ITEM 9A.

 

CONTROLS AND PROCEDURES

 

86
 
Disclosure Controls and Procedures

 

86
 
Management's Report on Internal Control over Financial Reporting

 

86
 
Internal Control Over Financial Reporting

 

86
 
ITEM 9B.

 

OTHER INFORMATION

 

86
  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM   87
  CONSOLIDATED STATEMENTS OF INCOME   88
  CONSOLIDATED BALANCE SHEETS   89
  CONSOLIDATED STATEMENTS OF TOTAL EQUITY   91
  CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME   92
  CONSOLIDATED STATEMENTS OF CASH FLOWS   93
  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS   94
 
Note 1. Summary of Significant Accounting Policies

 

94
    Basis of Presentation   94
    Cash Equivalents   94
    Restricted Cash and Deposits   94
    Inventory   95
    Property, Plant and Equipment   95
    Impairment of Long-Lived Assets   96
    Project Development Costs   96
    Intangible Assets   97
    Leases   98
      Leased Property   98
      Power Purchase Agreements   98
    Deferred Financing Costs   98
    Revenue Recognition   98
    Power Purchase Agreements   99
    Derivative Instruments and Hedging Activities   99
    Stock-Based Compensation   100
    Income Taxes   100
    New Accounting Guidance   101
      Accounting Guidance Adopted in 2010   101
        Consolidation—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities   101
        Fair Value Measurements and Disclosures   102
      Accounting Guidance Not Yet Adopted   102
        Revenue—Multiple-Deliverables   102
 
Note 2. Property, Plant and Equipment

 

102
    Asset Retirement Obligations   103
 
Note 3. Variable Interest Entities

 

104
    Variable Interest Entities   104

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      Description of Use of Variable Interest Entities   104
      Categories of Variable Interest Entities   105
        Projects or Entities that are Consolidated   105
        Projects that are not Consolidated   106
 
Note 4. Fair Value Measurements

 

109
    Valuation Techniques used to Determine Fair Value   111
      Level 1   111
      Level 2   111
      Level 3   111
    Long-term Debt   112
 
Note 5. Debt and Credit Agreements

 

113
    Long-Term Debt   113
      Liens and Security Interests   113
      Senior Notes   114
      Credit Agreements   114
      Viento Funding II Wind Financing   115
      American Bituminous Project   116
      Big Sky Turbine Financing   116
    2010 Project Financings   116
      High Lonesome   116
      Laredo Ridge   117
      Cedro Hill   117
      Other Letters of Credit Facilities   117
    Standby Letters of Credit   118
 
Note 6. Derivative Instruments and Hedging Activities

 

118
    Notional Volumes of Derivative Instruments   119
    Fair Value of Derivative Instruments   121
    Income Statement Impact of Derivative Instruments   121
    Energy Trading Derivative Instruments   123
    Contingent Features   123
    Margin and Collateral Deposits   123
    Commodity Price Risk Management   124
    Interest Rate Risk Management   124
    Credit Risk   124
 
Note 7. Income Taxes

 

126
    Current and Deferred Taxes   126
    Effective Tax Rate   127
    Accounting for Uncertainty in Income Taxes   128
      Unrecognized Tax Benefits   128
      Accrued Interest and Penalties   128
      Settlement of Tax Dispute   128
 
Note 8. Compensation and Benefit Plans

 

129
    Employee Savings Plan   129
    Pension Plans and Postretirement Benefits Other than Pensions   129
      Pension Plans   129
      Postretirement Benefits Other Than Pensions   132
    Discount Rate   134
    Plan Assets   134

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      Description of Pension and Postretirement Benefits Other Than Pensions Investment Strategies   134
      Determination of the Expected Long-Term Rate of Return on Assets   135
      Capital Markets Return Forecasts   135
      Fair Value of Plan Assets   135
        Pension Plan   136
    Stock-Based Compensation   138
      Stock Options   138
    Performance Shares   140
      Restricted Stock Units   141
    Supplemental Data on Stock-Based Compensation   143
 
Note 9. Commitments and Contingencies

 

143
    Power Plant and Other Lease Commitments   143
      Sale-Leaseback Transactions   144
    Other Commitments   145
      Fuel Supply Contracts   145
      Coal Transportation Agreements   145
      Gas Transportation Agreements   145
      Capital Expenditures   146
      Turbine Commitments   146
      Other Contractual Obligations   146
    Guarantees and Indemnities   146
      Environmental Indemnities Related to the Midwest Generation Plants   146
      Environmental Indemnity Related to the Homer City Plant   147
      Indemnities Provided under Asset Sale and Sale-Leaseback Agreements   148
    Contingencies   148
      Environmental Remediation   148
      Midwest Generation New Source Review Lawsuit   149
      Homer City New Source Review Lawsuit   150
    Insurance   150
 
Note 10. Environmental Developments

 

151
    Midwest Generation Environmental Compliance Plans and Costs   151
    Homer City Environmental Issues and Capital Resource Limitations   152
    Greenhouse Gas Regulation   152
    Transport Rule   153
    Hazardous Air Pollutant Regulations   153
    Water Quality   154
      Clean Water Act   154
    Coal Combustion Wastes   154
 
Note 11. Accumulated Other Comprehensive Income

 

154
 
Note 12. Supplemental Cash Flows Information

 

155
 
Note 13. Restructuring Costs

 

155
 
Note 14. Divestitures

 

156
    Discontinued Operations   156
 
Note 15. Related-Party Transactions

 

156
 
Note 16. Quarterly Financial Data (unaudited)

 

158

PART III

 

159

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ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

159
 
ITEM 11.

 

EXECUTIVE COMPENSATION

 

159
 
ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

159
 
ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

159
 
ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

159

PART IV

 

161
 
ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

161
 
SIGNATURES

 

167

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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:

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

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

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

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

the cost and availability of emission credits or allowances;

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

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

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

governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including the market structure rules applicable to each market and price mitigation strategies adopted by independent system operators and regional transmission organizations;

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;

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

weather conditions, natural disasters and other unforeseen events;

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

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

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

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

general political, economic and business conditions; and

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

Certain of the risk factors listed above are discussed in more detail in "Item 1A. Risk Factors" and in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures." Additional information about the risk factors listed above and other risks and uncertainties is contained throughout this annual report. Readers are urged to read this entire annual report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

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GLOSSARY

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

 
2010 Tax Relief Act   Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AOI   adjusted operating income (loss)
ARO(s)   asset retirement obligation(s)
BACT   best available control technology
BART   best available retrofit technology
bcf   billion cubic feet
Big 4   Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu   British thermal units
CAA   Clean Air Act
CAIR   Clean Air Interstate Rule
CAMR   Clean Air Mercury Rule
CARB   California Air Resources Board
CO2   carbon dioxide
coal plants   Midwest Generation coal plants and Homer City electric generating station
Commonwealth Edison   Commonwealth Edison Company
CPS   Combined Pollutant Standard
CPUC   California Public Utilities Commission
EIA   Energy Information Administration
EME   Edison Mission Energy
EMMT   Edison Mission Marketing & Trading, Inc.
EWG(s)   exempt wholesale generator(s)
FASB   Financial Accounting Standards Board
FERC   Federal Energy Regulatory Commission
FPA   Federal Power Act
GAAP   United States generally accepted accounting principles
GHG   greenhouse gas
GWh   gigawatt-hours
HAP(s)   hazardous air pollutant(s)
Homer City   EME Homer City Generation L.P.
Illinois EPA   Illinois Environmental Protection Agency
 

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ISO(s)   independent system operator(s)
Lehman Brothers   Lehman Brothers Commodity Services, Inc. (filed for bankruptcy on October 3, 2008) and Lehman Brothers Holdings, Inc. (filed for bankruptcy on September 15, 2008)
LIBOR   London Interbank Offered Rate
Midwest Generation   Midwest Generation, LLC
MMBtu   million British thermal units
Moody's   Moody's Investors Service, Inc.
MW   megawatts
MWh   megawatt-hours
NAAQS   National Ambient Air Quality Standard(s)
NAPP   Northern Appalachian
NERC   North American Electric Reliability Corporation
NOX   nitrogen oxide
NSR   New Source Review
NYISO   New York Independent System Operator
PADEP   Pennsylvania Department of Environmental Protection
PG&E   Pacific Gas & Electric Company
PJM   PJM Interconnection, LLC
PRB   Powder River Basin
PSD   Prevention of Significant Deterioration
RPM   Reliability Pricing Model
RTO(s)   regional transmission organization(s)
S&P   Standard & Poor's Ratings Services
SCE   Southern California Edison Company
SIP(s)   state implementation plan(s)
SNCR   selective non-catalytic reduction
SO2   sulfur dioxide
Transport Rule   Clean Air Transport Rule
US EPA   United States Environmental Protection Agency
U.S. Treasury grants   Cash grants, under the American Recovery and Reinvestment Act of 2009
 

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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:

Power Plants
  Location
  Primary
Electric
Purchaser2

  Fuel Type
  Ownership
Interest

  Net Physical
Capacity
(in MW)

  EME's
Capacity
Pro Rata Share
(in MW)

 
   

MERCHANT POWER PLANTS

 
 

Midwest Generation plants1

  Illinois   PJM   coal     100 %   5,172     5,172  
 

Midwest Generation plants1

  Illinois   PJM   oil     100 %   305     305  
 

Homer City plant1

  Pennsylvania   PJM   coal     100 %   1,884     1,884  

Merchant Wind

                               
 

Goat Wind

  Texas   ERCOT   wind     99.9% 3   150     150  
 

Lookout

  Pennsylvania   PJM   wind     100 %   38     38  


CONTRACTED POWER PLANTS – Domestic


 

Natural Gas

                               
 

Big 4 Projects

                               
   

Kern River1

  California   SCE   natural gas     50 %   300     150  
   

Midway-Sunset1

  California   PG&E   natural gas     50 %   225     113  
   

Sycamore1

  California   SCE   natural gas     50 %   300     150  
   

Watson

  California   SCE   natural gas     49 %   385     189  
 

Westside Projects1

                               
   

Coalinga

  California   PG&E   natural gas     50 %   38     19  
   

Mid-Set

  California   PG&E   natural gas     50 %   38     19  
   

Salinas River

  California   PG&E   natural gas     50 %   38     19  
   

Sargent Canyon

  California   PG&E   natural gas     50 %   38     19  
 

Sunrise1

  California   CDWR   natural gas     50 %   572     286  

Renewable Energy

                               
 

Buffalo Bear

  Oklahoma   WFEC   wind     100 %   19     19  
 

Cedro Hill

  Texas   CSA   wind     100 %   150     150  
 

Crosswinds

  Iowa   CBPC   wind     99% 3   21     21  
 

Elkhorn Ridge

  Nebraska   NPPD   wind     67 %   80     53  
 

Forward

  Pennsylvania   CECG   wind     100 %   29     29  
 

Hardin

  Iowa   IPLC   wind     99% 3   15     15  
 

High Lonesome

  New Mexico   APSC   wind     100 %   100     100  
 

Jeffers

  Minnesota   NSPC   wind     99.9% 3   50     50  
 

Minnesota Wind projects4

  Minnesota   NSPC/IPLC   wind     75-99% 3   83     75  
 

Mountain Wind I

  Wyoming   PC   wind     100 %   61     61  
 

Mountain Wind II

  Wyoming   PC   wind     100 %   80     80  
 

Odin

  Minnesota   MRES   wind     99.9% 3   20     20  
 

San Juan Mesa

  New Mexico   SPS   wind     75 %   120     90  
 

Sleeping Bear

  Oklahoma   PSCO   wind     100 %   95     95  
 

Spanish Fork

  Utah   PC   wind     100 %   19     19  
 

Storm Lake1

  Iowa   MEC   wind     100 %   108     108  
 

Wildorado

  Texas   SPS   wind     99.9% 3   161     161  
 

Huntington Waste-to-
Energy

  New York   LIPA   biomass     38 %   25     9  

Coal

                               
 

American Bituminous1

  West Virginia   MPC   waste coal     50 %   80     40  

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Power Plants
  Location
  Primary
Electric
Purchaser2

  Fuel Type
  Ownership
Interest

  Net Physical
Capacity
(in MW)

  EME's
Capacity
Pro Rata Share
(in MW)

 
   

CONTRACTED POWER PLANTS – International

                   
 

Doga1

  Republic of Turkey   TEDAS   natural gas     80 %   180     144  
                         

Total

                      10,979     9,852  
   
1
Plant is operated under contract by an EME operations and maintenance subsidiary or the plant is operated or managed directly by an EME subsidiary.

2
Electric purchaser abbreviations are as follows:

  APSC   Arizona Public Service Company   NPPD   Nebraska Public Power District
  CBPC   Corn Belt Power Cooperative   NSPC   Northern States Power Company
  CDWR   California Department of Water Resources   PC   PacifiCorp
  CECG   Constellation Energy Commodities Group, Inc.   PG&E   Pacific Gas & Electric Company
  CSA   City of San Antonio   PJM   PJM Interconnection, LLC
  ERCOT   Electric Reliability Council of Texas   PSCO   Public Service Company of Oklahoma
  IPLC   Interstate Power and Light Company   PSE   Puget Sound Energy, Inc.
  LIPA   Long Island Power Authority   SCE   Southern California Edison Company
  MEC   Mid-American Energy Company   SPS   Southwestern Public Service
  MPC   Monongahela Power Company   TEDAS   Türkiye Elektrik Dagitim Anonim Sirketi
  MRES   Missouri River Energy Services   WFEC   Western Farmers Electric Cooperative
3
Represents EME's current ownership interest. If the project achieves a specified rate of return, EME's interest will decrease.

4
Comprised of seven individual wind projects.

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

Fuel Source
  Percentage of EME's
Generation Capacity

 
   

Coal

    72 %

Natural gas

    14 %

Renewable energy

    14 %
   

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:

Operating Plant or Site
  Location
  Leased/
Owned

  Fuel
  Megawatts
 
   

Electric Generating Facilities

                   
 

Crawford Station

  Chicago, Illinois   owned   coal     532  
 

Fisk Station

  Chicago, Illinois   owned   coal     326  
 

Joliet Unit 6

  Joliet, Illinois   owned   coal     290  
 

Joliet Units 7 and 8

  Joliet, Illinois   leased   coal     1,036  
 

Powerton Station

  Pekin, Illinois   leased   coal     1,538  
 

Waukegan Station

  Waukegan, Illinois   owned   coal     689 1
 

Will County Station

  Romeoville, Illinois   owned   coal     761 2

Peaking Units

                   
 

Fisk

  Chicago, Illinois   owned   oil     197  
 

Waukegan

  Waukegan, Illinois   owned   oil     108  
                   

Total

                5,477  
   

 

Non-Operating Plant or Site
  Location
 
Collins Station3   Grundy County, Illinois
Crawford peaker4   Chicago, Illinois
Joliet peaker5   Joliet, Illinois
Calumet peaker5   Chicago, Illinois
Electric Junction peaker5   Aurora, Illinois
Lombard peaker5   Lombard, Illinois
Sabrooke peaker5   Rockford, Illinois
 
1
The Waukegan Station is comprised of Units 7 and 8. Midwest Generation shut down permanently Waukegan Station Unit 6 (100 MW) on December 21, 2007.

2
The Will County Station is comprised of Units 3 and 4. Midwest Generation shut down permanently Will County Station Units 1 and 2, totaling 299 MW of capacity, on December 29, 2010 in accordance with the CPS. For further discussion, see "Item 1. Business—Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide—Illinois."

3
All Collins Station units ceased operations and were decommissioned on or before December 31, 2004.

4
Peaking units ceased operations as of April 21, 2005.

5
Peaking units ceased operations as of December 31, 2004.


Power Sales

Energy and capacity from the Midwest Generation plants are sold under terms, including price, duration and quantity, arranged by EMMT, an EME subsidiary engaged in 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 NOx 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:

Merchant Wind Project
  Location
  Primary
Electric
Purchaser

  Commercial
Operations Date

  Ownership
Interest

  Net Physical
Capacity
(in MW)

  EME's Capacity
Pro Rata Share
(in MW)

 
   

Goat Wind

  Texas   ERCOT1   April 2008/June 2009     99.9% 3   150     150  

Lookout

  Pennsylvania   PJM2   October 2008     100 %   38     38  
                         

Total

                      188     188  
   
1
Electric Reliability Council of Texas


2
PJM Interconnection, LLC

3
Represents EME's current ownership interest. If the project achieves a specified rate of return, EME's interest will decrease.

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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.

Project
  Location
  Plant Description
  Primary Electric Purchaser
  Ownership
Interest

  Net
Physical
Capacity
(in MW)

  EME's
Capacity Pro
Rata Share
(in MW)

 
   

Kern River

  Bakersfield, CA  

Natural gas-fired cogeneration

 

Southern California Edison

    50 %   300     150  

Midway-Sunset

  Taft, CA  

Natural gas-fired cogeneration

 

Pacific Gas & Electric Company

    50 %   225     113  

Sycamore

  Bakersfield, CA  

Natural gas-fired cogeneration

 

Southern California Edison

    50 %   300     150  

Watson

  Carson, CA  

Natural gas-fired cogeneration

 

Southern California Edison

    49 %   385     189  
   


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.

Contracted Wind Plants
  Power Purchase
Agreement
Expiration Year

  Production Tax Credit Expiration Date
  Commercial Operation
or Acquisition Date

 
   

Buffalo Bear

  2033   December 2018     December 2008  

Cedro Hill

  2030   Qualified for U.S. Treasury grant     November 2010  

Crosswinds1

  20224   June 2017     June 2007  

Elkhorn Ridge

  2029   December 2018     March 2009  

Forward

  2017   April 2018     April 2008  

Hardin2

  2027   May 2017     May 2007  

High Lonesome

  2039   Qualified for U.S. Treasury grant     July 2009  

Jeffers

  2028   October 2018     October 2008  

Minnesota3

  2021-20345   June 2009-July 2016     April 2006  

Mountain Wind I

  2033   July 2018     July 2008  

Mountain Wind II

  2033   September 2018     September 2008  

Odin

  2028   June 2018     May 2008  

San Juan Mesa

  2025   December 2015     December 2005  

Sleeping Bear

  2032   October 2017     September 2007  

Spanish Fork

  2028   July 2018     July 2008  

Storm Lake

  2019   June 2009     May 1999  

Wildorado

  2027   April 2017     April 2007  
   
1
Ten separate limited liability companies collectively form the wind farm.

2
Seven separate limited liability companies collectively form the wind farm.

3
Thirty-seven separate limited liability companies each own a small wind-powered electric generation facility.

4
Agreement includes a five-year renewal option.

5
Each of the Minnesota Wind projects sells electricity under a power purchase agreement with Northern States Power Company that expires between 2025 and 2034, or with Interstate Power and Light Company that expires in 2021.


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:

Wind Project
  Location
  Primary Electric Purchaser
  Ownership
Interest

  EME's Capacity
Pro Rata Share
(in MW)

 
   

Big Sky

  Illinois  

Merchant1

    100 %   240  

Taloga

  Oklahoma  

Oklahoma Gas and Electric Company2

    100 %   130  

Laredo Ridge

  Nebraska  

Nebraska Public Power District2

    100 %   80  

CWN

  Minnesota  

Northern States Power Company2

    99 %   30  
                     

Total

                  480  
   
1
Plans to sell renewable energy credits into the PJM market as merchant generator or to third-party customers under power sales contracts. Sold 48 MW of capacity into a forward-year RPM auction.

2
Twenty-year power purchase agreement.

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:

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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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 NOx emissions from power plants) and fine particulate matter (affected by SO2 and NOx 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, NOx and SO2 emissions at the

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Midwest Generation plants. The CPS requires Midwest Generation to achieve air emission reductions for NOx 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, NOx 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 NOx 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 NOx 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, NOx 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 NOx and SO2 under the CPS are as described below:

NOx Emissions—Beginning in calendar year 2012 and continuing in each calendar year thereafter, Midwest Generation must comply with an annual and seasonal NOx 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 NOx 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 NOx 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 NOx 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 NOx, 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 NOx 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, NOx 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

Plant
  Location
  Interest
in Land

  Plant Description
 
Homer City plant   Pittsburgh, Pennsylvania   Owned 1 Coal-fired generation facility
Midwest Generation plants   Northeast Illinois   Owned 2 Coal, oil-fired generation facilities
Elkhorn Ridge   Bloomfield, Nebraska   Leased   Wind-powered electric generation facility
Kern River   Bakersfield, California   Leased   Natural gas-turbine cogeneration facility
Midway-Sunset   Taft, California   Leased   Natural gas-turbine cogeneration facility
San Juan Mesa   Elida, New Mexico   Leased   Wind-powered electric generation facility
Sunrise   Fellows, California   Leased   Combined cycle generation facility
Sycamore   Bakersfield, California   Leased   Natural gas-turbine cogeneration facility
Watson   Carson, California   Leased   Natural gas-turbine cogeneration facility
 
1
The Homer City site is subject to a ground lease pursuant to a sale-leaseback transaction.

2
The sites of Midwest Generation's Powerton and Joliet plants are subject to a ground lease pursuant to a sale-leaseback transaction.

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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.

   
INCOME STATEMENT DATA
(in millions)
 
 
  Years Ended December 31,  
 
  2010
  2009
  2008
  2007
  2006
 
   

Operating Revenues

  $ 2,423   $ 2,377   $ 2,811   $ 2,580   $ 2,239  

Operating Expenses

                               
 

Fuel, plant operations and plant operating leases

    1,641     1,552     1,544     1,444     1,332  
 

Depreciation and amortization

    248     236     194     162     144  
 

Asset write-downs, gain on buyout of contract, loss on termination of contract, and other charges and credits, net

    45     4     14     6      
 

Administrative and general

    182     196     207     204     140  
       

    2,116     1,988     1,959     1,816     1,616  
       

Operating Income

    307     389     852     764     623  

Equity in income from unconsolidated affiliates

    104     100     122     200     186  

Interest and other income

    30     24     48     103     120  

Interest expense, net of capitalized interest

    (263 )   (296 )   (279 )   (273 )   (279 )

Loss on early extinguishment of debt

                (160 )   (146 )
       

Income from continuing operations before income taxes

    178     217     743     634     504  

Provision for income taxes

    19     16     243     219     189  
       

Income from continuing operations

    159     201     500     415     315  

Income (loss) from operations of discontinued subsidiaries, net of tax

    4     (7 )   1     (2 )   98  
       

Net Income

    163     194     501     413     413  
       

Net Loss Attributable to Noncontrolling Interests

    1     3         1     1  
       

Net Income Attributable to EME Common Shareholder

  $ 164   $ 197   $ 501   $ 414   $ 414  
   

 

   
BALANCE SHEET DATA
(in millions)
 
 
  As of December 31,  
 
  2010
  2009
  2008
  2007
  2006
 
   

Current assets

  $ 1,859   $ 1,862   $ 2,661   $ 1,734   $ 2,594  

Total assets

    9,321     8,633     9,080     7,272     7,235  

Current liabilities

    524     549     635     454     631  

Long-term debt net of current maturities

    4,342     3,929     4,638     3,806     3,035  

Total EME common shareholder's equity

    2,817     2,761     2,684     1,923     2,582  
   

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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:

 
  Years Ended
December 31,
   
   
 
 
   
  Year Ended
December 31,
2008

 
(in millions)
  2010
  2009
  Change
 
   

Net income attributable to EME common shareholder

  $ 164   $ 197   $ (33 ) $ 501  
       

Non-Core Items

                         
 

Write-off of capitalized costs

    (24 )       (24 )    
 

Income (loss) from discontinued operations

    4     (7 )   11     1  
 

Settlement of tax disputes

    16     6     10      
       
 

Total non-core items

    (4 )   (1 )   (3 )   1  
       

Core Earnings

  $ 168   $ 198   $ (30 ) $ 500  
   

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.

$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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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 NOx 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 NOx 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 NOx 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 NOx 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:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Midwest Generation plants

  $ 264   $ 340   $ 688  

Homer City plant

    114     186     202  

Renewable energy projects

    51     53     60  

Energy trading

    110     49     164  

Big 4 projects

    52     46     87  

Sunrise

    33     37     24  

Doga

    15     8     8  

March Point1

    17     11      

Westside projects

    1     4     9  

Other projects

    9     9     13  

Other operating income (expense)

            (31 )
       

    666     743     1,224  

Corporate administrative and general

    (145 )   (163 )   (172 )

Corporate depreciation and amortization

    (19 )   (15 )   (12 )
       

AOI2

  $ 502   $ 565   $ 1,040  
   
1
Sold in 2010.

2
AOI is equal to operating income under GAAP, plus equity in income of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

AOI

  $ 502   $ 565   $ 1,040  

Less:

                   
 

Equity in income of unconsolidated affiliates

    104     100     122  
 

Dividend income from projects

    19     12     10  
 

Production tax credits

    62     56     44  
 

Other income, net

    9     5     12  
 

Net loss attributable to noncontrolling interests

    1     3      
       

Operating Income

  $ 307   $ 389   $ 852  
   


Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

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

 
  Years Ended December 31  
(in millions)
  2010
  2009
  2008
 
   

Operating Revenues

  $ 1,479   $ 1,487   $ 1,778  

Operating Expenses

                   
 

Fuel1

    519     547     482  
 

Plant operations

    448     396     431  
 

Plant operating leases

    75     75     75  
 

Depreciation and amortization

    114     109     106  
 

Asset write-downs and (gain) on buyout of contract

    42     2     (16 )
 

Administrative and general

    22     21     22  
       
 

Total operating expenses

    1,220     1,150     1,100  
       

Operating Income

    259     337     678  
       

Other Income

    5     3     10  
       

AOI

  $ 264   $ 340   $ 688  
   

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  Years Ended December 31  
(in millions)
  2010
  2009
  2008
 
   

Statistics2

                   
 

Generation (in GWh)

                   
   

Energy contracts

    29,798     28,977     26,010  
   

Load requirements services contracts

        1,333     5,090  
       
 

Total

    29,798     30,310     31,100  
   
 

Aggregate plant performance

                   
   

Equivalent availability

    82.2 %   85.3%     81.0 %
   

Capacity factor

    62.3 %   63.3%     64.8 %
   

Load factor

    75.8 %   74.2%     80.0 %
   

Forced outage rate

    6.2 %   5.8%     8.3 %
 

Average realized price/MWh

                   
   

Energy contracts

  $ 40.12   $ 41.17   $ 51.82  
   

Load requirements services contracts

  $   $ 62.52   $ 62.64  
 

Capacity revenues only (in millions)

  $ 263   $ 178   $ 111  
 

Average realized fuel costs/MWh

  $ 17.17   $ 18.54   $ 15.49  
   
1
Included in fuel costs were $13 million, $63 million and $5 million in 2010, 2009 and 2008, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NOX emission allowances to Midwest Generation were $0.4 million and $1 million in 2010 and 2009, respectively. There were no NOx transfers in 2008. Transfers of SO2 emission allowances from Midwest Generation were $5 million and $2 million in 2010 and 2008, respectively. There were no SO2 transfers in 2009. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

2
For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures-Coal Plants and Statistical Definitions."

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 NOx 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:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Operating Revenues

  $ 636   $ 663   $ 717  

Operating Expenses

                   
 

Fuel1

    279     251     270  
 

Plant operations

    117     104     126  
 

Plant operating leases

    103     102     102  
 

Depreciation and amortization

    18     16     16  
 

Administrative and general

    5     4     4  
       
 

Total operating expenses

    522     477     518  
       

Operating Income

    114     186     199  
       

Other Income

            3  
       

AOI

  $ 114   $ 186   $ 202  
   

Statistics2

                   
 

Generation (in GWh)

    11,028     11,446     11,334  
 

Equivalent availability

    79.7 %   84.7%     80.7 %
 

Capacity factor

    66.8 %   69.2%     68.3 %
 

Load factor

    83.8 %   81.7%     84.6 %
 

Forced outage rate

    10.8 %   9.4%     9.8 %
 

Average realized energy price/MWh

  $ 49.04   $ 48.85   $ 56.24  
 

Capacity revenues only (in millions)

  $ 114   $ 89   $ 46  
 

Average fuel costs/MWh

  $ 25.26   $ 21.89   $ 23.35  
   
1
Included in fuel costs were $7 million, $16 million and $20 million in 2010, 2009 and 2008, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO2 emission allowances to Homer City were $5 million and $2 million in 2010 and 2008, respectively. There were no SO2 transfers in 2009. Transfers of NOx emission allowances from Homer City were $0.4 million and $1 million in 2010 and 2009, respectively. There were no NOx transfers in 2008. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

2
For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures-Coal Plants and Statistical Definitions."

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.

 
  Years Ended December 31,  
Midwest Generation Plants
(in millions)

 
  2010
  2009
  2008
 
   

Operating revenues

  $ 1,479   $ 1,487   $ 1,778  

Less:

                   
 

Load requirements services contracts

        (83 )   (319 )
 

Unrealized (gains) losses

    6     (30 )   6  
 

Capacity and other1 revenues

    (290 )   (181 )   (117 )
       

Realized revenues

  $ 1,195   $ 1,193   $ 1,348  
   

Generation—energy contracts (in GWh)

    29,798     28,977     26,010  

Average realized energy price/MWh

 
$

40.12
 
$

41.17
 
$

51.82
 
   

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  Years Ended December 31,  
Homer City
(in millions)

 
  2010
  2009
  2008
 
   

Operating revenues

  $ 636   $ 663   $ 717  

Less:

                   
 

Unrealized (gains) losses

    20     (15 )   (21 )
 

Capacity and other revenues

    (115 )   (89 )   (59 )
       

Realized revenues

  $ 541   $ 559   $ 637  
   

Generation (in GWh)

    11,028     11,446     11,334  

Average realized energy price/MWh

 
$

49.04
 
$

48.85
 
$

56.24
 
   
1
A gain from the sale of the bankruptcy claims against Lehman Brothers is included in 2010.

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Operating revenues

                   
 

Midwest Generation plants

  $ 1,479   $ 1,487   $ 1,778  
 

Homer City plant

    636     663     717  
 

Renewable energy projects

    137     141     108  
 

Other revenues

    171     86     208  
       

Consolidated operating revenues as reported

  $ 2,423   $ 2,377   $ 2,811  
   


Average Realized Fuel Costs

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

 
  Years Ended December 31,  
Midwest Generation Plants
(in millions)

 
  2010
  2009
  2008
 
   

Fuel costs

  $ 519   $ 547   $ 482  

Add back:

                   
 

Unrealized gains (losses)

    (7 )   15      
       

Realized fuel costs

  $ 512   $ 562   $ 482  
   

Total generation (in GWh)

    29,798     30,310     31,100  

Average realized fuel costs/MWh

 
$

17.17
 
$

18.54
 
$

15.49
 
   

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The average realized fuel costs are presented as an aid in understanding the operating results of the Midwest Generation plants. Average realized fuel costs are a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel costs. Management believes that average realized fuel costs are meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the fuel costs of the coal plants to consolidated fuel costs presented in the preceding table is set forth below:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Fuel costs

                   
 

Midwest Generation plants

  $ 519   $ 547   $ 482  
 

Homer City plant

    279     251     270  
 

Other

    11     (2 )   (5 )
       

Consolidated fuel costs as reported

  $ 809   $ 796   $ 747  
   


Statistical Definitions

Generation from load requirements services contracts at the Midwest Generation plants represents two load requirements services contracts, awarded as part of an Illinois auction, with Commonwealth Edison that commenced on January 1, 2007. One contract expired in May 2008 and the remaining contract expired in May 2009. In 2010, generation sold under load requirements services contracts at the Homer City plant is included in generation.

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

The capacity factor indicates how much power a unit generated compared to the maximum amount of power that could be generated according to its rating. It is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.

The load factor indicates how much power a unit generated compared to the maximum amount of power that a unit was available to generate electricity. It is determined by dividing capacity factor by the equivalent availability factor.

The forced outage rate refers to forced outages and deratings excluding events outside of management's control as defined by NERC. Examples include floods, tornado damage and transmission outages.

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

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Renewable Energy Projects

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Operating Revenues

  $ 137   $ 141   $ 108  

Production Tax Credits

    62     56     44  
       

    199     197     152  
       

Operating Expenses

                   
 

Plant operations

    55     55     35  
 

Depreciation and amortization

    89     92     59  
 

Asset impairment and sale of assets

    3          
 

Administrative and general

    3     3     2  
       
 

Total operating expenses

    150     150     96  

Other Income

   
2
   
3
   
4
 

Net Loss Attributable to Noncontrolling Interests

   
   
3
   
 
       

AOI1

  $ 51   $ 53   $ 60  
   

Statistics2

                   
 

Generation (in GWh)3

    3,646     3,081     2,286  
 

Aggregate plant performance3

                   
   

Equivalent availability

    91.78%     88.7%     80.4 %
   

Capacity factor

    32.97%     31.4%     33.1 %
   
1
AOI is equal to operating income (loss) plus equity in income (losses) of unconsolidated affiliates, production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects.

2
The statistics section summarizes key performance measures related to wind projects, which represents substantially all of the renewable energy projects.

3
Includes renewable energy projects that are unconsolidated at EME. Generation excluding unconsolidated projects was 3,037 GWh in 2010 and 2,514 GWh in 2009.

AOI from renewable energy projects decreased $2 million in 2010 compared to 2009, and decreased $7 million in 2009 compared to 2008. The 2010 decrease was primarily due to the impairment of a Minnesota Wind project and an increase in costs related to projects under construction. The 2009 decrease in AOI was primarily attributable to mild wind conditions, which reduced the revenue increases relative to the increased operating costs associated with additional projects coming on line. Expenses incurred for projects under construction also contributed to the decrease in AOI. EME's share of installed capacity of new wind projects that commenced operations during 2010, 2009 and 2008 was 150 MW, 223 MW and 396 MW, respectively.

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AOI in 2010, 2009 and 2008 included payments from Suzlon Wind Energy Corporation (Suzlon) for availability losses of $2 million, $17 million and $28 million, respectively. Payments under the availability guarantee are designed to compensate EME for lost earnings, including production tax credits. Accordingly, the payments under the availability guarantee are paid on a pre-tax basis which affects period-to-period comparisons that include production tax credits which are after tax.


Energy Trading

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities primarily in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from ISOs.

AOI from energy trading activities increased $61 million in 2010 compared to 2009, and decreased $115 million in 2009 compared to 2008. The 2010 increase in AOI energy trading activities was attributable to increased revenues in congestion and power trading. Congestion trading results increased in 2010 compared to 2009 due to unseasonable cold weather and transmission outages in the New York and PJM markets. The 2009 decrease in AOI from energy trading activities was attributable to lower transmission congestion in the eastern U.S. power grid. In addition, energy trading included favorable results for load service transactions in 2009.


Adjusted Operating Income from Unconsolidated Affiliates

Big 4 Projects.    AOI from the Big 4 projects increased $6 million in 2010 compared to 2009, and decreased $41 million in 2009 compared to 2008. The changes in income are driven by changes in natural gas prices affecting steam revenues and plant maintenance.

Sunrise.    AOI from the Sunrise project decreased $4 million in 2010 from 2009 and increased $13 million in 2009 from 2008. The 2010 decrease was primarily due to a lower availability bonus, partially offset by lower maintenance expenses. The 2009 increase was primarily due to higher availability incentive payments in 2009 and lower maintenance expenses.

March Point.    AOI from the March Point project increased $6 million in 2010 from 2009 and $11 million in 2009 from 2008. The 2010 increase was primarily due to equity distributions received from the project. EME subsequently sold its ownership interest in the March Point project to its partner at book value in February 2010. The 2009 increase was due to EME recommencing recording its share of equity in income from the March Point project in 2009.

Doga.    AOI from the Doga project increased $7 million in 2010 from 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.

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Other Operating Income (Expense)

Other operating income (expense) in 2008 resulted from a charge of $23 million related to the termination of a turbine supply agreement in connection with the Walnut Creek project and a $7 million write-down of capitalized costs related to development projects. These amounts are reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statements of income. For additional information regarding capital expenditures for turbines and the Walnut Creek project, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments" and "—Note 15. Related-Party Transactions."


Corporate Administrative and General Expenses

Corporate administrative and general expenses decreased $18 million in 2010 from 2009 and decreased $9 million in 2009 from 2008. The 2010 and 2009 decreases were primarily attributable to lower development costs related to renewable energy. In April 2009, EME reduced approximately 75 positions in its regional and corporate offices.


Interest Income (Expense)

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Interest income

  $ 2   $ 7   $ 26  
   

Interest expense, net of capitalized interest

                   
 

EME debt

    (229 )   (267 )   (254 )
 

Non-recourse debt

    (34 )   (29 )   (25 )
   

  $ (263 ) $ (296 ) $ (279 )
   

Interest income decreased primarily due to lower interest rates and, to a lesser extent, lower average cash balances.

EME's interest expense decreased $33 million in 2010 from 2009 and increased $17 million in 2009 from 2008. The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities, partially offset by higher wind project financing. The 2009 increase was primarily due to higher debt balances under EME's credit facility in 2009, compared to 2008, and EME's wind financing in June 2009. Capitalized interest was $54 million, $19 million and $32 million in 2010, 2009 and 2008, respectively. The 2010 increase was the result of increased interest capitalization for renewable energy projects under construction.


Income Taxes

EME's income taxes from continuing operations in 2010 included a $16 million income tax benefit resulting from the California Franchise Tax Board's acceptance and application of the federal settlement of tax disputes finalized with the Internal Revenue Service in 2009 for tax

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years 1986 through 2002. In addition, income taxes in 2010, 2009 and 2008 included tax benefits of production tax credits of $62 million, $56 million and $44 million, respectively.

EME's effective tax rates were 11%, 7% and 33%, respectively, for the years ended December 31, 2010, 2009 and 2008. The effective tax rate for 2010 was impacted by the recapture of qualified production deductions realized in prior years resulting from a carryback of net operating losses to 2008. The effective tax rate for 2009 was impacted by lower pretax income in relation to the level of production tax credits and estimated state income tax benefits allocated from Edison International. Estimated state income tax benefits allocated from Edison International of $7 million, $15 million and $5 million were recognized for the years ended December 31, 2010, 2009 and 2008, respectively.

For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes."


Results of Discontinued Operations

The 2010 results of discontinued operations included foreign exchange gains and interest expense on contract indemnities denominated in euros, adjustments to unrecognized tax benefits, and expiration in 2010 of another contract indemnity. The contract indemnities relate to the sale of EME's international projects in December 2004. Results in 2009 and 2008 included foreign exchange gains (losses), change in estimates, and interest expense also associated with these contract indemnities.


Related-Party Transactions

EME owns interests in partnerships that sell electricity generated by their project facilities to SCE and others under the terms of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $367 million, $366 million and $686 million in 2010, 2009 and 2008, respectively. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 15. Related-Party Transactions."


New Accounting Guidance

For a discussion of new accounting guidance affecting EME, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at December 31, 2010:

(in millions)
  Cash and Cash Equivalents
  Available Under Credit Facilities
  Total Available Liquidity
 
   

EME as a holding company

  $ 427   $ 484   $ 911  

EME subsidiaries without contractual dividend restrictions

    188         188  
       

EME corporate cash and cash equivalents

    615     484     1,099  

EME subsidiaries with contractual dividend restrictions

                   
 

Midwest Generation1

    295     497     792  
 

Homer City

    132         132  
 

Other EME subsidiaries

    33         33  
       

Total

  $ 1,075   $ 981   $ 2,056  
   
1
Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure requirements.

Because EME, as a holding company, does not directly own any revenue-producing generation facilities, EME relies on cash distributions and tax payments from its projects to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, see "—Dividend Restrictions in Major Financings."

The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2010, which mature in June 2012:

(in millions)
  EME
  Midwest
Generation

 
   

Commitments

  $ 564   $ 500  

Outstanding borrowings

         

Outstanding letters of credit

    (80 )   (3 )
       

Amount available

  $ 484   $ 497  
   

EME and Midwest Generation may seek to extend or replace credit facilities or retire them by other means. The terms and conditions of any refinancing could be substantially different than those in the current credit facilities. Senior notes in the principal amount of $500 million, which were issued in 2006 and which bear interest at 7.50% per annum, are due in June 2013. EME may also from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.

For additional discussion of liquidity, see "Management's Overview—EME's Liquidity."

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Bonus Depreciation Impact on EME

The Small Business Jobs Act of 2010 and the 2010 Tax Relief Act extended 50% bonus depreciation for qualifying property through 2012 and created a new 100% bonus depreciation for qualifying property placed in service between September 9, 2010 and December 31, 2011. These provisions are expected to result in a consolidated Edison International net operating loss for federal income tax purposes for 2011, and delay tax-allocation payments to EME until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years, In addition, EME expects to make tax-allocation payments in 2012 as a result of reallocation of tax obligations from the expected Edison International consolidated net operating loss during 2011.

The negative impact on 2010 net income was $15 million from recapture of 2008 Section 199 deductions realized in prior years resulting from the carryback of net operating losses.


Capital Investment Plan

At December 31, 2010, forecasted capital expenditures through 2013 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)
  2011
  2012
  2013
 
   

Midwest Generation Plants

                   
 

Plant capital expenditures

  $ 34   $ 23   $ 29  
 

Environmental expenditures

    151     132     198  

Homer City Plant

                   
 

Plant capital expenditures

    18     25     16  
 

Environmental expenditures

             

Renewable Energy Projects

                   
 

Capital and construction expenditures

    189          
 

Turbine commitments

    90          

Other capital expenditures

    21     19     17  
       

Total

  $ 503   $ 199   $ 260  
   


Environmental Capital Expenditures

Midwest Generation plants' environmental expenditures include $109 million for expenditures in 2011 related to SNCR equipment and $372 million for expenditures in 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to

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continue or complete the project. For additional discussion, see "Management's Overview—Environmental Developments—Midwest Generation Compliance Plans and Costs."

The capital investment plan set forth in the previous table does not include environmental capital expenditures for Homer City. However, depending on upcoming and future regulatory developments, Homer City may be required to undertake capital projects to install additional pollution control equipment, which will be dependent on lessor decisions regarding the funding of these expenditures. For a discussion of environmental regulations, see "Management's Overview—Environmental Developments—Homer City Environmental Issues and Capital Resource Limitations."


Non-Environmental Capital Expenditures

Plant capital expenditures in the preceding table relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, condenser re-tubing, development of a coal-cleaning plant refuse site and a new ash disposal site, and main power transformer replacement.

Renewable energy projects' capital and construction expenditures include a project of an unconsolidated entity in which construction expenditures will be substantially funded by EME. Construction project financing of $48 million was available as of December 31, 2010. 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.


Future Projects

At December 31, 2010, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Future development of the wind portfolio is dependent on the availability of third-party capital. To the extent that third-party capital is available, the success of development efforts will depend upon, among other things, obtaining permits and agreements necessary to support an investment. This process may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.

For additional information regarding capital expenditures for turbines and the Walnut Creek project, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments" and "—Note 15. Related-Party Transactions."


EME's Historical Consolidated Cash Flow

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

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Condensed Consolidated Statement of Cash Flows

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Operating cash flow from continuing operations

  $ 602   $ 258   $ 728  

Operating cash flow from discontinued operations

    4     (7 )   1  
       

Net cash provided by operating activities

    606     251     729  

Net cash provided by (used in) financing activities

    425     (714 )   844  

Net cash used in investing activities

    (752 )   (548 )   (760 )
       

Net increase (decrease) in cash and cash equivalents

  $ 279   $ (1,011 ) $ 813  
   


Consolidated Cash Flows from Operating Activities

The 2010 increase as compared to 2009 in cash provided by operating activities from continuing operations was primarily attributable to higher realized revenues from derivative contracts and payments on U.S. Treasury grants.

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


Consolidated Cash Flows from Financing Activities

The 2010 increase as compared to 2009 in cash used in financing activities from continuing operations was attributable to project-level financing of renewable energy projects and repayment of credit facilities in 2009.

The 2009 increase as compared to 2008 in cash used in financing activities from continuing operations was attributable to repayments of $376 million and $475 million under EME's corporate credit facility and Midwest Generation's working capital facility, respectively. These repayments were partially offset by proceeds received from the issuance of a $189 million term loan as part of a $202 million project financing completed in June 2009.


Consolidated Cash Flows from Investing Activities

The 2010 increase as compared to 2009 in cash used in investing activities was primarily attributable to the construction of wind projects. Cash flows related to short-term investments decreased in 2009 compared to 2008 as EME curtailed its purchase of short-term investments.

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Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of December 31, 2010 were as follows:

 
  Moody's Rating
  S&P Rating
  Fitch Rating
 

EME1

  B3     B-   B-

Midwest Generation2

  Ba2     B+   BB

EMMT

  Not Rated     B-   Not Rated
 
1
Senior unsecured rating.

2
First priority senior secured rating.

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

EME does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party.


Credit Rating of EMMT

The Homer City sale-leaseback documents restrict Homer City's ability to enter into derivative activities with EMMT to sell forward the output of the Homer City plant if EMMT does not have an investment grade credit rating from S&P or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents also include a requirement that Homer City's counterparty to such transactions, whether it is EMMT or another party, and Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City plant through EMMT, which has a below investment grade credit rating, and Homer City is not rated. In order to continue to sell forward the output of the Homer City plant through EMMT, EME has obtained a consent from the sale-leaseback owner participants that allows Homer City to enter into such sales, under specified conditions, through March 1, 2014. Homer City continues to be in compliance with the terms of the consent; however, because EMMT's credit rating has dropped below BB-, the consent is revocable by the sale-leaseback owner participants at any time. The sale-leaseback owner participants have not indicated that they intend to revoke the consent; however, there can be no assurance that they will not do so in the future. An additional consequence of EMMT's

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lowered credit rating is a requirement for EMMT to prepay for Homer City's output to satisfy a requirement under the terms of the consent that outstanding accounts receivable between EMMT and Homer City be reduced to zero. Revocation of the consent would not affect trades between EMMT and Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City plant into the spot market on the terms set forth in the Homer City sale-leaseback documents.


Margin, Collateral Deposits and Other Credit Support for Energy Contracts

To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. At December 31, 2010, EMMT had deposited $43 million in cash with clearing brokers in support of futures contracts and had deposited $16 million in cash with counterparties in support of forward energy and congestion contracts. Cash collateral provided to others offset against derivative liabilities totaled $4 million at December 31, 2010. In addition, EME had received cash collateral of $52 million at December 31, 2010 to support credit risk of counterparties under margin agreements. The liability for margin deposits received from counterparties has been offset against net derivative assets.

Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of December 31, 2010 could increase by approximately $89 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings."


EME's Liquidity as a Holding Company

Intercompany Tax-Allocation Agreement

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

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regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME received net tax-allocation payments of $116 million and $166 million in 2010 and 2009, respectively, and made net tax-allocation payments to Edison International of $95 million in 2008. EME expects to receive tax-allocation payments in 2011 as a result of the carryback of Edison International consolidated net operating losses for 2010 and subsequently make tax-allocation payments in 2012 as a result of the reallocation of tax obligations from an expected Edison International consolidated net operating loss during 2011. For further information, see "—Available Liquidity—Bonus Depreciation Impact on EME."


EME's Credit Facility Financial Ratios

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility. The following details of EME's interest coverage ratio and a maximum corporate-debt-to-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements. As of December 31, 2010, EME and its subsidiaries are in compliance with the terms of their debt covenants.

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The following table sets forth the major components of the interest coverage ratio:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
 
   

Funds Flow Available for Interest

             
 

Distributions

             
   

Midwest Generation

  $ 125   $ 200  
   

Homer City

    74     75  
   

Big 4 Projects

    77     62  
   

U.S. Treasury grants

    92      
   

Renewable energy projects1

    223     208  
   

Other projects

    63     47  
 

Tax payments received from subsidiaries

    136     68  
 

Realized trading income

    120     36  
 

Tax allocation receipts (payments)2

    90     139  
 

Operating expenses

    (139 )   (151 )
 

Other items, net

    (56 )   (14 )
       

  $ 805   $ 670  
   

Net Interest Expense

             
 

EME corporate debt

  $ 223   $ 261  
 

Addback: Capitalized interest

    54     19  
 

Powerton-Joliet intercompany notes

    112     112  
 

EME interest income

        (2 )
       

  $ 389   $ 390  
   

Ratio

    2.07     1.72  

Covenant threshold (not less than)

    1.20     1.20  
   
1
The 2009 amount includes proceeds of $167 million from the wind financing by Viento Funding II, Inc., net of financing costs, distributed to EME in 2009.

2
Excludes production tax credits for Viento Funding II, Inc. and certain state tax payments which are classified in other items, net.

The Small Business Jobs Act of 2010 and the 2010 Tax Relief Act provisions are expected to result in a consolidated net operating loss for federal income tax purposes for 2011 and delay tax-allocation payments to EME until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years.

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The following table sets forth the major components of the corporate-debt-to-capital ratio:

 
  December 31,  
(in millions)
  2010
  2009
 
   

Corporate Debt

             
 

Indebtedness for money borrowed

  $ 3,700   $ 3,700  
 

Powerton-Joliet termination value

    933     1,046  
 

Letters of credit

    83     104  
       

  $ 4,716   $ 4,850  
   

Corporate Capital

             
 

Common shareholder's equity

  $ 2,842   $ 2,761  
 

Less:

             
   

Non-cash cumulative changes in accounting

    (9 )   1  
   

Accumulated other comprehensive income

    31     (78 )
 

Adjustments:

             
   

After-tax losses incurred on termination of Collins lease

    587     587  
   

Dividend to Mission Energy Holding Company for repayment of 13.5% notes

    899     899  
       

    4,350     4,170  
       
 

Corporate debt

    4,716     4,850  
       

  $ 9,066   $ 9,020  
   

Corporate-debt-to-capital ratio

    0.52     0.54  

Covenant threshold (not more than)

    0.75     0.75  
   


Dividend Restrictions in Major Financings

General

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


Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at December 31, 2010 or for the 12 months ended December 31, 2010:

Subsidiary
  Financial Ratio
  Covenant
  Actual
 
   

Midwest Generation (Midwest Generation plants)

  Debt to Capitalization Ratio   Less than or equal to 0.60 to 1     0.15 to 1  

Homer City (Homer City plant)

  Senior Rent Service Coverage Ratio   Greater than 1.7 to 1     2.51 to 1  
   

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Midwest Generation Financing Restrictions on Distributions

Midwest Generation is bound by the covenants in its credit agreement and certain covenants under the Powerton-Joliet lease documents with respect to Midwest Generation making payments under the leases. These covenants include restrictions on the ability to, among other things, incur debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines of business, enter into swap agreements, or engage in transactions for any speculative purpose. In order for Midwest Generation to make a distribution, it must be in compliance with the covenants specified under its credit agreement, including maintaining a debt to capitalization ratio of no greater than 0.60 to 1.


Homer City Sale-Leaseback Restrictions on Distributions

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

At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid and the senior rent service coverage ratio for the prior 12-month period (taken as a whole and projected for each of the prospective two 12-month periods) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of Homer City less amounts paid for operating expenses, capital expenditures funded by Homer City, taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service reserve letter of credit. No more than two rent default events may have occurred, whether or not cured. A rent default event is defined as the failure to pay the equity portion of the rent within five business days of when it is due. EME has not guaranteed Homer City's obligations under the leases.


EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries

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


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

EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter

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preceding the sale or disposition in question. At December 31, 2010, the maximum permissible sale or disposition of EME assets is calculated as follows:

(in millions)
   
 
   

Consolidated Net Tangible Assets

       
 

Total consolidated assets

  $ 9,321  
 

Less:

       
   

Consolidated current liabilities

    524  
   

Intangible assets

    78  
       

  $ 8,719  
   

10% Threshold

  $ 872  
   

This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.

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

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Contractual Obligations, Commercial Commitments and Contingencies

Contractual Obligations

EME has contractual obligations and other commercial commitments that represent prospective cash requirements. The following table summarizes EME's significant consolidated contractual obligations as of December 31, 2010.

 
   
  Payments Due by Period  
(in millions)
  Total
  Less than
1 year

  1 to 3
years

  3 to 5
years

  More than
5 years

 
   

Long-term debt1

  $ 6,711   $ 340   $ 1,180   $ 842   $ 4,349  

Power plant and other operating lease obligations2

    3,166     339     664     496     1,667  

Purchase obligations3:

                               
 

Fuel supply contracts

    765     482     283          
 

Coal transportation agreements

    231     231              
 

Gas transportation agreements

    60     8     16     17     19  
 

Capital expenditures

    182     182              
 

Turbine commitments

    90     90              
 

Other contractual obligations

    198     85     103     8     2  

Employee benefit plan contribution4

    22     22              
       

Total Contractual Obligations5,6

  $ 11,425   $ 1,779   $ 2,246   $ 1,363   $ 6,037  
   
1
For additional details, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount also includes interest payments totaling $2.3 billion over the applicable period of the debt.

2
At December 31, 2010, minimum operating lease payments were primarily related to long-term leases for the Powerton and Joliet Stations and the Homer City plant. For further discussion, see "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

3
For additional details, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

4
Amount includes estimated contribution for pension plans and postretirement benefits other than pensions. The estimated contributions beyond 2011 are not available. For more information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 8. Compensation and Benefit Plans—Pension Plans and Postretirement Benefits Other than Pensions."

5
At December 31, 2010, EME had a total net liability recorded for uncertain tax positions of $153 million, which is excluded from the table. EME cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the Internal Revenue Service. For more information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes."

6
The contractual obligations table does not include derivative obligations and AROs, which are discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities," and "—Note 2. Property, Plant and Equipment," respectively.


Commercial Commitments

Standby Letters of Credit

As of December 31, 2010, standby letters of credit under EME and its subsidiaries' credit facilities aggregated $116 million and were scheduled to expire as follows: $95 million in 2011,

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$11 million in 2012, and $10 million in 2017. Certain letters of credit are subject to automatic annual renewal provisions.


Contingencies

EME's significant contingencies related to the Midwest Generation NSR lawsuit and Homer City NSR Lawsuit are discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."


Off-Balance Sheet Transactions

Introduction

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


Investments Accounted for under the Equity Method

EME has a number of investments in power projects that are accounted for under the equity method. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities."


Sale-Leaseback Transactions

EME has entered into sale-leaseback transactions related to the Powerton Station and Units 7 and 8 of the Joliet Station in Illinois and the Homer City plant in Pennsylvania. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Power Plant and Other Lease Commitments."

EME's subsidiaries record depreciation expense from the power plants and interest expense from the lease financing in lieu of an operating lease expense which EME uses in preparing its consolidated financial statements. The treatment of these leases as operating leases on its consolidated financial statements in lieu of lease financings, which are recorded by EME's subsidiaries, resulted in an increase in consolidated net income of $36 million, $35 million and $46 million in 2010, 2009 and 2008, respectively.

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

  Power Station(s)
  Acquisition Price
(in millions)

  Equity Investor
  Original Equity Investment in Owner-Lessor (in millions)
  Amount of Lessor Debt at December 31, 2010
(in millions)

  Maturity Date of Lessor Debt
 
     
 

Powerton/Joliet

  $ 1,367   PSEG/Citigroup, Inc.   $ 238   $ 565 Series B     2016  
 

Homer City

 
$

1,591
 

GECC/Metropolitan Life

 
$

798
 
$

201 Series A
   
2019
 
 

        Insurance Company         $ 495 Series B     2026  
     
PSEG
- PSEG Resources, Inc.
GECC
- General Electric Capital Corporation

The operating lease payments to be made by each of EME's subsidiary lessees are structured to service the lessor debt and provide a return to the owner-lessor's equity investors. Neither the value of the leased assets nor the lessor debt is reflected on EME's consolidated balance sheet. In accordance with GAAP, EME records rent expense on a levelized basis over the terms of the respective leases. The following table summarizes the lease payments and rent expense.

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Cash payments under plant operating leases

                   
 

Powerton and Joliet facilities

  $ 170   $ 185   $ 185  
 

Homer City plant

    155     151     152  
       

Total cash payments under plant operating leases

  $ 325   $ 336   $ 337  
   

Rent expense

                   
 

Powerton and Joliet facilities

  $ 75   $ 75   $ 75  
 

Homer City plant

    103     102     102  
       

Total rent expense

  $ 178   $ 177   $ 177  
   

To the extent that EME's cash rent payments exceed the amount levelized over the term of each lease, EME records prepaid rent. At December 31, 2010 and 2009, aggregate prepaid rent on these leases was $1,187 million and $1,038 million, respectively. To the extent that EME's cash rent payments are less than the amount levelized, EME reduces the amount of prepaid rent.

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

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leases would trigger obligations under EME's guarantee of such leases. These events could have a material adverse effect on EME's results of operations and financial position.


EME's Obligations to Midwest Generation

Proceeds, in the aggregate amount of approximately $1.4 billion, were received by Midwest Generation from the sale of the Powerton and Joliet plants, described above under "—Sale-Leaseback Transactions." These proceeds were loaned to EME and used by EME to repay corporate indebtedness. Although interest and principal payments made by EME to Midwest Generation under the intercompany loan assist in the payment of the lease rental payments owed by Midwest Generation, the intercompany obligation does not appear on EME's consolidated balance sheet. The following table summarizes principal payments due under this intercompany loan:

Years Ending December 31,
(in millions)

  Principal Amount
  Interest Amount
  Total
 
   

2011

  $ 9   $ 111   $ 120  

2012

    11     110     121  

2013

    12     109     121  

2014

    544     86     630  

2015

    284     40     324  

Thereafter

    483         483  
       

Total

  $ 1,343   $ 456   $ 1,799  
   

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

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MARKET RISK EXPOSURES

Introduction

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


Derivative Instruments

EME uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. For derivative instruments recorded at fair value, changes in fair value are recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting. For derivatives that qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings.


Unrealized Gains and Losses

EME classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Midwest Generation plants

                   
 

Non-qualifying hedges

  $ (11 ) $ 40   $ (16 )
 

Ineffective portion of cash flow hedges

    (2 )   5     10  

Homer City plant

                   
 

Non-qualifying hedges

    (1 )   1     1  
 

Ineffective portion of cash flow hedges

    (19 )   14     20  
       

Total unrealized gains (losses)

  $ (33 ) $ 60   $ 15  
   

At December 31, 2010, cumulative unrealized gains of $4 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to 2011.


Fair Value Disclosures

In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of

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EME's derivative instruments, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "—Note 6. Derivative Instruments and Hedging Activities," respectively.

The fair value of derivatives used for non-trading purposes at December 31, 2010 was $46 million. A 10% change in the market price of the underlying commodity at December 31, 2010 would increase or decrease the fair value of outstanding non-trading commodity derivative instruments by approximately $58 million.

The fair value of derivatives used for trading purposes at December 31, 2010 was $110 million. A 10% change in the market price of the underlying commodity at December 31, 2010 would increase or decrease the fair value of trading contracts by approximately $26 million. The impact of changes to the various inputs used to determine the fair value of Level 3 derivatives would not be anticipated to be material to EME's results of operations as such changes would be offset by similar changes in derivatives classified within Level 3 as well as other levels. Level 3 assets and liabilities are 58% and 34%, respectively, of assets and liabilities measured at fair value before the impact of offsetting collateral and netting as of December 31, 2010.


Commodity Price Risk

Introduction

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


Energy Price Risk Affecting Sales from the Coal Plants

Energy and capacity from the coal plants 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. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub, and to a lesser extent, the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant.

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

 
  24-Hour Average Historical Market Prices1  
 
  2010
  2009
  2008
 
   

Midwest Generation plants

                   
 

Northern Illinois Hub

  $ 33.08   $ 28.86   $ 49.01  

Homer City plant

                   
 

PJM West Hub

  $ 45.88   $ 38.31   $ 68.56  
 

Homer City Busbar

    39.35     34.91     57.72  
   
1
Energy prices were calculated at the respective delivery points using historical hourly real-time prices as published by PJM or provided on the PJM web-site.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at December 31, 2010:

 
  24-Hour Forward Energy Prices1  
 
  Northern
Illinois Hub

  PJM West Hub
 
   

2011 calendar "strip"2

  $ 30.68   $ 45.45  

2012 calendar "strip"2

  $ 32.37   $ 46.41  
   
1
Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub and PJM West Hub delivery points.

2
Market price for energy purchases for the entire calendar year.

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

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EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) as of December 31, 2010 for electricity expected to be generated in 2011 and 2012:

 
  2011   2012  
 
  MWh (in
thousands)

  Average
price/
MWh1

  MWh (in
thousands)

  Average
price/
MWh1

 
       

Midwest Generation plants

                         
 

Northern Illinois and AEP/Dayton Hubs

    10,870   $ 37.75     3,358   $ 38.11  

Homer City plant2,3

                         
 

PJM West Hub

    2,540     55.36     1,370     51.68  
       

Total

    13,410           4,728        
   
1
The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.

2
Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. Years 2011 and 2012 include hedging activities entered into by EMMT for the Homer City plant that are not designated under the intercompany agreements with Homer City due to limitations under the sale leaseback transaction documents.

3
The average price/MWh includes 72 to 84 MW for periods ranging from January 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.


Capacity Price Risk

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

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The following table summarizes the status of capacity sales for Midwest Generation and Homer City at December 31, 2010:

 
   
   
   
  RPM Capacity
Sold in Base
Residual Auction
  Other Capacity Sales,
Net of Purchases3
   
 
 
  Installed
Capacity
MW

  Unsold
Capacity1
MW

  Capacity
Sold2
MW

  MW
  Price per
MW-day

  MW
  Average
Price per
MW-day

  Aggregate
Average
Price per
MW-day

 
   

January 1, 2011 to May 31, 2011

                                                 
 

Midwest Generation

    5,477     (548 )   4,929     4,929   $ 174.29           $ 174.29  
 

Homer City

    1,884     (261 )   1,623     1,813     174.29     (190 ) $ 53.95     188.38  

June 1, 2011 to May 31, 2012

                                                 
 

Midwest Generation

    5,477     (495 )   4,982     4,582     110.00     400     85.00     107.99  
 

Homer City

    1,884     (113 )   1,771     1,771     110.00             110.00  

June 1, 2012 to May 31, 2013

                                                 
 

Midwest Generation

    5,477     (773 )   4,704     4,704     16.46             16.46  
 

Homer City

    1,884     (232 )   1,652     1,736     133.37     (84 )   16.46     139.31  

June 1, 2013 to May 31, 2014

                                                 
 

Midwest Generation

    5,477     (827 )   4,650     4,650     27.73             27.73  
 

Homer City

    1,884     (104 )   1,780     1,780     226.15             221.03 4
   
1
Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.

2
Excludes 72 to 84 MW of capacity for periods ranging from January 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

3
Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.

4
Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.

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

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Basis Risk

Sales made from the coal plants in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City plant and for settlement points at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Midwest Generation plants. EME's hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as "basis risk." During 2010, transmission congestion in PJM resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 14%, compared to 9% during 2009 and 16% during 2008. During 2010, transmission congestion in PJM resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 13% and 1%, respectively, compared to 14% and 1%, respectively, during 2009.

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

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Coal and Transportation Price Risk

The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at December 31, 2010 for the following three years:

 
  Amount of Coal Under Contract
in Millions of Equivalent Tons1
 
 
  2011
  2012
  2013
 
   

Midwest Generation plants2

    15.9     9.8      

Homer City plant

    4.6     1.8     0.5  
   
1
The amount of coal under contract in equivalent tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the Homer City plant.

2
In January 2011, Midwest Generation entered into additional contractual agreements for the purchase of 1.25 million tons for 2011.

EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City plant, increased during 2010 from 2009 and decreased during 2009 from 2008. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to a price of $70 per ton at December 31, 2010, compared to a price of $52.50 per ton at December 31, 2009, as reported by the EIA. In 2010, the price of NAPP coal ranged from $54 per ton to $71 per ton, as reported by the EIA. The 2010 increase in NAPP coal prices was primarily driven by the export market demand and global coal pricing.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Midwest Generation plants increased during 2010 from 2009 year-end prices and declined during 2009 from 2008 year-end prices. The price of PRB coal fluctuated between $9.80 per ton and $15.35 per ton during 2010, with a price of $13.60 per ton at December 31, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the EIA. The 2010 increase in PRB coal prices was due to the draw down of inventory levels and flat to slight declines of PRB coal production.

EME has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through 2011. EME is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.

Based on EME's anticipated coal requirements in 2011 in excess of the amount under contract, EME expects that a 10% change in the price of coal at December 31, 2010 would increase or decrease pre-tax income in 2011 by approximately $6 million.

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Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO2 allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, the coal plants are required to hold seasonal and annual NOx allowances.

In the event that actual emissions required are greater than allowances held, EME is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO2 allowances was $50 per ton in 2010, $65 per ton in 2009 and $315 per ton in 2008. The average purchase price of annual NOx allowances was $936 per ton in 2010 and $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO2 allowances and annual NOx allowances was $9 per ton and $320 per ton, respectively, at December 31, 2010.

Based on EME's anticipated SO2 requirements and annual and seasonal NOx requirements for 2011 beyond those allowances already purchased, EME expects that a 10% change in the price of SO2 emission allowances and annual and seasonal NOx emission allowances at December 31, 2010 would increase or decrease pre-tax income in 2011 by approximately $0.5 million.


Credit Risk

For further information related to credit risk and how EME manages credit risk, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At December 31,

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2010, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

 
  December 31, 2010  
(in millions)
  Exposure2
  Collateral
  Net Exposure
 
   

Credit Rating1

                   
 

A or higher

  $ 141   $ (14 ) $ 127  
 

A-

    2         2  
 

BBB+

    4         4  
 

BBB

    31         31  
 

BBB-

    34         34  
 

Below investment grade

    39     (38 )   1  
       

Total

  $ 251   $ (52 ) $ 199  
   
1
EME assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

2
Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable.

The credit risk exposure set forth in the above table is comprised of $149 million of net accounts receivable and payables and $102 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $59 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

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


Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. A 10% change in market interest rates at December 31, 2010 would increase or decrease the fair value of the interest rate swap agreements by approximately $7 million. The fair market values of fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated long-term debt (including current portion) was $3.8 billion at

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December 31, 2010, compared to the carrying value of $4.5 billion. A 10% increase in market interest rates at December 31, 2010 would result in a decrease in the fair value of total long-term debt by approximately $167 million. A 10% decrease in market interest rates at December 31, 2010 would result in an increase in the fair value of total long-term debt by approximately $182 million.


CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Introduction

The accounting policies described below are considered critical to obtaining an understanding of EME's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing EME's consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or if different estimates that could have been selected had been used could have a material impact on EME's results of operations or financial position. For more information on EME's accounting policies, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."


Derivatives

EME uses derivative instruments to manage exposure to changes in electricity, fuel oil and interest rates. Derivative instruments that do not meet the normal purchases and sales exception at fair value are recorded with changes in the derivative's fair value recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for cash flow hedge accounting treatment, the effective portion of the changes in the derivative's fair value is recognized in other comprehensive income until the hedged item is recognized in earnings. EME records derivative instruments used for trading at fair value with changes in fair value recognized in income.

Management's judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management's judgment is also required to determine the fair value of derivative transactions.

Key Assumptions and Approach Used.    EME determines the fair value of derivative instruments based on forward market prices in active markets adjusted for nonperformance risk. If quoted market prices are not available, internally developed models are used to determine the fair value. When actual market prices, or relevant observable inputs are not available, it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid and non-liquid trading hubs. In assessing nonperformance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit

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risks of derivative contracts, but provides market information of the related risk of nonperformance.

In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. For further information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

Effect if Different Assumptions Used.    As described above, fair value is determined using a combination of market information or observable data and unobservable inputs which reflect management's assumptions. Changes in observable data would impact results. In addition, unobservable inputs could have an impact on results. Fair value for Level 3 derivatives is derived using observable and unobservable inputs. As of December 31, 2010, Level 3 derivatives had a net fair value of $91 million. While it is difficult to determine the impact of a change in any one input, if the fair value of Level 3 derivatives were increased or decreased by 10%, the impact would be a $10 million increase or decrease to operating revenues.

For EME's derivative instruments that are measured at fair value using quantitative pricing models, a significant change in estimate could affect EME's results of operations. For further sensitivities in EME's assumptions used to calculate fair value, see "Market Risk Exposures—Derivative Instruments—Fair Value Disclosures." For further information on derivative instruments, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."


Impairment of Long-Lived Assets

Nature of Estimates Required.    Long-lived assets, including intangible assets, are evaluated for impairment in accordance with applicable authoritative guidance. Authoritative guidance requires that if the undiscounted expected future cash flow from a company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be recognized on the financial statements. The impairment charges, if applicable, are calculated as the excess of the asset's carrying value over its fair value, which represents the discounted expected future cash flows attributable to the asset or, in the case of assets expected to be sold, at fair value less costs to sell. Long-lived assets for impairment are evaluated whenever indicators of impairment exist or when there is a commitment to sell or dispose of the asset. These evaluations may result from significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as economic or operational analyses.

Key Assumptions and Approach Used.    The assessment of impairment requires significant management judgment to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. Factors that are considered important, which could trigger an impairment, include operating losses from a project, projected future operating losses, the financial condition of counterparties, or significant negative industry or economic trends. The determination of fair value requires management to apply judgment

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in: (1) estimating future prices of energy and capacity in wholesale energy markets and fuel prices that are susceptible to significant change, (2) environmental and maintenance expenditures, and (3) the time period due to the length of the estimated remaining useful lives.

Effect if Different Assumptions Used.    The estimates and assumptions used to determine whether an impairment exists are subject to a high degree of uncertainty. The estimated fair value of an asset would change materially if different estimates and assumptions were used to determine the amounts or timing of future revenues, environmental compliance costs or operating expenditures.


Application to Merchant Coal-Fired Power Plants

Weak commodity prices combined with continuing, heightened public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants, which may require significant capital and increased operating costs to meet environmental requirements. For a discussion of environmental requirements, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments" Management has reviewed long-term cash flow forecasts that include assumptions about future electricity and fuel prices, future capacity payments under the PJM RPM, and future capital expenditure requirements under different scenarios. Assumptions included in the long-term cash flow forecasts include:

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

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

Plans for compliance with both existing and possible future environmental regulations.

If electricity and capacity prices do not increase consistent with the fundamental forecast or if EME decides not to install additional environmental control equipment and, instead, shuts down one or more coal-fired power plants, the forecasted cash flow would be less than expected and impairment may result.

EME includes allocated acquired emission allowances as part of each power plant asset group. In the case of the Powerton and Joliet Stations, EME also includes prepaid rent in the respective asset group. EME's unit of account is at the plant level and, accordingly, the closure of a unit at a multi-unit site would not result in an impairment of property, plant and equipment unless such condition were to affect an impairment assessment on the entire plant.

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The following table summarizes the net book value of the merchant coal-fired asset groups at December 31, 2010:

(in millions)
   
 
   

Midwest Generation plants

       
 

Crawford Station

  $ 178  
 

Fisk Station

    124  
 

Joliet Station

    683  
 

Powerton Station

    721  
 

Waukegan Station

    365  
 

Will County Station

    537  

Homer City plant

 
$

978
 
   


Accounting for Contingencies, Guarantees and Indemnities

Nature of Estimates Required.    EME records loss contingencies when it determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. When a guarantee or indemnification subject to authoritative guidance is entered into, EME records a liability for the estimated fair value of the underlying guarantee or indemnification. Gain contingencies are recognized in the financial statements when they are realized.

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

During 2004, EME sold a majority of its international operations. The asset sale agreements contain indemnities from EME to the purchasers, including indemnification for pre-closing environmental liabilities and for pre-closing foreign taxes imposed with respect to operations of the assets prior to the sale. At December 31, 2010, EME had recorded an estimated liability of $42 million (of which $3 million is classified as a current liability) related to these matters.

In addition, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation Company LLC for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in a supplemental agreement. The estimated liability is based on studies that estimate future losses

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based on claims experience and other available information. In calculating future losses, various assumptions were made, including, but not limited to, the settlement of future claims under the supplemental agreement, the distribution of exposure sites and that the filing date of asbestos claims will not be after 2044. At December 31, 2010, Midwest Generation had recorded a liability of $56 million related to this contract indemnity.

Effect if Different Assumptions Used.    Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenues and expenses recorded on the consolidated financial statements. In addition, for guarantees and indemnities actual results may differ from the amounts recorded and disclosed and could have a significant impact on EME's consolidated financial statements. For a discussion of contingencies, guarantees and indemnities, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Guarantees and Indemnities," "—Contingencies" and "Item 1. Business—Environmental Matters and Regulations."


Income Taxes

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

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

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

Effect if Different Assumptions Used.    Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenues and expenses recorded in the financial statements. EME continues to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. A tax liability has been recorded with respect to tax positions in which the outcome is uncertain and

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the effect is estimable. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes."


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

FINANCIAL STATEMENTS

   
 

Report of Independent Registered Public Accounting Firm

  87

Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008

  88

Consolidated Balance Sheets at December 31, 2010 and 2009

  89

Consolidated Statements of Total Equity for the years ended December 31, 2010, 2009 and 2008

  91

Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008

  92

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008

  93

Notes to Consolidated Financial Statements

  94
 


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

None.


ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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


Management's Report on Internal Control over Financial Reporting

EME's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f), for EME. Under the supervision and with the participation of its President and Chief Financial Officer, EME's management conducted an evaluation of the effectiveness of EME's internal control over financial reporting based on the framework set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, EME's management concluded that EME's internal control over financial reporting was effective as of December 31, 2010.


Internal Control Over Financial Reporting

There were no changes in EME's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.


ITEM 9B. OTHER INFORMATION

None.

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

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

In our opinion, the consolidated financial statements listed in the index appearing under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Edison Mission Energy and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) of the Form 10-K present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 1 and 3 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities and fair value disclosure principles as of January 1, 2010.

/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 28, 2011

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EDISON MISSION ENERGY AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF INCOME
(in millions)

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Operating Revenues

  $ 2,423   $ 2,377   $ 2,811  

Operating Expenses

                   
 

Fuel

    809     796     747  
 

Plant operations

    654     579     621  
 

Plant operating leases

    178     177     176  
 

Depreciation and amortization

    248     236     194  
 

Asset write-downs, gain on buyout of contract and loss on termination of contract, net (Notes 1, 2, 9 and 15)

    45     4     14  
 

Administrative and general

    182     196     207  
       
   

Total operating expenses

    2,116     1,988     1,959  
       
 

Operating income

    307     389     852  
       

Other Income (Expense)

                   
 

Equity in income from unconsolidated affiliates

    104     100     122  
 

Dividend income

    19     12     10  
 

Interest income

    2     7     26  
 

Interest expense, net of capitalized interest

    (263 )   (296 )   (279 )
 

Other income (expense), net

    9     5     12  
       
   

Total other income (expense)

    (129 )   (172 )   (109 )
       
 

Income from continuing operations before income taxes

    178     217     743  
 

Provision for income taxes

    19     16     243  
       

Income From Continuing Operations

    159     201     500  

Income (loss) from Operations of Discontinued Subsidiaries, net of tax (Note 14)

    4     (7 )   1  
       

Net Income

    163     194     501  
       

Net Loss Attributable to Noncontrolling Interests

    1     3      
       

Net Income Attributable to Edison Mission Energy Common Shareholder

  $ 164   $ 197   $ 501  
   

Amounts Attributable to Edison Mission Energy Common Shareholder

                   

Income from continuing operations, net of tax

  $ 160   $ 204   $ 500  

Income (loss) from discontinued operations, net of tax

    4     (7 )   1  
       

Net Income Attributable to Edison Mission Energy Common Shareholder

  $ 164   $ 197   $ 501  
   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS
(in millions)

 
  December 31,  
 
  2010
  2009
 
   

Assets

             

Current Assets

             
 

Cash and cash equivalents

  $ 1,075   $ 796  
 

Accounts receivable—trade

    170     201  
 

Receivables from affiliates

    192     93  
 

Inventory

    236     196  
 

Derivative assets

    46     197  
 

Restricted cash

    2     69  
 

Margin and collateral deposits

    59     120  
 

Prepaid expenses and other

    79     190  
       
   

Total current assets

    1,859     1,862  
       

Investments in Unconsolidated Affiliates

    557     361  
       

Property, Plant and Equipment, net

    5,332     4,805  
       

Other Assets

             
 

Deferred financing costs

    54     43  
 

Long-term derivative assets

    70     81  
 

Restricted deposits

    44     40  
 

Rent payments in excess of levelized rent expense under plant operating leases

    1,187     1,038  
 

Other long-term assets

    218     403  
       
   

Total other assets

    1,573     1,605  
       

Total Assets

  $ 9,321   $ 8,633  
   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share amounts)

 
  December 31,  
 
  2010
  2009
 
   

Liabilities and Shareholder's Equity

             

Current Liabilities

             
 

Accounts payable

  $ 90   $ 97  
 

Payables to affiliates

    18     14  
 

Accrued liabilities

    201     247  
 

Derivative liabilities

    6     5  
 

Interest payable

    31     30  
 

Deferred taxes

    34     119  
 

Current maturities of long-term debt

    48     37  
 

Short-term debt

    96      
       
   

Total current liabilities

    524     549  
       

Long-term debt net of current maturities

    4,342     3,929  

Deferred taxes and tax credits

    836     672  

Deferred revenues

    160     153  

Long-term derivative liabilities

    19     15  

Other long-term liabilities

    619     478  
       

Total Liabilities

    6,500     5,796  
       

Commitments and Contingencies (Notes 5, 6, 9 and 10)

             

Equity

             
 

Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of December 31, 2010 and 2009

    64     64  
 

Additional paid-in capital

    1,336     1,339  
 

Retained earnings

    1,448     1,280  
 

Accumulated other comprehensive income (loss)

    (31 )   78  
       
   

Total Edison Mission Energy common shareholder's equity

    2,817     2,761  
       

Noncontrolling Interests

    4     76  
       

Total Equity

    2,821     2,837  
       

Total Liabilities and Equity

  $ 9,321   $ 8,633  
   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF TOTAL EQUITY
(in millions)

 
   
  Edison Mission Energy Shareholder's Equity    
 
 
  Total Equity
  Common Stock
  Additional Paid-in Capital
  Retained Earnings (Accumulated Deficit)
  Accumulated Other Comprehensive Income (Loss)
  Non-
controlling Interests

 
   

Balance at December 31, 2007

  $ 1,965   $ 64   $ 1,326   $ 596   $ (63 ) $ 42  
 

Net income

    501             501          
 

Other comprehensive income, net of tax

    263                 263      
 

Payments to Edison International for stock purchases related to stock-based compensation

    (12 )           (12 )        
 

Excess tax benefits related to stock-option exercises

    3         3              
 

Other stock transactions, net

    6         6              
 

Sale of membership interest in noncontrolling interests

    28                     28  
 

Cash contributions from noncontrolling interests

    12                     12  
 

Cash distributions to noncontrolling interests

    (2 )                   (2 )
       

Balance at December 31, 2008

    2,764     64     1,335     1,085     200     80  
 

Net income (loss)

    194             197         (3 )
 

Other comprehensive loss, net of tax

    (122 )               (122 )    
 

Payments to Edison International for stock purchases related to stock-based compensation

    (2 )           (2 )        
 

Other stock transactions, net

    4         4              
 

Cash contributions from noncontrolling interests

    2                     2  
 

Cash distributions to noncontrolling interests

    (3 )                   (3 )
       

Balance at December 31, 2009

    2,837     64     1,339     1,280     78     76  
 

Impact of consolidation and deconsolidation of variable interest entities (Note 1)

    (61 )           10         (71 )
 

Net income (loss)

    163             164         (1 )
 

Other comprehensive loss, net of tax

    (109 )               (109 )    
 

Payments to Edison International for stock purchases related to stock-based compensation

    (6 )           (6 )        
 

Other stock transactions, net

    7         7              
 

Purchase of noncontrolling interests

    (10 )       (10 )            
       

Balance at December 31, 2010

  $ 2,821   $ 64   $ 1,336   $ 1,448   $ (31 ) $ 4  
   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Net Income

  $ 163   $ 194   $ 501  

Other comprehensive income (loss), net of tax

                   
 

Pension and postretirement benefits other than pensions:

                   
   

Prior service adjustment, net of tax

    (7 )   1     3  
   

Net gain (loss) adjustment, net of tax expense (benefit) of $(10), $6 and $(26) for 2010, 2009 and 2008, respectively

    (14 )   10     (41 )
   

Amortization of net loss and prior service adjustment included in expense, net of tax

    1     2     1  
 

Unrealized gains (losses) on derivatives qualified as cash flow hedges:

                   
   

Unrealized holding gains arising during period, net of income tax expense of $37, $36 and $138 for 2010, 2009 and 2008, respectively

    55     43     211  
   

Reclassification adjustments included in net income, net of income tax expense (benefit) of $(96), $(124) and $58 for 2010, 2009 and 2008, respectively

    (144 )   (178 )   89  
       

Other comprehensive income (loss), net of tax

    (109 )   (122 )   263  
       

Comprehensive Income

    54     72     764  
       

Comprehensive Loss Attributable to Noncontrolling Interests

    1     3      
       

Comprehensive Income Attributable to Edison Mission Energy Common Shareholder

  $ 55   $ 75   $ 764  
   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Cash Flows From Operating Activities

                   
 

Net income

  $ 163   $ 194   $ 501  
 

(Income) loss from discontinued operations

    (4 )   7     (1 )
       
 

Income from continuing operations, net

    159     201     500  
 

Adjustments to reconcile income to net cash provided by (used in) operating activities:

                   
   

Equity in income from unconsolidated affiliates

    (104 )   (100 )   (121 )
   

Distributions from unconsolidated affiliates

    91     76     108  
   

Depreciation and amortization

    260     246     202  
   

Deferred taxes and tax credits

    162     275     104  
   

Asset write-downs, gain on buyout of contract and loss on termination of contract, net

    45     4     14  
 

Changes in operating assets and liabilities:

                   
   

(Increase) decrease in margin and collateral deposits

    61     (32 )   (3 )
   

Increase in receivables

    (65 )   (35 )   (1 )
   

Increase in inventory

    (37 )   (8 )   (40 )
   

(Increase) decrease in prepaid expenses and other

    6     53     (9 )
   

(Increase) decrease in restricted cash

    68     (69 )    
   

Increase in rent payments in excess of levelized rent expense

    (149 )   (160 )   (162 )
   

Decrease in accounts payable and other current liabilities

    (93 )   (109 )   (7 )
   

(Increase) decrease in derivative assets and liabilities

    18     (168 )   215  
   

Proceeds from U.S. Treasury grants

    92          
   

(Increase) decrease in other operating—assets

    (9 )   16     (53 )
   

Increase (decrease) in other operating—liabilities

    97     68     (19 )
       
 

Operating cash flow from continuing operations

    602     258     728  
 

Operating cash flow from discontinued operations

    4     (7 )   1  
       
   

Net cash provided by operating activities

    606     251     729  
       

Cash Flows From Financing Activities

                   
 

Borrowings on long-term debt

    401     189     1,130  
 

Payments on long-term debt agreements

    (48 )   (886 )   (292 )
 

Borrowings on short-term debt

    96          
 

Cash contributions from noncontrolling interests

        2     12  
 

Cash dividends to noncontrolling interests

        (3 )    
 

Payments to affiliates related to stock-based awards

    (6 )   (2 )   (8 )
 

Excess tax benefits related to stock-based awards

    1         3  
 

Financing costs

    (19 )   (14 )   (1 )
       
   

Net cash provided by (used in) financing activities from continuing operations

    425     (714 )   844  
       

Cash Flows From Investing Activities

                   
 

Capital expenditures

    (764 )   (283 )   (552 )
 

Proceeds from return of capital and loan repayments and sale of assets

    34     30     39  
 

Proceeds from sale of membership interest

            28  
 

Purchase of interest of acquired companies

    (4 )   (22 )   (19 )
 

Investments in and loans to unconsolidated affiliates

    (7 )        
 

Purchase of short-term investments

            (19 )
 

Maturities of short-term investments

    1     3     96  
 

(Increase) decrease in restricted deposits

    (5 )   3     4  
 

Investments in other assets

    (7 )   (279 )   (337 )
       
   

Net cash used in investing activities from continuing operations

    (752 )   (548 )   (760 )
       

Net increase (decrease) in cash and cash equivalents

    279     (1,011 )   813  

Cash and cash equivalents at beginning of period

    796     1,807     994  
       

Cash and cash equivalents at end of period

  $ 1,075   $ 796   $ 1,807  
   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

Edison Mission Energy (EME) is an indirect, wholly owned subsidiary of Edison Mission Group Inc., which is a wholly owned, non-utility subsidiary of Edison International, which is also the parent holding company of Southern California Edison Company (SCE). EME is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also engages in hedging and energy trading activities in competitive power markets. Midwest Generation, LLC is referred to as Midwest Generation, EME Homer City Generation L.P. is referred to as Homer City, and Edison Mission Marketing & Trading, Inc. is referred to as EMMT in this report.


Basis of Presentation

The consolidated financial statements include the accounts of EME and all subsidiaries and partnerships in which EME has a controlling interest and variable interest entities in which EME is deemed the primary beneficiary. EME's investments in unconsolidated affiliates and variable interest entities in which EME is not deemed to be the primary beneficiary, are accounted for by the equity method. For a discussion of EME's variable interest entities, see Note 3—Variable Interest Entities. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.

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


Cash Equivalents

Cash equivalents included money market funds totaling $813 million and $690 million at December 31, 2010 and 2009, respectively. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months.


Restricted Cash and Deposits

Cash balances that are restricted under margining agreements are classified as restricted cash and included in current assets, as such amounts change frequently based on forward market prices. Restricted deposits consisted of cash balances that are restricted to pay amounts required for lease payments, debt service or to provide collateral. Included in restricted deposits was $20 million at each December 31, 2010 and 2009 related to lease payments and $24 million and $20 million at December 31, 2010 and 2009, respectively, related to debt service and collateral reserves, or other.

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Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory is recorded at actual cost when purchased and then expensed at weighted-average cost as used. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that revenues earned from the generation of power will not cover the cost of the inventory in the ordinary course of business. Inventory consisted of the following:

 
  December 31,  
(in millions)
  2010
  2009
 
   

Coal, fuel oil and other raw materials

  $ 163   $ 132  

Spare parts, materials and supplies

    73     64  
       

Total inventory

  $ 236   $ 196  
   


Property, Plant and Equipment

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

As part of the acquisition of the Midwest Generation plants and Homer City plant, EME acquired emission allowances under the United States Environmental Protection Agency's (US EPA's) Acid Rain Program. EME uses these emission allowances in the normal course of its business to generate electricity and has classified them as part of property, plant and equipment. Acquired emission allowances will be amortized on a straight-line basis.

Estimated useful lives for property, plant and equipment are as follows:

 
Power plant facilities   3 to 35 years
Leasehold improvements   Shorter of life of lease or
estimated useful life
Emission allowances   25 to 33.75 years
Equipment, furniture and fixtures   3 to 10 years
Capitalized leased equipment   5 years
 

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The remaining estimated useful life or lease term at December 31, 2010 for the Midwest Generation coal plants is as follows:

 
Crawford Station   14 years
Fisk Station   14 years
Joliet Unit 6   19 years
Joliet Units 7 and 81   20 years
Powerton Station1   23 years
Waukegan Station   14 years
Will County Station   19 years
 
1
Represents leased facilities. The leases may be renewed based on criteria outlined in their respective agreements.

Estimated useful lives of individual facilities could be impacted by decisions related to the installation of environmental remediation equipment. If environmental compliance equipment is not installed, the useful life may be shortened.

Certain of EME's power plant facilities and equipment require periodic major maintenance. These costs are expensed as incurred.

Interest incurred on funds borrowed by EME is capitalized during the construction period. Such capitalized interest is included in property, plant and equipment. Capitalized interest is amortized over the depreciation period of the major plant and facilities for the respective project. Capitalized interest was $54 million, $19 million and $32 million in 2010, 2009 and 2008, respectively.


Impairment of Long-Lived Assets

EME evaluates the impairment of its investments in projects and other long-lived assets based on a review of estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying amount of such investments or assets may not be recoverable. If the carrying amount for an investment in a project exceeds fair value, an impairment loss is recorded if the decline is other than temporary. If the carrying amount of a long-lived asset exceeds the expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized.


Project Development Costs

EME capitalizes project development costs incurred in the assessment, design and construction of generating projects once it is probable that the project will be completed. EME determines it is probable that the project will be completed based upon management's determination that the project is economically and operationally feasible and appropriate management and regulatory approvals have been obtained or are probable. Project development costs consist of professional fees, permits and other directly related development costs incurred by EME. The capitalized costs are recorded in other long-term assets on EME's consolidated balance sheets until the start of construction, at which time the costs are transferred to construction in progress, a component of property, plant and equipment. The

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capitalized costs are amortized over the life of the projects once operational or charged to expense if management determines the costs to be unrecoverable.


Intangible Assets

Acquired intangible assets with indefinite lives are not amortized; rather they are tested at least annually for impairment or when events or changes in circumstances indicate that the asset might be impaired. Intangible assets are periodically reviewed when impairment indicators are present to assess recoverability from future operations using undiscounted future cash flows. Project development rights are subject to ongoing impairment analysis, such that if a project is no longer expected to be developed, the capitalized costs are written off.

Current unamortized intangible assets reflected in prepaid expenses and other on EME's consolidated balance sheet, consist of purchased emission allowances and were $29 million and $51 million at December 31, 2010 and 2009, respectively.

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

 
  December 31,  
(in millions)
  2010
  2009
 
   

Project development rights

  $ 4   $ 10  

Option rights

    14     17  

Purchased emission allowances1

    31     21  
       

Total unamortized intangible assets

  $ 49   $ 48  
   
1
Emission allowances do not have a pre-determined contractual term or expiration date. Emission allowances are stated at weighted average cost.

Project development rights relate to the consolidation of a development stage enterprise. As project development is completed, the project development rights will be considered part of the property, plant and equipment and depreciated over the estimated useful lives of the respective projects. During 2008, EME recorded a $7 million write-down of capitalized costs, which was reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statement of income.

Option rights relate to EME's joint development agreement entered into to develop jointly a portfolio of projects located in Arizona, Nevada and New Mexico and an option to purchase specific projects. As of December 31, 2010, option rights were $14 million, net of a $3 million write-down in 2009, which was reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statement of income for options unused. The remaining projects are in development with target completion dates of 2012 and beyond. EME is required to fund ongoing development expenses for each project.

Emission allowances at EME's coal plants are classified as current or long-term assets based on the time the allowances are expected to be used. Total emission allowances at these facilities decreased in 2010 due to usage of existing allowances. EME also holds purchased emission allowances related to thermal projects under development.

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Leases

Leased Property

Minimum lease payments under operating leases are levelized (total minimum lease payments divided by the number of years of the lease) and recorded as rent expense over the terms of the leases. Lease payments in excess of the minimum are recorded as rent expense in the year incurred. Operating leases primarily consist of long-term leases for the Powerton, Joliet and Homer City power plants. For additional information on these sale-leaseback transactions, see Note 9—Commitments and Contingencies—Power Plant and Other Lease Commitments.


Power Purchase Agreements

Power purchase agreements entered into by EME may contain leases as described under Power Purchase Agreements, below.


Deferred Financing Costs

Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis that approximates the effective interest rate method over the term of the related debt. EME had unamortized debt issuance costs of $54 million and $43 million at December 31, 2010 and 2009, respectively. Amortization of deferred financing costs charged to interest expense was $5 million, $3 million and $1 million in 2010, 2009 and 2008, respectively.


Revenue Recognition

Generally, revenues and related costs are recognized when electricity is generated or services are provided unless the transaction is accounted for as a derivative and does not qualify for the normal purchases and sales exception. EME's subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts, all subject to market conditions. One of EME's subsidiaries executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EME's subsidiaries generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. EME's subsidiaries record the settlement of non-trading physical forward contracts on a gross basis. EME nets the cost of purchased power against related third-party sales in markets that use locational marginal pricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EME's subsidiaries do not take title to the underlying commodity. Therefore, gains and losses from settlement of financial swaps and options are recorded net in operating revenues in the accompanying consolidated income statements.

Revenues under certain long-term power sales contracts are recognized based on the output delivered at the lower of the amount billable or the average rate over the contract term. The excess of the amounts billed over the portion recorded as revenues is reflected in deferred revenues on the consolidated balance sheets.

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EME accounts for grant income on the deferred method and, accordingly, will recognize operating revenues related to such income over the estimated useful life of the projects. In 2010, EME received $92 million in U.S. Treasury grants (cash grants, under the American Recovery and Reinvestment Act of 2009) related to wind projects that was included in prepaid expenses and other on its consolidated balance sheet at December 31, 2009.


Power Purchase Agreements

EME, generally as the seller, enters into long-term power purchase agreements in the normal course of business. Accounting for long-term power purchase agreements is complex and varies based on the terms and conditions of each agreement. A power purchase agreement may be considered a variable interest in a variable interest entity. Under this classification, the power purchase agreement is evaluated to determine if EME is the primary beneficiary in the variable interest entity, in which case, such entity would be consolidated. EME does not have any power purchase agreements in which it is the primary beneficiary.

A power purchase agreement may also contain a lease for accounting purposes. This generally occurs when a power purchase agreement (signed or modified after June 30, 2003) designates a specific power plant in which the buyer purchases substantially all of the output and does not otherwise meet a fixed price per unit of output exception. EME has a number of power purchase agreements that contain leases. These agreements are classified as operating leases. EME records rental income from wind projects that are accounted for as operating leases as electricity is delivered at rates defined in power sales agreements. Revenues from these power sales agreements were $81 million, $83 million and $46 million in 2010, 2009 and 2008, respectively.

A power purchase agreement that does not contain a lease may be classified as a derivative subject to a normal purchases and sales exception, in which case the power purchase agreement is classified as an executory contract. The contracts that are not eligible for the normal purchases and sales exception are defined as a derivative and are recorded on the consolidated balance sheets at fair value. For further information on derivatives and hedging activities, see Note 6—Derivative Instruments and Hedging Activities.

Power purchase agreements that do not meet the above classification are accounted for on the accrual basis.


Derivative Instruments and Hedging Activities

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

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The accounting guidance for cash flow hedges provides that the effective portion of gains or losses on derivative instruments designated and qualifying as cash flow hedges be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gains or losses on the derivative instruments, if any, must be recognized currently in earnings.

Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows. Derivative and hedging accounting policies are discussed further in Note 6—Derivative Instruments and Hedging Activities.


Stock-Based Compensation

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

EME recognizes stock-based compensation expense on a straight-line basis over the requisite service period. EME recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, EME recognized stock-based compensation expense over the explicit requisite service period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal requisite service period for the award, stock-based compensation is recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement.


Income Taxes

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

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to separate company limitations, additional tax liabilities or benefits based on the impact to the combined group including EME's taxable income or losses and state apportionment factors. At December 31, 2010 and 2009, amounts included in receivables from affiliates and other long-term assets associated with the tax-allocation agreements totaled $199 million and $80 million, respectively.

EME accounts for deferred income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted income tax rates. Investment and energy tax credits are deferred and amortized over the term of the power purchase agreement of the respective project while production tax credits are recognized when earned. EME's investments in wind-powered electric generation projects qualify for federal production tax credits under Section 45 of the Internal Revenue Code, unless a U.S. Treasury cash grant has been elected. Such credits are allowable for production during the 10-year period after a qualifying wind energy facility is placed into service. Certain of these investments may also be eligible for an option to claim investment tax credits (30% of eligible property) or to obtain cash grants for specified renewable energy projects in lieu of credits (30% of eligible property). Cash grants in lieu of tax credits are obtained separate from the tax return. EME applied for and received U.S. Treasury grants in 2010 for Phase II of the Goat Wind and High Lonesome wind projects, which were placed in service in 2009. Certain of EME's wind projects also qualify for state tax credits, which are accounted for similarly to federal production tax credits. For further information regarding income taxes, see Note 7—Income Taxes.


New Accounting Guidance

Accounting Guidance Adopted in 2010

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

The Financial Accounting Standards Board (FASB) issued an accounting standards update that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, its ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has the obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. EME adopted this guidance effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of certain wind assets totaling $253 million and the consolidation of coal assets totaling $99 million at January 1, 2010. Deconsolidation did not result in a gain or loss. The consolidation of EME's 50% partnership interest in American Bituminous Power Partners, L.P., referred to as the Ambit project, a coal-fired electrical plant project with a capacity of 80 MW, resulted in a cumulative effect adjustment that increased retained earnings by $10 million. For further discussion, see Note 3—Variable Interest Entities.

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Fair Value Measurements and Disclosures

The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. The requirements, which EME adopted effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. Since this guidance impacts disclosures only, the adoption did not have an impact on EME's consolidated results of operations, financial position or cash flows. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 4—Fair Value Measurements.


Accounting Guidance Not Yet Adopted

Revenue—Multiple-Deliverables

In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The adoption of this accounting standards update will not have a material impact on EME's consolidated results of operations, financial position or cash flows.


Note 2. Property, Plant and Equipment

Property, plant and equipment consisted of the following:

 
  December 31,  
(in millions)
  2010
  2009
 
   

Power plant facilities

  $ 4,478   $ 4,133  

Leasehold improvements

    177     156  

Emission allowances

    1,305     1,305  

Construction in progress1

    1,036     616  

Equipment, furniture and fixtures

    95     69  
       

   
7,091
   
6,279
 

Less accumulated depreciation and amortization

   
1,759
   
1,474
 
       

Net property, plant and equipment

  $ 5,332   $ 4,805  
   
1
Construction in progress consisted of $888 million and $451 million at December 31, 2010 and 2009, respectively, related to wind projects.

In the fourth quarter of 2010, Midwest Generation recorded a $40 million write-off reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" of

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capitalized construction in progress costs for air emissions control technology that is not currently being pursued for use at the Powerton Station.

The power sales agreements of certain wind projects qualify as operating leases pursuant to authoritative guidance on leases. The carrying amount and related accumulated depreciation of the property of these wind projects totaled $1.4 billion and $137 million, respectively, at December 31, 2010.


Asset Retirement Obligations

Authoritative guidance on asset retirement obligations (AROs) requires entities to record the fair value of a liability for an ARO in the period in which it is incurred, including a liability for the fair value of a conditional ARO, if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. When an ARO liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased for accretion expense to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Settlement of an ARO liability for an amount other than its recorded amount results in an increase or decrease in expense.

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

EME has recorded AROs related to its wind facilities due to site lease obligations to return the land to grade at the end of the respective leases. Wind-related AROs cover site reclamation and turbine and related facility dismantlement. The earliest settlement of any of these obligations is anticipated to be in 2019. However, the operation of an individual facility may impact the timing of the ARO for that facility. Decisions made in conjunction with each facility's operation could extend or shorten the anticipated life depending on improvements and other factors.

EME recorded a liability representing expected future costs associated with site reclamations, facilities dismantlement and removal of environmental hazards, which is included in other

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long-term liabilities on EME's consolidated balance sheets. A reconciliation of the changes in the ARO liability is as follows:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Beginning balance

  $ 43   $ 34   $ 16  

Accretion expense

    3     3     1  

Revisions

            (4 )

Liabilities added

    9     6     21  

Transfers out1

    (1 )        
       

Ending balance

  $ 54   $ 43   $ 34  
   
1
Transfers out represents the deconsolidation of two wind projects and consolidation of one coal project effective January 1, 2010. For further discussion, see Note 3—Variable Interest Entities.


Note 3. Variable Interest Entities

Variable Interest Entities

Authoritative guidance regarding consolidation of variable interest entities defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk, or as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. Effective January 1, 2010, EME adopted the FASB's new guidance. Under this new qualitative model, the primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of variable interest entities in which EME has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements. EME uses variable interest entities to conduct its business as described below.


Description of Use of Variable Interest Entities

EME is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME'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 subsidiaries and affiliates have financed the development and construction or acquisition of its projects by capital contributions from EME and the incurrence of debt or lease obligations by its subsidiaries and affiliates owning the operating facilities. These project

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level debt or lease obligations are generally secured by project specific assets and structured as non-recourse to EME, with several exceptions, including EME's guarantee of the Powerton and Joliet leases as part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Midwest Generation plants.


Categories of Variable Interest Entities

Projects or Entities that are Consolidated

EME has purchased a majority interest in a number of wind projects under joint development agreements with third-party developers. At December 31, 2010 and 2009, EME had majority interests in 15 wind projects with a total generating capacity of 700 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. Upon the application of the new guidance effective January 1, 2010, EME deconsolidated two of these projects. See further discussion in "—Projects that are not Consolidated." In determining that EME was the primary beneficiary of the 13 projects consolidated at December 31, 2010, the key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities.

The following table presents summarized financial information of the wind projects that were consolidated by EME:

 
  December 31,  
(in millions)
  2010
  2009
 
   

Current assets

  $ 16   $ 73  

Net property, plant and equipment1

    660     944  

Other long-term assets

    2     2  
       
 

Total assets1

  $ 678   $ 1,019  
       

Current liabilities

  $ 11   $ 17  

Long-term debt net of current maturities

    16     20  

Deferred revenues

    57     58  

Other long-term liabilities

    19     21  
       
 

Total liabilities

  $ 103   $ 116  
       

Noncontrolling interests

  $ 4   $ 76  
   
1
Amounts included assets of $253 million ($247 million of net property, plant and equipment) that were deconsolidated on January 1, 2010.

Assets serving as collateral for the debt obligations had a carrying value of $71 million and $81 million at December 31, 2010 and 2009, respectively, and primarily consist of property, plant and equipment. The consolidated statements of income and cash flows for the years ended December 31, 2010 and 2009 includes $13 million and $12 million of pre-tax losses, respectively, and $7 million and $37 million of operating cash flows, respectively, related to variable interest entities that are consolidated.

EME has a 50% partnership interest in the Ambit project. EME has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has

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the obligation to absorb losses and right to receive benefits from the project. Effective January 1, 2010, under new accounting guidance, EME is the primary beneficiary. As the primary beneficiary, EME consolidated Ambit project assets totaling $99 million on January 1, 2010.

The following table presents the summarized financial information of the Ambit project consolidated by EME:

(in millions)
  December 31, 2010
 
   

Current assets

  $ 10  

Net property, plant and equipment

    79  

Other long-term assets

    4  
       
 

Total assets

  $ 93  
       

Current liabilities

  $ 14  

Long-term obligations net of current maturities

    55  

Deferred revenues

    14  

Other long-term liabilities

    2  
       
 

Total liabilities

  $ 85  
   

Substantially all of the assets above are pledged as collateral for the partnership's debt obligations.

The consolidated statements of income and cash flows for the year ended 2010 were not significantly impacted by the consolidation of the Ambit project.


Projects that are not Consolidated

EME accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. As of December 31, 2010 and 2009, EME had five significant variable interests in projects that are not consolidated, consisting of the Big 4 projects and the Sunrise project. A subsidiary of EME operates the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects) and EME's partner provides the fuel management services. In addition, the executive director of these projects is provided by EME's partner. Commercial and operating activities are jointly controlled by a management committee of each variable interest entity. Accordingly, EME continues to account for its variable interests under the equity method.

EME deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EME is not the primary beneficiary of these projects. Accordingly, effective January 1, 2010, EME accounts for its interests in these projects under the equity method.

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The following table presents the carrying amount of EME's investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment:

 
  As of December 31, 2010  
(in millions)
  Investment
  Maximum
Exposure

 
   

Natural gas-fired projects

  $ 333   $ 333  

Wind projects

    224     224  
   

EME's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EME's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's investment, but would not require EME to contribute additional capital. At December 31, 2010, entities which EME has accounted for under the equity method had indebtedness of $116 million, of which $41 million is proportionate to EME's ownership interest in these two projects. At December 31, 2009, entities which EME has accounted for under the equity method had indebtedness of $245 million, of which $104 million was proportionate to EME's ownership interest in these two projects.

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Revenues

  $ 828   $ 936   $ 1,434  

Expenses

    653     734     1,193  
       

Net income

  $ 175   $ 202   $ 241  
   

 

 
  December 31,  
(in millions)
  2010
  2009
 
   

Current assets

  $ 296   $ 387  

Noncurrent assets

    850     715  
       
 

Total assets

  $ 1,146   $ 1,102  
       

Current liabilities

  $ 157   $ 198  

Noncurrent liabilities

    74     198  

Equity

    915     706  
       
 

Total liabilities and equity

  $ 1,146   $ 1,102  
   

The difference between the carrying value of these equity investments and the underlying equity in the net assets was $11 million at December 31, 2010. The difference is being amortized over the life of the projects. The majority of noncurrent liabilities are comprised of project financing arrangements that are non-recourse to EME. The undistributed earnings of

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equity method investments were $28 million and $30 million at December 31, 2010 and 2009, respectively.

In February 2010, EME sold its 50% ownership interest in the March Point project to its partner after receiving an $18 million equity distribution reflected in "Equity in income from unconsolidated affiliates" on EME's consolidated statement of income. The purchaser of EME's interest in March Point has agreed to indemnify EME for claims under a guarantee.

The following table presents, as of December 31, 2010, the investments in unconsolidated affiliates accounted for by the equity method that represent at least five percent (5%) of EME's income before tax or in which EME has an investment balance greater than $50 million:

Unconsolidated
Affiliates

  Location
  Investment at
December 31,
2010
(in millions)

  Ownership
Interest at
December 31,
2010

  Operating Status
 

San Juan Mesa

  Elida, NM   $ 92     75 % Operating wind-powered facility

Elkhorn Ridge

  Bloomfield, NE     81     67 % Operating wind-powered facility

Sunrise

  Fellows, CA     174     50 % Operating gas-fired facility

Midway-Sunset

  Taft, CA     40     50 % Operating cogeneration facility

Sycamore

  Bakersfield, CA     36     50 % Operating cogeneration facility

Kern River

  Bakersfield, CA     26     50 % Operating cogeneration facility

Watson

  Carson, CA     48     49 % Operating cogeneration facility
 

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

(in millions)
  2010
  2009
 
   

Investments in Unconsolidated Affiliates

             
 

Equity investment

  $ 548   $ 351  
 

Cost investment

    9     10  
       

Total

  $ 557   $ 361  
   

At December 31, 2010 and 2009, EME has a 38% ownership interest in a small biomass project that it accounts for under the cost method of accounting as it does not have a significant influence over the project's operating and financial activities. EME believes that the carrying amount at December 31, 2010 and 2009 was not impaired.

At December 31, 2010 and 2009, EME accounted for its ownership in the Doga project on the cost method as accumulated distributions exceeded accumulated earnings. EME has not estimated the fair value of cost method investments as quoted market prices are not available and the determination of fair value is highly subjective and cannot be readily ascertained.

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Note 4. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or a liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. The fair value of derivative assets' nonperformance risk was not material as of December 31, 2010 and 2009.

EME categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The following table sets forth EME's assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:

 
  As of December 31, 2010  
(in millions)
  Level 1
  Level 2
  Level 3
  Netting and
Collateral1

  Total
 
   

Assets at Fair Value

                               
 

Money market funds2

  $ 813   $   $   $   $ 813  
       
 

Derivatives

                               
   

Electricity

  $   $ 70   $ 107   $ (61 ) $ 116  
   

Natural gas

    1             (1 )    
   

Fuel oil

    8             (8 )    
       
   

Total commodity contracts

    9     70     107     (70 )   116  
       
 

Total assets

  $ 9   $ 70   $ 107   $ (70 ) $ 116  
       

Liabilities at Fair Value

                               
 

Derivatives

                               
   

Electricity

  $   $ 12   $ 16   $ (21 ) $ 7  
   

Natural gas

        2             2  
   

Coal

        1         (1 )    
       
   

Total commodity contracts

        15     16     (22 )   9  
   

Interest rate contracts

        16             16  
       
 

Total liabilities

  $   $ 31   $ 16   $ (22 ) $ 25  
   

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  As of December 31, 2009  
(in millions)
  Level 1
  Level 2
  Level 3
  Netting and
Collateral1

  Total
 
   

Assets at Fair Value

                               
 

Money market funds2

  $ 758   $   $   $   $ 758  
       
 

Derivatives

                               
   

Electricity

  $   $ 235   $ 179   $ (136 ) $ 278  
   

Natural gas

    2             (2 )    
   

Fuel oil

    15             (15 )    
       
   

Total commodity contracts

    17     235     179     (153 )   278  
       
 

Total assets

  $ 17   $ 235   $ 179   $ (153 ) $ 278  
       

Liabilities at Fair Value

                               
 

Derivatives

                               
   

Electricity

  $   $ 85   $ 6   $ (73 ) $ 18  
   

Natural gas

    3     1         (4 )    
       
   

Total commodity contracts

    3     86     6     (77 )   18  
   

Interest rate contracts

        2             2  
       
 

Total liabilities

  $ 3   $ 88   $ 6   $ (77 ) $ 20  
   
1
Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

2
At December 31, 2010 and 2009, included in cash and cash equivalents, and at December 31, 2009, also included in restricted cash, and prepaid expenses and other on EME's consolidated balance sheets.

The following table sets forth a summary of changes in the fair value of assets and liabilities, net categorized as Level 3:

 
   
  2009  
(in millions)
  2010
Derivatives

  Derivatives
  Money
Market
Funds

 
   

Fair value, net asset at beginning of periods

  $ 173   $ 213   $ 3  

Total realized/unrealized gains (losses):

                   
 

Included in earnings1

    64     7      
 

Included in accumulated other comprehensive income (loss)

    2     3      

Purchases and settlements, net2

    (143 )   (40 )   (3 )

Transfers in or out of Level 3

    (5 )   (10 )    
       

Fair value, net asset at end of periods

  $ 91   $ 173   $  
   

Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at end of periods1

  $ 13   $ 64   $  
   
1
Reported in operating revenues on EME's consolidated statements of income.

2
Includes impact of load requirements services contracts settled when offsetting purchases of energy derivative contracts were classified as Level 2.

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EME determines the fair value of transfers in and out of each level at the end of each reporting period. There were no significant transfers between levels during 2010, 2009 and 2008.


Valuation Techniques used to Determine Fair Value

Level 1

Level 1 includes assets and liabilities where unadjusted quoted prices in active markets are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded derivatives and money market funds.


Level 2

Level 2 pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and liabilities utilizing Level 2 inputs include over-the-counter derivatives.

Derivative contracts that are over-the-counter traded are valued using pricing models and are generally classified as Level 2. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. Forward market prices are developed based on the source that best represents trade activity in each market. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.


Level 3

Level 3 includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, qualifying facilities contracts, derivative contracts that trade infrequently (such as congestion revenue rights in the California market, financial transmission rights traded in markets outside California and over-the-counter derivatives at illiquid locations), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3. In circumstances where EME cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

For derivative contracts that trade infrequently (illiquid financial transmission rights and congestion revenue rights), changes in fair value are based on the hypothetical sale of illiquid positions. Objective criteria are reviewed, including system congestion and other underlying drivers and fair value is adjusted when it is concluded that a change in objective criteria

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would result in a new valuation that better reflects fair value. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of EME's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models that may require EME to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.


Long-term Debt

The carrying amounts and fair values of EME's long-term debt were as follows:

 
  December 31, 2010   December 31, 2009  
(in millions)
  Carrying
Amount

  Fair Value
  Carrying
Amount

  Fair Value
 
   

Long-term debt, including current portion

  $ 4,390   $ 3,670   $ 3,966   $ 3,150  
   

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

The carrying amount of trade receivables, payables and short-term debt approximates fair value and, therefore, is not included in the table above.

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Note 5. Debt and Credit Agreements

Long-Term Debt

Long-term debt includes both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay such obligations. At December 31, 2010, recourse debt to EME totaled $3.7 billion and non-recourse project debt totaled $690 million. The following table summarizes long-term debt (rates and terms as of December 31, 2010):

 
  December 31,  
(in millions)
  2010
  2009
 
   

Recourse

             

EME (parent only)

             
 

Senior Notes, net

             
   

due 2013 (7.50%)

  $ 500   $ 500  
   

due 2016 (7.75%)

    500     500  
   

due 2017 (7.00%)

    1,200     1,200  
   

due 2019 (7.20%)

    800     800  
   

due 2027 (7.625%)

    700     700  

Non-recourse

             

EME CP Holdings Co.
Note Purchase Agreement due 2015 (7.31%)

   
54
   
61
 

Viento Funding II, Inc.
Term Loan due 2016 (LIBOR plus 3.875%) (4.335%)

    150     178  

American Bituminous Power Partners, L.P.
Bonds due 2017 (Floating 0.34%)

    63      

Big Sky Wind, LLC
Vendor financing loan due 2014 (LIBOR plus 2.5%) (2.96%)

    190      

Cedro Hill Wind, LLC
Term Loan due 2025 (LIBOR plus 3.0%) (3.31%)

    135      

High Lonesome Mesa, LLC
Bonds Series 2010A and 2010B due 2017 (6.85%)

    75      

Other

    23     27  
       

Subtotal

  $ 4,390   $ 3,966  

Less current maturities of long-term debt

    48     37  
       

Total

  $ 4,342   $ 3,929  
   

Long-term debt maturities at December 31, 2010, for the next five years are summarized as follows: $48 million in 2011, $58 million in 2012, $566 million in 2013, $260 million in 2014, and $70 million in 2015.


Liens and Security Interests

In connection with Midwest Generation's financing activities, a first priority security interest was provided in substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants, the receivables of EMMT directly related

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to Midwest Generation's hedging activities and the pledge of the intercompany notes from EME (approximately $1.3 billion at December 31, 2010). The net book value of assets pledged or mortgaged was $2.8 billion at December 31, 2010. In addition to these assets, Midwest Generation's membership interests and the capital stock of Edison Mission Midwest Holdings were pledged.

In connection with the Viento Funding II wind financing, Viento Funding II's payment obligations are secured by pledges of its direct and indirect ownership interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. In connection with the Big Sky turbine financing, the loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if any, of the Big Sky wind project is to be deposited on a monthly basis. In connection with each of the High Lonesome, Laredo Ridge and Cedro Hill wind financings, the payment obligations are secured by a mortgage on the respective project's real property assets and a pledge of the respective project's material contracts. In connection with the High Lonesome financing, a security interest was also provided in an operations and maintenance reserve account and a debt service reserve account that the project is required to fund over a period of time.

For further details regarding consolidated assets pledged as security for debt obligations, see Note 3—Variable Interest Entities.


Senior Notes

EME has $3.7 billion of senior notes due 2013 through 2027. The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, of the senior notes plus a "make-whole" premium. The senior notes are EME's senior unsecured obligations, ranking equal in right of payment to all of EME's existing and future senior unsecured indebtedness, and will be senior to all of EME's future subordinated indebtedness. EME's secured debt and its other secured obligations are effectively senior to the senior notes to the extent of the value of the assets securing such debt or other obligations. None of EME's subsidiaries have guaranteed the senior notes and, as a result, all the existing and future liabilities of EME's subsidiaries are effectively senior to the senior notes.


Credit Agreements

Total borrowings available under EME's secured credit facility maturing in June 2012 were $564 million, and subject to the satisfaction of conditions as set forth in the secured credit facility, EME is permitted to increase the amount available under the secured credit facility to an amount that, when taken together with all other secured indebtedness of EME, does not exceed 15% of EME's consolidated net tangible assets, as defined in the secured credit facility. Loans made under this credit facility bear interest, at EME's election, at either London Interbank Offered Rate, or LIBOR, (which is based on the interbank Eurodollar market) or the base rate (which is calculated as the higher of Citibank, N.A.'s publicly announced base rate and the federal funds rate in effect from time to time plus 0.50%) plus, in both cases, an applicable margin. The applicable margin depends on EME's debt ratings. The credit facility contains financial covenants which require EME to maintain an interest

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coverage ratio not less than 1.20 and a corporate debt to corporate capital ratio not more than 0.75. A failure to meet a ratio threshold could trigger other provisions and require a prepayment of the outstanding borrowings. At December 31, 2010, the interest coverage ratio was 2.07 for the year ended December 31, 2010 and the corporate debt to corporate capital ratio was 0.52.

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

Borrowings made under Midwest Generation's credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%. The working capital facility matures in June 2012. The working capital facility contains financial covenants which require Midwest Generation to maintain a debt to capitalization ratio of no greater than 0.60 to 1. At December 31, 2010, the debt to capitalization ratio was 0.15 to 1. Midwest Generation uses its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation can also support its hedging activities by granting liens to eligible hedge counterparties.

The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2010:

(in millions)
  EME
  Midwest
Generation

 
   

Commitments

  $ 564   $ 500  

Outstanding borrowings

         

Outstanding letters of credit

    (80 )   (3 )
       

Amount available

  $ 484   $ 497  
   


Viento Funding II Wind Financing

In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The financing included a $189 million seven-year term loan and a $13 million letter of credit facility which replaced project letters of credit previously issued under the EME corporate credit facility. Interest under the term loan accrues at LIBOR plus 3.875% initially, with the rate increasing 0.25% on the third and sixth anniversaries of the closing date. Viento Funding II entered into interest rate swap agreements at 3.175% to hedge the majority of the variable interest rate under the term loan. For further details regarding the interest rate swap agreements, see Note 6—Derivative Instruments and Hedging Activities.

Distributions from Viento Funding II are subject to compliance with the terms and conditions of its credit facilities, including a 12-month historic debt service coverage ratio test as

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specified in the agreements of 1.20 to 1.0. The debt service coverage ratio was 2.08 at December 31, 2010. At December 31, 2010, $150 million was outstanding under this loan. The amount of outstanding letters of credit was $13 million.


American Bituminous Project

EME consolidated the Ambit project on January 1, 2010. At December 31, 2010, this project had $63 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The Ambit project is required to maintain funded reserve accounts primarily for debt servicing and maintenance costs. The required reserve account balance at December 31, 2010 was $18 million and was under funded by $14 million. The underfunded reserve does not create an event of default under the loan, but does restrict distributions from the Ambit project.


Big Sky Turbine Financing

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

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

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

the loan has a five-year final maturity. However, specific events, including project performance, may trigger earlier repayment.

At December 31, 2010, $190 million was outstanding under this loan.


2010 Project Financings

High Lonesome

In November 2010, EME completed through its subsidiary, High Lonesome Mesa, LLC, a non-recourse financing of its interests in the High Lonesome wind project. The $81 million financing included: $50 million Series 2010A bonds issued by the New Mexico Renewable Energy Transmission Authority, as a conduit issuer for High Lonesome Mesa, LLC, with proceeds loaned to the High Lonesome wind project, $25 million Series 2010B bonds issued directly by the project, and a $6 million debt service reserve letter of credit facility.

Both series of bonds mature on November 1, 2017, and accrue interest at 6.85%. The Series 2010A bonds are scheduled to partially amortize over the term, while no principal payments of the Series 2010B bonds are due until maturity. As of December 31, 2010, there were $50 million and $25 million outstanding under the Series 2010A bonds and Series 2010B bonds, respectively, and $5 million of outstanding letters of credit.

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Laredo Ridge

In July 2010, EME completed through its subsidiary, Laredo Ridge Wind, LLC, a non-recourse financing of its interests in the Laredo Ridge wind project. The financing included: a $75 million construction loan required to be converted to a 15-year amortizing term loan by August 31, 2011, subject to meeting specified conditions; a $53 million bridge loan, secured by the expected U.S. Treasury grant, immediately due to be fully repaid upon receipt of the U.S. Treasury grant and no later than December 31, 2011; a $9 million letter of credit facility; and a $3 million working capital facility.

Interest under the construction loan and the term loan will accrue at LIBOR plus 2.75% initially, with the rate increasing 0.125% after the third, sixth, ninth and twelfth years. Pursuant to the financing agreement, Laredo Ridge entered into a forward starting interest rate swap agreement at 3.46% to hedge the majority of the variable interest rate debt effective March 31, 2011, the same date EME estimates that the construction loan will convert to the term loan. Interest under the bridge loan will accrue at LIBOR plus 2.50%. For further details regarding the interest rate swap agreements, see Note 6—Derivative Instruments and Hedging Activities. As of December 31, 2010, there was $43 million outstanding under the construction loan at a weighted average interest rate of 3.01% and $53 million outstanding under the bridge loan at a weighted average interest rate of 2.76%, both classified as short-term debt on EME's consolidated balance sheet, and $3 million of outstanding letters of credit.


Cedro Hill

In March 2010, EME completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that was converted to a 15-year amortizing term loan on December 22, 2010, a $10 million letter of credit facility and a $4 million working capital facility.

Interest under the term loan will accrue at LIBOR plus 3% initially, with the rate increasing 0.125% after the third, sixth, ninth and eleventh years and 0.25% after the thirteenth year. Pursuant to the financing agreement, Cedro Hill Wind entered into a forward starting interest rate swap agreement at 4.29% to hedge the majority of the variable interest rate debt. For further details regarding the interest rate swap agreements, see Note 6—Derivative Instruments and Hedging Activities. As of December 31, 2010, there was $135 million outstanding under the term loan at a weighted average interest rate of 3.31% classified as long-term debt on EME's consolidated balance sheet and $10 million of outstanding letters of credit.


Other Letters of Credit Facilities

As of December 31, 2010, a subsidiary of EME had a $10 million letter of credit facility with $2 million outstanding letters of credit.

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Standby Letters of Credit

As of December 31, 2010, standby letters of credit under EME's credit facility aggregated $80 million and were scheduled to expire as follows: $72 million in 2011 and $8 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $36 million, $3 million of which was under the Midwest Generation credit facility, and were scheduled to expire as follows: $23 million in 2011, $3 million in 2012 and $10 million in 2017. Certain letters of credit are subject to automatic annual renewal provisions.


Note 6. Derivative Instruments and Hedging Activities

EME uses derivative instruments to reduce EME's exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. To the extent that EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.

Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EME's consolidated balance sheets with offsetting changes recorded on the consolidated statements of income. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on EME's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted transaction occurs.

Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues on the consolidated statements of income.

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

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Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging and trading activities:

December 31, 2010  
 
   
   
   
  Hedging Activities    
 
Commodity
  Instrument
  Classification
  Unit of
Measure

  Cash Flow
Hedges

  Economic
Hedges

  Trading
Activities

 
   

Electricity

  Forwards/Futures   Sales   GWh1     16,799 2   22,456 4   34,630  

Electricity

  Forwards/Futures   Purchases   GWh     408 2   22,931 4   37,669  

Electricity

  Capacity   Sales   MW-Day
(in thousands)
    190 3       136 3

Electricity

  Capacity   Purchases   MW-Day
(in thousands)
    8 3       419 3

Electricity

  Congestion   Sales   GWh         136 5   12,020 5

Electricity

  Congestion   Purchases   GWh         1,143 5   187,689 5

Natural gas

  Forwards/Futures   Sales   bcf1             30.6  

Natural gas

  Forwards/Futures   Purchases   bcf             34.3  

Fuel oil

  Forwards/Futures   Sales   barrels         250,000     10,000  

Fuel oil

  Forwards/Futures   Purchases   barrels         490,000     10,000  

Coal

  Forwards/Futures   Sales   tons             2,630,500  

Coal

  Forwards/Futures   Purchases   tons             2,645,500  
   

 

(in millions)
Instrument
  Purpose
  Type of Hedge
  Notional
Amount

  Expiration Date
 

Amortizing interest rate swap

  Convert floating rate (6-month
LIBOR) debt to fixed rate
(3.175%) debt
  Cash flow   $ 138   June 2016

Amortizing forward starting
interest rate swap

  Convert floating rate (3-month
LIBOR) debt to fixed rate
(4.29%) debt
  Cash flow     122   December 2025

Amortizing forward starting
interest rate swap

  Convert floating rate (3-month
LIBOR) debt to fixed rate
(3.46%) debt
  Cash flow     68   March 2026
 

 

December 31, 2009  
 
   
   
   
  Hedging Activities    
 
Commodity
  Instrument
  Classification
  Unit of Measure
  Cash Flow Hedges
  Economic Hedges
  Trading Activities
 
   

Electricity

  Forwards/Futures   Sales   GWh1     24,355 2   26,838 4   23,306  

Electricity

  Forwards/Futures   Purchases   GWh     106 2   25,971 4   23,404  

Electricity

  Capacity   Sales   MW-Day
(in thousands)
    254 3   1 3   597 3

Electricity

  Capacity   Purchases   MW-Day
(in thousands)
    11 3   2 3   736 3

Electricity

  Congestion   Sales   GWh         136 5   10,212 5

Electricity

  Congestion   Purchases   GWh         1,576 5   181,930 5

Natural gas

  Forwards/Futures   Sales   bcf1         3.3     30.8  

Natural gas

  Forwards/Futures   Purchases   bcf             30.6  

Fuel oil

  Forwards/Futures   Sales   barrels         250,000     120,000  

Fuel oil

  Forwards/Futures   Purchases   barrels         625,000     120,000  
   

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(in millions)  
Instrument
  Purpose
  Type of Hedge
  Notional
Amount

  Expiration Date
 
   

Amortizing interest rate swap

  Convert floating rate (6-month
LIBOR) debt to fixed rate
(3.175%) debt
  Cash flow   $ 160     June 2016  
   
1
The terms gigawatt-hours and billion cubic feet are referred to as GWh and bcf, respectively.

2
EME's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the coal plants which meet the normal purchases and sales exception and are accounted for on the accrual method.

3
EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Reliability Pricing Model (RPM) auction is not accounted for as a derivative.

4
EME also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.

5
Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

Included in trading activities in the preceding table, EME shows net the volume of energy trading activities that are physically settled. Gross purchases and sales totaled 3,944 GWh, 3,791 GWh and 4,080 GWh during 2010, 2009 and 2008, respectively.

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Fair Value of Derivative Instruments

The following table summarizes the fair value of derivative instruments reflected on EME's consolidated balance sheets:

December 31, 2010  
 
  Derivative Assets   Derivative Liabilities    
 
(in millions)
  Short-term
  Long-term
  Subtotal
  Short-term
  Long-term
  Subtotal
  Net Assets
 
   

Non-trading activities

                                           
 

Cash flow hedges

  $ 54   $ 2   $ 56   $ 10   $ 25   $ 35   $ 21  
 

Economic hedges

    77     2     79     71         71     8  

Trading activities

    184     103     287     148     29     177     110  
       

    315     107     422     229     54     283     139  

Netting and collateral received1

    (269 )   (37 )   (306 )   (223 )   (35 )   (258 )   (48 )
       

Total

  $ 46   $ 70   $ 116   $ 6   $ 19   $ 25   $ 91  
   

 

December 31, 2009  
 
  Derivative Assets   Derivative Liabilities    
 
(in millions)
  Short-term
  Long-term
  Subtotal
  Short-term
  Long-term
  Subtotal
  Net Assets
 
   

Non-trading activities

                                           
 

Cash flow hedges

  $ 240   $ 17   $ 257   $ 69   $ 6   $ 75   $ 182  
 

Economic hedges

    202     8     210     180         180     30  

Trading activities

    234     111     345     182     41     223     122  
       

    676     136     812     431     47     478     334  

Netting and collateral received1

    (479 )   (55 )   (534 )   (426 )   (32 )   (458 )   (76 )
       

Total

  $ 197   $ 81   $ 278   $ 5   $ 15   $ 20   $ 258  
   
1
Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally enforceable master netting agreement exists with a derivative counterparty.


Income Statement Impact of Derivative Instruments

The following table provides the activity of accumulated other comprehensive income, containing information about the changes in the fair value of cash flow hedges, to the extent

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effective, and reclassification from accumulated other comprehensive income into results of operations:

 
  Cash Flow Hedge Activity1    
 
  Income Statement
Location

(in millions)
  2010
  2009
 

Accumulated other comprehensive income derivative gain at January 1

  $ 175   $ 398    

Effective portion of changes in fair value

    92     79    

Reclassification from accumulated other comprehensive income to net income

    (240 )   (302 ) Operating revenues
         

Accumulated other comprehensive income derivative gain at December 31

  $ 27   $ 175    
 
1
Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at December 31, 2010 and 2009 were $16 million and $105 million, respectively.

The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.

EME recorded net gains (losses) of $(4) million, $24 million and $7 million in 2010, 2009 and 2008, respectively, in operating revenues on the consolidated statements of income representing the amount of cash flow hedge ineffectiveness.

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

 
   
  December 31,  
 
  Income Statement Location
 
(in millions)
  2010
  2009
 
   

Economic hedges

  Operating revenues   $ 8   $ 34  

  Fuel costs     2     18  

Trading activities

  Operating revenues     114     47  
   

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Energy Trading Derivative Instruments

The fair value of outstanding energy trading derivative instruments at December 31, 2010 and 2009 was $110 million and $122 million, respectively. The change in the fair value of trading contracts was as follows:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
 
   

Fair value of trading contracts at beginning of periods

  $ 122   $ 112  

Net gains from energy trading activities

    114     47  

Amount realized from energy trading activities

    (131 )   (44 )

Other changes in fair value

    5     7  
       

Fair value of trading contracts at end of periods

  $ 110   $ 122  
   


Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at December 31, 2010 and, accordingly, the contingent features described above do not currently have liquidity exposure. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.


Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. EME nets counterparty receivables and payables where balances exist under master netting arrangements. EME presents the portion of its margin and collateral deposits netted with its derivative positions

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on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:

 
  December 31,  
(in millions)
  2010
  2009
 
   

Collateral provided to counterparties

             
 

Offset against derivative liabilities

  $ 4   $ 49  
 

Reflected in margin and collateral deposits

    59     120  

Collateral received from counterparties

             
 

Offset against derivative assets

    52     124  
   


Commodity Price Risk Management

EME's merchant operations create exposure to commodity price risk, which reflects the potential impact of a change in the market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided by a risk management committee, to ensure compliance with EME's risk management policies. EME uses estimates of the variability in gross margin to help identify, measure, monitor and control its overall market risk exposure and earnings volatility with respect to hedge positions at the coal plants and the merchant wind projects, and uses "value at risk" metrics to help identify, measure, monitor and control its overall risk exposure in respect to its trading positions. These measures allow management to aggregate overall commodity risk, compare risk on a consistent basis and identify changes in risk factors. Value at risk measures the possible loss, and variability in gross margin measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers volumetric exposure limits. When appropriate, EME manages the spread between the electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives.


Interest Rate Risk Management

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


Credit Risk

In conducting EME's hedging and trading activities, EME enters into transactions with utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with market price changes occurring since the original contract was executed if the nonperforming counterparty were unable to pay the resulting damages owed to EME. Further, EME would be exposed to the risk of

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non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.

To manage credit risk, EME evaluates the risk of potential defaults by counterparties. Credit risk is measured as the loss that EME would expect to incur if a counterparty failed to perform pursuant to the terms of its contractual obligations. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.

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

The majority of the coal for the coal plants is purchased from suppliers under contracts which may be for multiple years. None of the coal suppliers to the coal plants have investment grade credit ratings and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier.

The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 66%, 48% and 50% of EME's consolidated operating revenues for the years ended December 31, 2010, 2009 and 2008, respectively. Moody's Investors Service, Inc. (Moody's) rates PJM's debt Aa3. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At December 31, 2010 and 2009, EME's account receivable due from PJM was $64 million and $50 million, respectively.

For the years ended December 31, 2010, 2009 and 2008, a second customer, Constellation Energy Commodities Group, Inc. accounted for less than 10%, 16% and 10%, respectively, of EME's consolidated operating revenues. Sales to Constellation are primarily generated from the coal plants and consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB- by Standard & Poor's Ratings Services (S&P) and Baa3 by Moody's. At December 31, 2010 and 2009, EME's account receivable due from Constellation was $32 million and $36 million, respectively.

For the year ended December 31, 2008, EME also derived 12% of its consolidated operating revenues from the sale of energy, capacity and ancillary services generated at the Midwest Generation plants to Commonwealth Edison Company under load requirements services contracts.

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Note 7. Income Taxes

Current and Deferred Taxes

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Continuing Operations

                   
 

Current

                   
   

Federal

  $ (288 ) $ (176 ) $ 95  
   

State

    18     (35 )   33  
       
   

Total current

    (270 )   (211 )   128  
       
 

Deferred

                   
   

Federal

  $ 278   $ 187   $ 96  
   

State

    11     40     19  
       
   

Total deferred

    289     227     115  
       
 

Provision for income taxes from continuing operations

    19     16     243  
       

Discontinued operations

    9     (2 )   5  
       

Total

  $ 28   $ 14   $ 248  
   

EME recorded a tax benefit of $16 million in 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for the tax years 1986 through 2002.

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Continuing operations

  $ 178   $ 217   $ 743  

Discontinued operations

    13     (9 )   6  
       

Total

  $ 191   $ 208   $ 749  
   

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The components of net accumulated deferred income tax liability are:

 
  December 31,  
(in millions)
  2010
  2009
 
   

Deferred tax assets

             
 

Accrued charges and liabilities

  $ 201   $ 156  
 

Net operating loss and tax credit carryforwards

    60      
 

Deferred income

        5  
 

Other

    2      
       
   

Total

    263     161  

Deferred tax liabilities

             
 

Basis differences in property

  $ 1,117   $ 821  
 

Derivative instruments

        93  
 

Deferred investment tax credit

    4     5  
 

State taxes

    9     27  
 

Other

    3     6  
       
   

Total

    1,133     952  
       

Deferred tax liabilities and tax credits, net

  $ 870   $ 791  
   

Classification of net accumulated deferred income taxes

             
 

Included in current liabilities

  $ 34   $ 119  
 

Included in non-current liabilities

  $ 836   $ 672  
   


Effective Tax Rate

The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholder:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Provision for income taxes at federal statutory rate of 35%

  $ 62   $ 76   $ 260  

State tax-net of federal benefit (excludes state tax settlement)

    9     7     33  

Production tax credits, net

    (61 )   (55 )   (43 )

Qualified production deduction

    15     (2 )   (13 )

Deferred tax adjustments1

    6          

Resolution of 1986-2002 state tax issues

    (16 )        

Other

    4     (10 )   6  
       

Income tax expense from continuing operations

  $ 19   $ 16   $ 243  
   

Effective tax rate

    11%     7%     33%  
   
1
Deferred tax adjustments in 2010 included $3 million of prior period expenses determined to be immaterial to overall results.

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Accounting for Uncertainty in Income Taxes

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)
  2010
  2009
  2008
 
   

Balance at January 1

  $ 115   $ 144   $ 136  

Tax positions taken during the current year

                   
 

Increases

            8  
 

Decreases

             

Tax positions taken during a prior year

                   
 

Increases

    126     11      
 

Decreases

    (80 )        

Increases (decreases) for settlements during the period

   
(8

)
 
(40

)
 
 

Decreases resulting from a lapse in statute of limitations

             
       

Balance at December 31

 
$

153
 
$

115
 
$

144
 
   

The total amount of unrecognized tax benefits as of December 31, 2010 that, if recognized, would affect the effective tax rate was $148 million. EME believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $9 million within the next 12 months.

Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 remain subject to audit.


Accrued Interest and Penalties

The total amount of accrued interest expense (income) and penalties was $32 million and $12 million as of December 31, 2010 and 2009, respectively. The total amount of interest expense (income) and penalties recognized in income tax expense was $13 million, $(45) million and $8 million for 2010, 2009 and 2008, respectively.


Settlement of Tax Dispute

The Internal Revenue Service examination phase of Edison International's federal income tax returns for tax years 2003 through 2006 was completed in the fourth quarter of 2010, and a revenue agent report was issued. The revenue agent report includes the following EME item:

a proposed adjustment increasing the taxable gain on the 2004 sale of EME's international assets, which, if sustained, would result in federal tax payments of approximately $175 million, including interest and penalties. The Internal Revenue Service has asserted a 40% penalty for understatement of tax liability related to this matter.

Edison International disagrees with the proposed adjustments and filed a protest with the Internal Revenue Service in 2011.

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Note 8. Compensation and Benefit Plans

Employee Savings Plan

A 401(k) plan is maintained to supplement eligible employees' retirement income. The plan received contributions from EME of $14 million in 2010, $13 million in 2009 and $15 million in 2008.


Pension Plans and Postretirement Benefits Other than Pensions

Pension Plans

Noncontributory defined benefit pension plans (the non-union plan has a cash balance feature) cover most employees meeting minimum service requirements. The expected contributions (all by the employer) are approximately $20 million for the year ended December 31, 2011.

Volatile market conditions have affected the value of the trusts established to fund its future long-term pension benefits. The market value of the investments (reflecting investment returns, contributions and benefit payments) within the plan trusts declined 35% during 2008. This reduction in the value of plan assets resulted in a change in the pension plan funding status from overfunded to underfunded and will also result in increased future expense and increased future contributions. Improved market conditions in 2010 and 2009 partially offset the impacts of the 2008 market conditions.

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Information on plan assets and benefit obligations is shown below:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
 
   

Change in projected benefit obligation

             
 

Projected benefit obligation at beginning of year

  $ 243   $ 211  
 

Service cost

    16     15  
 

Interest cost

    14     13  
 

Actuarial loss

    22     10  
 

Benefits paid

    (8 )   (6 )
       

Projected benefit obligation at end of year

 
$

287
 
$

243
 
   

Change in plan assets

             
 

Fair value of plan assets at beginning of year

  $ 128   $ 99  
 

Actual return on plan assets

    20     25  
 

Employer contributions

    24     10  
 

Benefits paid

    (8 )   (6 )
       

Fair value of plan assets at end of year

 
$

164
 
$

128
 
   

Funded status at end of year

 
$

(123

)

$

(115

)
   

Amounts recognized on consolidated balance sheets:

             

Long-term liabilities

  $ (123 ) $ (115 )

Amounts recognized in accumulated other comprehensive income:

             

Prior service cost

  $ 1   $ 1  

Net loss

    47     37  

Accumulated benefit obligation at end of year

 
$

245
 
$

204
 

Pension plans with an accumulated benefit obligation in excess of plan assets:

             

Projected benefit obligation

  $ 287   $ 243  

Accumulated benefit obligation

    245     204  

Fair value of plan assets

    164     128  

Weighted-average assumptions used to determine obligations at end of year:

             

Discount rate

    5.25%     6.0% to 6.25%  

Rate of compensation increase

    4.5% to 6.0%     5.0% to 6.0%  
   

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

Expense components:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Service cost

  $ 16   $ 15   $ 13  

Interest cost

    14     13     12  

Expected return on plan assets

    (10 )   (8 )   (10 )

Net amortization

    2     4     1  
       

Total expense

 
$

22
 
$

24
 
$

16
 
   

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Net loss (gain)

  $ 12   $ (7 ) $ 49  

Prior service cost

            1  

Amortization of net loss

    (2 )   (4 )   (1 )
       

Total in other comprehensive (income) loss

 
$

10
 
$

(11

)

$

49
 
   

Total in expense and other comprehensive (income) loss

 
$

32
 
$

13
 
$

65
 
   

The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2011 are $0.1 million for prior service costs and $3.5 million for net loss.

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

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Discount rate

    6.0%     6.25%     6.25%  

Rate of compensation increase

    4.5% to 6.0%     5.0% to 6.0%     5.0%  

Expected long-term return on plan assets

    7.5%     7.5%     7.5%  
   

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

Years Ending December 31,
(in millions)

   
 
   

2011

  $ 11  

2012

    13  

2013

    15  

2014

    17  

2015

    19  

2016-2020

    123  
   

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Postretirement Benefits Other Than Pensions

Non-union employees retiring at or after age 55 with at least 10 years of service may be eligible for postretirement medical, dental, vision, and life insurance coverage. Eligibility for a company contribution toward the cost of these benefits in retirement depends on a number of factors, including the employee's hire date. The expected contributions (all by the employer) for the postretirement benefits other than pensions are $2 million for the year ended December 31, 2011.

Information on plan assets and benefit obligations is shown below:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
 
   

Change in benefit obligation

             

Benefit obligation at beginning of year

  $ 94   $ 99  

Service cost

    2     2  

Interest cost

    5     5  

Amendments

    11     (2 )

Actuarial (gain) loss

    12     (8 )

Benefits paid

    (2 )   (2 )
       

Benefit obligation at end of year

 
$

122
 
$

94
 
   

Change in plan assets

             

Fair value of plan assets at beginning of year

  $   $  

Employer contributions

    2     2  

Benefits paid

    (2 )   (2 )
       

Fair value of plan assets at end of year

 
$

 
$

 
   

Funded status at end of year

 
$

(122

)

$

(94

)
   

Amounts recognized on consolidated balance sheets:

             

Long-term liabilities

  $ (122 ) $ (94 )

Amounts recognized in accumulated other comprehensive income:

             

Prior service cost (credit)

  $ 8   $ (4 )

Net loss

    23     11  

Weighted-average assumptions used to determine obligations at end of year:

             

Discount rate

    5.5%     6.0%  

Assumed health care cost trend rates:

             

Rate assumed for following year

    9.75%     8.25%  

Ultimate rate

    5.5%     5.5%  

Year ultimate rate reached

    2019     2016  
   

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

Expense components:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Service cost

  $ 2   $ 2   $ 3  

Interest cost

    6     5     6  

Amortization of prior service credit

    (2 )   (1 )   (2 )

Amortization of net loss

    1     1     1  
       

Total expense

  $ 7   $ 7   $ 8  
   

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

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Net loss (gain)

  $ 12   $ (8 ) $ 18  

Prior service cost (credit)

    11     (2 )   (6 )

Amortization of prior service credit

    1     1     3  

Amortization of net loss

    (1 )   (1 )   (3 )
       

Total in other comprehensive (income) loss

  $ 23   $ (10 ) $ 12  
   

Total in expense and other comprehensive (income) loss

  $ 30   $ (3 ) $ 20  
   

The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2011 are $0.7 million for prior service credit and $1.2 million for net loss.

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

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Discount rate

    6.0%     6.25%     6.25%  

Assumed health care cost trend rates:

                   

Current year

    8.25%     8.75%     9.25%  

Ultimate rate

    5.5%     5.5%     5.0%  

Year ultimate rate reached

    2016     2016     2015  
   

Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of December 31, 2010, by $21 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated benefit obligation as of December 31, 2010, by $18 million and annual aggregate service and interest costs by $1 million.

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The following benefit payments are expected to be paid:

Years Ending December 31,
(in millions)

  Before
Subsidy1

  Net
 
   

2011

  $ 2   $ 2  

2012

    3     3  

2013

    4     4  

2014

    4     4  

2015

    5     5  

2016-2020

    39     37  
   
1
Medicare Part D prescription drug benefits.


Discount Rate

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


Plan Assets

Description of Pension and Postretirement Benefits Other Than Pensions Investment Strategies

The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active and passive investment strategies within asset classes. Target allocations for pension plan assets are 30% for United States equities, 16% for non-United States equities, 35% for fixed income, 15% for opportunistic and/or alternative investments and 4% for other investments. Edison International employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches. Risk is managed through diversification among multiple asset classes, managers, styles and securities. Plan, asset class and individual manager performance are measured against targets. Edison International also monitors the stability of its investments managers' organizations.

Allowable investment types include:

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

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

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

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Opportunistic, Alternative, and Other Investments:

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


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

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


Capital Markets Return Forecasts

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


Fair Value of Plan Assets

The plan assets for EME pension are included in the Southern California Edison Company Retirement Plan Trust (Master Trust) assets which include investments in equity securities, U.S. treasury securities, other fixed-income securities, common/collective funds, mutual funds, other investment entities, foreign exchange and interest rate contracts, and partnership/joint ventures. Equity securities, U.S. treasury securities, mutual and money market funds are classified as Level 1 as fair value is determined by observable, unadjusted quoted market prices in active or highly liquid and transparent markets. Common/collective funds are valued at the net asset value (NAV) of shares held. Although common/collective funds are determined by observable prices, they are classified as Level 2 because they trade in markets

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that are less active and transparent. The fair value of the underlying investments in equity mutual funds and equity common/collective funds are based upon stock-exchange prices. The fair value of the underlying investments in fixed-income common/collective funds, fixed-income mutual funds and other fixed income securities including municipal bonds are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. Foreign exchange and interest rate contracts are classified as Level 2 because the values are based on observable prices but are not traded on an exchange. Future contracts trade on an exchange and therefore classified as Level 1. One of the partnerships is classified as Level 2 since this investment can be readily redeemed at NAV and the underlying investments are liquid publicly traded fixed-income securities which have observable prices. The remaining partnerships/joint ventures are classified as Level 3 because fair value is determined primarily based upon management estimates of future cash flows. Other investment entities are valued similarly to common collective funds and are, therefore, classified as Level 2. The Level 1 registered investment companies are either mutual or money market funds. The remaining funds in this category are readily redeemable at NAV and classified as Level 2 and are discussed further in footnote 6 to the pension plan master trust investments table below.


Pension Plan

The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2010 by asset class and level within the fair value hierarchy:

(in millions)
  Level 1
  Level 2
  Level 3
  Total
 
   

Corporate stocks1

  $ 786   $   $   $ 786  

Common/collective funds2

        600         600  

Corporate bonds3

        555         555  

Partnerships/joint ventures4

        155     345     500  

U.S. government and agency securities5

    84     316         400  

Registered investment companies6

    84     169         253  

Other investment entities7

        159         159  

Interest-bearing cash

    5             5  

Other

    2     30         32  
       

Total

  $ 961   $ 1,984   $ 345   $ 3,290  
             

Receivables and payables, net

                      (55 )
                         

Net plan assets available for benefits

                      3,235  
                         

EME's share of net plan assets

                    $ 164  
   

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

(in millions)
  Level 1
  Level 2
  Level 3
  Total
 
   

Corporate stocks1

  $ 678   $   $   $ 678  

Common/collective funds2

        612         612  

Corporate bonds3

        469         469  

Partnerships/joint ventures4

        101     240     341  

U.S. government and agency
securities5

    104     352         456  

Registered investment companies6

    73     58         131  

Other investment entities7

        135         135  

Interest-bearing cash

    5             5  

Foreign exchange contracts

        6         6  

Other

        7         7  
       

Total

  $ 860   $ 1,740   $ 240   $ 2,840  
             

Receivables and payables, net

                      17  
                         

Net plan assets available for benefits

                      2,857  
                         

EME's share of net plan assets

                    $ 128  
   
1
Corporate stocks are diversified. For 2010 and 2009, respectively, performance is primarily benchmarked against the Russell Indexes (63% and 61%) and Morgan Stanley Capital International (MSCI) indexes (37% and 39%).

2
At December 31, 2010 and 2009, respectively, the common/collective assets were invested in equity index funds that seek to track performance of the Standard and Poor's (S&P 500) Index (29% and 33%), Russell 200 and Russell 1000 indexes (28% and 26%) and the MSCI Europe, Australasia and Far East (EAFE) Index (11% and 10%). A non-index U.S. equity fund representing 23% and 20% of this category as of December 31, 2010 and 2009, respectively, is actively managed. Another fund representing 8% and 7% of this category, as of December 31, 2010 and 2009, respectively, is a global asset allocation fund.

3
Corporate bonds are diversified. At December 31, 2010 and 2009, respectively, this category includes $65 million and $52 million for collateralized mortgage obligations and other asset backed securities of which $17 million and $12 million are below investment grade.

4
Partnership/joint venture Level 2 investments consist primarily of a partnership which invests in publicly traded fixed income securities, primarily from the banking and finance industry and U.S. government agencies. Approximately 60% of the Level 3 partnerships are invested in asset backed securities including distressed mortgages. The remaining Level 3 partnerships are invested in small private equity and venture capital funds. Investment strategies for these funds include branded consumer products, early stage technology, California geographic focus, and diversified U.S. and non-U.S. fund-of-funds.

5
Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relate to the Federal National Mortgage Association and the Federal Home Loan Mortgage Corporation.

6
Level 1 of registered investment companies consists of a global equity mutual fund which seeks to outperform the MSCI World Total Return Index. Level 2 of this category primarily consists of (1) short-term, emerging market and high yield bond funds and (2) a hedge fund that invests through liquid instruments in a global diversified portfolio of equity, fixed income, interest rate, foreign currency and commodities markets.

7
At December 31, 2010 and 2009, respectively, 57% and 64% of the other investment entities balance is invested in emerging market equity securities. At December 31, 2010 and 2009, respectively, about 24% and 17% of the assets in this category are invested in domestic mortgage backed securities. Most of the remaining funds invest in below grade fixed income securities including foreign issuers.

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At December 31, 2010 and 2009, approximately 69% and 67%, respectively, of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.

The following table sets forth a summary of changes in the fair value of Level 3 investments for 2010 and 2009:

(in millions)
  2010
  2009
 
   

Fair value, net at beginning of period

  $ 240   $ 111  

Actual return on plan assets:

             
 

Relating to assets still held at end of period

    42     34  
 

Relating to assets sold during the period

    24     6  

Purchases and dispositions, net

    39     89  

Transfers in and/or out of Level 3

         
       

Fair value, net at end of period

  $ 345   $ 240  
   


Stock-Based Compensation

Edison International maintains a shareholder-approved incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. The maximum number of shares of Edison International's common stock authorized to be issued or transferred pursuant to awards under the 2007 Performance Incentive Plan, as amended in 2009, is 21.5 million shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued (carry-over shares). As of December 31, 2010, Edison International had approximately 9 million shares remaining for future issuance under its stock-based compensation plans.


Stock Options

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

Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the option term. Stock options granted in 2007 and later have no dividend equivalent rights except for options granted to Edison International's Board of Directors in 2007. Unless transferred to nonqualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

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

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Expected terms (in years)

    7.3     7.4     7.4  

Risk-free interest rate

    2.0% to 3.2%     2.8% to 3.5%     2.6% to 3.8%  

Expected dividend yield

    3.3% to 4.0%     3.6% to 5.0%     2.3% to 3.9%  

Weighted-average expected dividend yield

    3.8%     5.0%     2.5%  

Expected volatility

    19% to 20%     20% to 21%     17% to 19%  

Weighted-average volatility

    19.8%     20.6%     17.4%  
   

The expected term represents the period of time for which the options are expected to be outstanding and is primarily based on historical exercise and post-vesting cancellation experience and stock price history. The risk-free interest rate for periods within the contractual life of the option is based on a zero coupon U.S. Treasury issued STRIPS (separate trading of registered interest and principal of securities) whose maturity equals the option's expected term on the measurement date. Expected volatility is based on the historical volatility of Edison International's common stock for the lesser of 1) the period from January 1, 2003 through the last month-end prior to the grant date, or 2) the length of the options expected term. The volatility period used was 87 months, 84 months and 72 months at December 31, 2010, 2009 and 2008, respectively.

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

 
   
  Weighted-Average    
 
 
  Stock
Options

  Exercise
Price

  Remaining
Contractual
Term (Years)

  Aggregate
Intrinsic
Value

 
   

Outstanding, December 31, 2009

    3,144,531   $ 31.49              

Granted

    724,657     33.30              

Expired

    (19,840 )   45.66              

Transferred from affiliates

    36,593     34.28              

Forfeited

    (127,080 )   30.48              

Exercised

    (266,424 )   22.11              
                         

Outstanding, December 31, 2010

    3,492,437     32.57     6.04        
                         

Vested and expected to vest at December 31, 2010

    3,401,045     32.58     5.98   $ 28,797,824  
                         

Exercisable at December 31, 2010

    1,923,233     32.98     4.24     16,833,610  
   

At December 31, 2010, there was $4 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately two-and-a-half years.

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Performance Shares

A target number of contingent performance shares were awarded to executives in March 2008, March 2009 and March 2010, and vest at the end of December 2010, 2011 and 2012, respectively. Performance shares awarded contain dividend equivalent reinvestment rights. An additional number of target contingent performance shares will be credited based on dividends on Edison International common stock for which the ex-dividend date falls within the performance period. The vesting of Edison International's performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International's total shareholder return relative to the total shareholder return of a specified group of peer companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International's ranking among these companies. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Edison International also has discretion to pay certain dividend equivalents in Edison International common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares that can be settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the requisite service period based on the fair values determined, except for awards granted to retirement-eligible participants.

The fair value of performance shares is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires various assumptions noted in the following table:

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Equity awards

                   
 

Grant date risk-free interest rate

    1.3 %   1.3 %   3.9 %
 

Grant date expected volatility

    21.6 %   21.4 %   17.4 %

Liability awards1

                   
 

Expected volatility

    20.6 %   21.9 %   19.2 %
 

Risk-free interest rate

                   
   

2010 awards

    0.6 %        
   

2009 awards

    0.3 %   1.1 %    
   

2008 awards

        0.5 %   0.8 %
   
1
The portion of performance shares classified as share-based liability awards are revalued at each reporting period.

The risk-free interest rate is based on the daily spot rate on the grant or valuation date on U.S. Treasury zero coupon issue or STRIPS (separate trading of registered interest and principal of securities) with terms nearest to the remaining term of the performance shares

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and is used as proxy for the expected return for the specified group of peer companies. Expected volatility is based on the historical volatility of Edison International's (and the specified group of peer companies') common stock for the most recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data services provider.

At December 31, 2010, there was $0.7 million (based on the December 31, 2010 fair value of performance shares classified as equity awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.

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

 
  Equity Awards   Liability Awards  
 
  Shares
  Weighted-
Average Grant-
Date Fair Value

  Shares
  Weighted-
Average Fair
Value

 
   

Nonvested at December 31, 2009

    70,408   $ 33.04     70,408        

Granted

    27,437     32.50     27,437        

Forfeited

    (14,449 )   50.87     (14,449 )      

Transferred from affiliates

    354     45.17     354        
                       

Nonvested at December 31, 2010

    83,750     29.84     83,750   $ 34.18  
   


Restricted Stock Units

Restricted stock units were awarded to executives in March 2008, March 2009 and March 2010 and vest and become payable in January 2011, 2012 and 2013, respectively. Each restricted stock unit awarded is a contractual right to receive one share of Edison International common stock, if vesting requirements are satisfied. Restricted stock units awarded contain dividend equivalent reinvestment rights. An additional number of restricted stock units will be credited based on dividends on Edison International common stock for which the ex-dividend date falls within the performance period. The vesting of Edison International's restricted stock units is dependent upon continuous service through the end of the three-calendar-year-plus-two-days vesting period. Vesting is subject to a pro-rated adjustment for employees who are terminated under certain circumstances or retire. Cash awards are substituted to the extent necessary to pay tax withholding or any government levies.

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The following is a summary of the status of Edison International nonvested restricted stock units granted to EME employees:

 
  Restricted
Stock Units

  Weighted-Average
Grant-Date
Fair Value

 
   

Nonvested at December 31, 2009

    101,073   $ 34.00  

Granted

    53,558     33.30  

Forfeited

    (6,762 )   31.73  

Paid Out

    (21,898 )   47.29  

Affiliate transfers—net

    1,421     38.91  
             

Nonvested at December 31, 2010

    127,392     32.23  
   

The fair value for each restricted stock unit awarded is determined as the closing price of Edison International common stock on the grant date.

Compensation expense related to these shares, which is based on the grant-date fair value, is recognized ratably over the requisite service period, except for awards whose holders become eligible for retirement vesting during the service period, in which case recognition is accelerated into the year the holders become eligible for retirement vesting. At December 31, 2010, there was $2 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $1 million in 2011 and $1 million in 2012.

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Supplemental Data on Stock-Based Compensation

 
  Years Ended December 31,  
(in millions, except per award amounts)
  2010
  2009
  2008
 
   

Stock-based compensation expense (benefit)1

                   
 

Stock options

  $ 4   $ 3   $ 6  
 

Performance shares

    2     1     (3 )
 

Restricted stock units

    1     1     1  
 

Other

    2     3     3  
       

Total stock-based compensation expense (benefit)

  $ 9   $ 8   $ 7  
       

Income tax benefits related to stock compensation expense

  $ 4   $ 3   $ 3  

Excess tax benefits2

    1         3  

Stock options

                   
 

Weighted average grant date fair value per option granted

  $ 4.92   $ 3.00   $ 9.88  
 

Fair value of options vested

    3     3     4  
 

Cash used to purchase shares to settle options

    11     1     11  
 

Cash from participants to exercise stock options

    6     1     5  
 

Value of options exercised

    4     0.4     6  
 

Tax benefits from options exercised

    2     0.2     2  

Performance shares classified as equity awards

                   
 

Weighted average grant date fair value per share granted

  $ 32.50   $ 21.06   $ 41.25  
 

Fair value of shares vested

    0.9     0.2     0.7  
 

Value of shares settled

            3  
 

Tax benefits realized from settlement of awards

            1  

Performance shares classified as liability awards

                   
 

Value of shares settled

  $   $   $ 2  
 

Tax benefits realized from settlement of awards

            1  

Restricted stock units3

                   
 

Weighted average grant date fair value per unit granted

  $ 33.30   $ 24.99   $ 48.66  
   
1
Reflected in administration and general on the consolidated statements of income.

2
Reflected in excess tax benefits related to stock-based awards in cash flows from financing activities on the consolidated statements of cash flows.

3
The value of restricted stock units settled was less than $1 million for 2010, 2009 and 2008.


Note 9. Commitments and Contingencies

Power Plant and Other Lease Commitments

EME leases office space, property and equipment under noncancelable lease agreements that expire in various years through 2037.

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Future minimum payments for operating leases at December 31, 2010 are:

Years Ending December 31,
(in millions)

  Homer City
Plant

  Powerton and
Joliet Power
Facilities

  Other Operating
Leases

 
   

2011

  $ 161   $ 151   $ 27  

2012

    160     151     24  

2013

    149     151     29  

2014

    138     151     17  

2015

    107     67     16  

Thereafter

    1,260     267     140  
       

Total future commitments

  $ 1,975   $ 938   $ 253  
   

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

Operating lease expense amounted to $217 million, $209 million and $208 million in 2010, 2009 and 2008, respectively.


Sale-Leaseback Transactions

On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City plant to third-party lessors. Under the terms of the 33.67-year leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City plant, EME has a right of first refusal to acquire the interest at fair market value. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.

On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power facilities located in Illinois to third-party lessors. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EME's subsidiary makes semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, EME has a right of first refusal to acquire the interest at fair market value. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases.

Under the terms of the foregoing sale-leaseback transactions, distributions are restricted by EME's subsidiaries unless specified financial covenants are met. At December 31, 2010, EME's subsidiaries met these covenants. In addition, the lease agreements and the Midwest Generation credit agreement contain covenants that include, among other things, restrictions on the ability of these subsidiaries to incur debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines of business, or engage in transactions for any speculative purpose.

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Other Commitments

Certain other minimum commitments are estimated as follows:

(in millions)
  2011
  2012
  2013
  2014
  2015
 
   

Fuel supply contracts

  $ 482   $ 250   $ 33   $   $  

Coal transportation agreements

    231                  

Gas transportation agreements

    8     8     8     9     8  

Capital expenditures

    182                  

Turbine commitments

    90                  

Other contractual obligations

    85     72     31     5     3  
       

  $ 1,078   $ 330   $ 72   $ 14   $ 11  
   


Fuel Supply Contracts

At December 31, 2010, Midwest Generation and Homer City had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. In January 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments, together with estimated transportation costs under existing agreements, total $34 million for 2011.

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


Coal Transportation Agreements

At December 31, 2010, Midwest Generation and Homer City had contractual agreements for the transportation of coal. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts.


Gas Transportation Agreements

At December 31, 2010, EME had a contractual commitment to transport natural gas. EME's share of the commitment to pay minimum fees under its gas transportation agreement, which has a remaining contract length of seven years, is estimated to aggregate $41 million in the next five years. EME has entered into agreements to re-sell the transportation under this agreement which aggregates $50 million over the same period.

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Capital Expenditures

At December 31, 2010, EME's subsidiaries had firm commitments for capital and construction expenditures primarily related to selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants and the construction of wind projects. EME intends to fund these expenditures through project-level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations. EME has secured $394 million in wind project financing and anticipated U.S. Treasury grants. For further discussion, see Note 5—Debt and Credit Agreements.


Turbine Commitments

To support its renewable program, EME has entered into several agreements for the purchase of turbines. Under one of these agreements, EME's failure to schedule turbine delivery by June 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $21 million charge against earnings. EME has identified a project in which to place these turbines. However, development is not complete, and EME cannot be assured that this project will be constructed.

On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EME against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EME committed to purchase on amended terms 23 wind turbines (aggregating 55 MW), agreed to certain price adjustments on the turbines purchased under the original contract, may elect to deploy up to 60 additional wind turbines (aggregating 144 MW) that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. EME made payments of $20 million and further agreed to payments up to $20 million for settlement of remaining disputes related to turbines purchased.


Other Contractual Obligations

At December 31, 2010, EME and its subsidiaries were party to turbine operations and maintenance agreements, agreements for the purchase of materials used in the operation of environmental controls equipment and a coal cleaning agreement.


Guarantees and Indemnities

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


Environmental Indemnities Related to the Midwest Generation Plants

In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company (Commonwealth Edison) with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The

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indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "—Contingencies—Midwest Generation New Source Review Lawsuit." Except as discussed below, EME has not recorded a liability related to these environmental indemnities.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 223 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2010. While the range of this liability is between $46 million and $67 million , Midwest Generation had recorded a $56 million and $50 million liability at December 31, 2010 and 2009, respectively, for previous, pending and future claims.

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


Environmental Indemnity Related to the Homer City Plant

In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity

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provisions, they are not subject to a maximum potential liability and do not have expiration dates. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review Lawsuit." EME has not recorded a liability related to this indemnity.


Indemnities Provided under Asset Sale and Sale-Leaseback Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At December 31, 2010 and 2009, EME had recorded a liability of $42 million (of which $3 million is classified as a current liability) and $96 million, respectively, related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the assets prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined.

Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. No significant amounts are recorded as a liability for these matters.

In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. No significant amounts are recorded as a liability for these matters.


Contingencies

Environmental Remediation

With respect to potential liabilities arising under CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $3 million at December 31, 2010 for estimated environmental investigation and

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remediation costs for the Midwest Generation plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that require remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future remediation costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.


Midwest Generation New Source Review Lawsuit

In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration (PSD) requirements and of the New Source Performance Standards of the Clean Air Act (CAA), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology (BACT) emissions rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review (NSR) permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard (CPS). Several Chicago-based environmental action groups have intervened in the case.

Nine of the ten counts related to PSD requirements in the complaint were dismissed in March 2010, and the tenth count was also dismissed to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The court did not address (i) other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA, or (ii) the complaint in intervention filed by the Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.

In June 2010, the US EPA, the State of Illinois, and several environmental action groups filed amended complaints similar to the prior complaints, but also seeking to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. Midwest Generation, EME and Commonwealth Edison have filed a motion to dismiss the amended complaints.

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


Homer City New Source Review Lawsuit

In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleges violations of the PSD and Title V provisions of the CAA and its implementing regulations, including requirements contained in the Pennsylvania State Implementation Plan. The PSD counts allege that the prior owners of the Homer City plant performed projects in the 1990s that triggered state and federal PSD permitting requirements by increasing emissions of sulfur dioxide and/or particulate matter. All defendants are alleged to have failed to comply with the PSD permitting requirements for those projects. The complaint also alleges that, as a result of triggering PSD permitting requirements, including the requirement to install controls sufficient to meet BACT emissions rates for sulfur dioxide and/or particulate matter, the owners and operators have been required, but have failed, to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint calls for an injunction ordering Homer City to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or NSR permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. Pennsylvania Department of Environmental Protection (PADEP), the State of New York and the State of New Jersey have intervened in the lawsuit.

Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, Mission Energy Holding Company, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs seek to have their suit certified as a class action and request injunctive relief, the funding of a health assessment study and medical monitoring, compensatory and punitive damages.

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


Insurance

At December 31, 2010 and 2009, EME's subsidiaries had a $10 million receivable each year recorded primarily related to insurance claims from unplanned outages. During 2009 and 2008, $2 million and $6 million, respectively, related to business interruption insurance

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coverage were recorded and have been reflected in other income (expense), net on EME's consolidated statements of income. EME's subsidiaries received $17 million and $9 million in cash payments related to insurance claims during 2010 and 2009, respectively.


Note 10. Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During 2010, Midwest Generation continued its permitting and planning activities for nitrogen oxide (NOx) and sulfur dioxide (SO2) controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois Environmental Protection Agency (Illinois EPA) to allow the installation of SNCR technology on multiple units to meet the NOx 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 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.

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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 Clean Air Transport Rule (Transport Rule) described below. 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.


Greenhouse Gas Regulation

There have been a number of federal and state legislative and regulatory initiatives to reduce greenhouse gas (GHG) emissions. Any climate change regulation or other legal obligation that would require substantial reductions in GHG emissions or that would impose additional costs or charges for the GHG emissions could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, as well as the cost of purchased power, which could adversely affect EME's business.

Significant developments include the following:

In December 2009, the US EPA issued a final finding that certain GHGs, including carbon dioxide, threaten the public health and welfare. The US EPA has issued a proposed rule, known as the "GHG tailoring rule," which generally subjects newly constructed sources of GHG emissions and newly modified existing major sources to the Prevention of Significant Deterioration air permitting program (and later, the Title V permitting program), beginning in January 2011. The current program, which applies to only new or newly modified sources, is not expected to have an immediate effect on EME's existing generating plants. However, regulation of GHG emissions pursuant to this 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.

Under a pending court 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 expected to be in 2015 or 2016. The specific requirements will not be known until the regulations are finalized.

In December 2010, the California Air Resources Board (CARB) finalized regulations establishing a California cap-and-trade program, which include revisions to CARB's mandatory GHG emissions reporting regulation. The regulations and the cap-and-trade

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In December 2010, the Supreme Court agreed to hear a case in which an appellate court found that judicial remedies for nuisance allegedly caused by GHG emissions were appropriate. The Supreme Court's decision may resolve the question of whether or not this type of litigation presents questions capable of judicial resolution or political questions that should be resolved by elected officials.


Transport Rule

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 NOx and SO2 substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule.

The Transport Rule is scheduled to be finalized in 2011. Depending on the approach to emissions allowance trading and allocation adopted by the US EPA, the Transport Rule may provide allowance allocations 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 to reduce SO2 emissions at Units 1 and 2 of the Homer City facilities and, depending on the approach adopted, may also require Homer City to procure a significant amount of additional allowances or curtail operations if it is unable to do so on acceptable terms.


Hazardous Air Pollutant Regulations

In accordance with a consent decree entered in April 2010, the US EPA committed to proposing regulations by March 2011 limiting emissions of Hazardous Air Pollutants (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 available control technology, or MACT standard). Unlike the Clean Air Mercury Rule, 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.

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Water Quality

Clean Water Act

Regulations under the federal Clean Water Act govern critical 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 U.S. Supreme Court decision that held that the US EPA 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. The new regulations will not allow the use of restoration to achieve compliance, but it is unknown whether they will use a cost-benefit analysis for determining the best technology available for compliance.

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. 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. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals. Two different proposed approaches are under consideration. If the US EPA lists these residuals as special wastes subject to regulation as hazardous wastes, as proposed under one alternative, could require EME to incur additional capital and operating costs without assurance that the additional costs could be recovered.


Note 11. Accumulated Other Comprehensive Income

Accumulated other comprehensive income consisted of the following:

(in millions)
  Unrealized
Gains on Cash
Flow Hedges

  Unrecognized
Losses and Prior
Service
Adjustments, Net1

  Accumulated
Other
Comprehensive
Income

 
   

Balance at December 31, 2008

  $ 240   $ (40 ) $ 200  
 

Change for 2009

    (135 )   13     (122 )
       

Balance at December 31, 2009

    105     (27 )   78  
 

Change for 2010

    (89 )   (20 )   (109 )
       

Balance at December 31, 2010

  $ 16   $ (47 ) $ (31 )
   

1
For further detail, see Note 8—Compensation and Benefit Plans.

Included in accumulated other comprehensive income at December 31, 2010 was $26 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $10 million, net of

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tax, of unrealized losses related to interest rate hedges. The maximum period over which an interest rate hedge is designated is through March 31, 2026. The maximum period over which a commodity cash flow hedge is designated is through May 31, 2014.

Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $26 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.


Note 12. Supplemental Cash Flows Information

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Cash paid (received)

                   
 

Interest (net of amount capitalized)

  $ 239   $ 301   $ 295  
 

Income taxes

    (96 )   (131 )   120  
 

Cash payments under plant operating leases

    325     336     337  

Details of assets acquired

                   
 

Fair value of assets acquired

  $ 1   $ 14   $  
 

Liabilities assumed

        3      
       
 

Net assets acquired

  $ 1   $ 11   $  
   

Non-cash activities from consolidation of variable
interest entities

                   
 

Assets

  $ 94   $ 3   $ 3  
 

Liabilities

    99     4     4  

Non-cash activities from deconsolidation of variable
interest entities

                   
 

Assets

  $ 249   $   $  
 

Liabilities

    253          
   

In connection with certain wind projects acquired during the past four years, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments or made payments that were due upon commencement of construction and/or completion of construction scheduled during 2007 through 2011.


Note 13. Restructuring Costs

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

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Note 14. Divestitures

Discontinued Operations

Summarized financial information for discontinued operations is as follows:

 
  Years Ended December 31,  
(in millions)
  2010
  2009
  2008
 
   

Income (loss) before income taxes

  $ 13   $ (9 ) $ 6  

Provision (benefit) for income taxes

    9     (2 )   5  
       

Income (loss) from operations of discontinued foreign
subsidiaries

  $ 4   $ (7 ) $ 1  
   

Tax indemnity payments of $41 million were made in 2010 related to EME's previous sale of an international project. EME recorded discontinued operations income before taxes of $13 million due primarily to expiration of a contract indemnity during 2010 and changes in foreign exchange rates.

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


Note 15. Related-Party Transactions

Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or SCE employees, are shared among all affiliates of Edison International, and the costs of these corporate support services are allocated to all affiliates, including EME. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). In addition, services of Edison International or SCE employees are sometimes directly requested by EME and these services are performed for EME's benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. EME believes the allocation methodologies utilized are reasonable. EME made reimbursements for the cost of these programs and other services, which amounted to $52 million, $55 million and $66 million in 2010, 2009 and 2008, respectively. At December 31, 2010 and 2009, the amount due to Edison International was $13 million and $14 million, respectively.

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

Edison Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission

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Operation & Maintenance is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities and may also earn incentive compensation as set forth in the agreements. EME has investments in wind projects that are accounted for under the equity method for which Edison Mission Operation & Maintenance has entered into operation and maintenance agreements to provide operation and maintenance services for the wind facilities. EME recorded revenues under the operation and maintenance agreements of $23 million for 2010, $26 million for 2009 and $28 million for 2008, reflected in operating revenues on EME's consolidated statements of income. Receivables from affiliates for Edison Mission Operation & Maintenance totaled $5 million and $6 million at December 31, 2010 and 2009, respectively.

EME owns interests in partnerships that sell electricity generated by their project facilities to SCE and others under the terms of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $367 million, $366 million and $686 million in 2010, 2009 and 2008, respectively.

Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a 10-year power sales contract starting in 2013 for the output of a 479 MW gas-fired peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. Construction of the Walnut Creek project cannot begin until offsets for particulate matter (of 10 micrometers or less) and SO2 emissions required by its permits have been obtained. The capital costs to construct this project, if built, excluding interest, are estimated in the range of $500 million to $600 million over a period of 28 months. During 2008, EME recorded a $23 million charge related to the termination of a turbine supply agreement in connection with the Walnut Creek project reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statement of income.

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Note 16. Quarterly Financial Data (unaudited)

(in millions)
  First
  Second
  Third
  Fourth
  Total
 
   

2010

                               
 

Operating revenues

  $ 651   $ 493   $ 691   $ 588   $ 2,423  
 

Operating income (loss)

    130     (46 )   179     44     307  
 

Income (loss) from continuing
operations

    75     (20 )   118     (14 )   159  
 

Income (loss) from operations of
discontinued subsidiaries, net of
tax

    6     3     (5 )       4  
 

Net income (loss)

    81     (17 )   113     (14 )1   163  

2009

                               
 

Operating revenues

  $ 612   $ 557   $ 593   $ 615   $ 2,377  
 

Operating income

    131     88     80     90     389  
 

Income from continuing operations

    53     46     53     49     201  
 

Income (loss) from operations of
discontinued subsidiaries, net of
tax

    3     (7 )   (1 )   (2 )   (7 )
 

Net income

    56     39     52     47     194  
   
1
Reflects a $40 million pre-tax ($24 million, after tax) write-off of capitalized costs at the Powerton Station. For more information, see Note 2—Property, Plant and Equipment.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Omitted pursuant to General Instruction I.(2)(c).


ITEM 11. EXECUTIVE COMPENSATION

Omitted pursuant to General Instruction I.(2)(c).


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

Omitted pursuant to General Instruction I.(2)(c).


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

Omitted pursuant to General Instruction I.(2)(c).


ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

INDEPENDENT ACCOUNTANT FEES

The following table sets forth the aggregate fees billed to EME (consolidated total including EME and its subsidiaries), for the fiscal years ended December 31, 2010 and December 31, 2009, by PricewaterhouseCoopers LLP:

 
  EME and Subsidiaries  
($000)
  2010
  2009
 
   

Audit fees

  $ 3,178   $ 2,962  

Audit related fees1

    53     197  

Tax fees2

    343     385  

All other fees

         
       

Total

  $ 3,574   $ 3,544  
   
1
The nature of the services comprising these fees were assurance and related services related to the performance of the audit or review of the financial statements and not reported under "Audit Fees" above.

2
The nature of the services comprising these fees were to support compliance with federal, state and foreign tax reporting and payment requirements, including tax return review and review of tax laws, regulations or cases.

The Edison International Audit Committee reviews with management and pre-approves all audit services to be performed by the independent accountants and all non-audit services that are not prohibited and that require pre-approval under the Securities Exchange Act. The Edison International Audit Committee's pre-approval responsibilities may be delegated to one or more Edison International Audit Committee members, provided that such delegate(s) presents any pre-approval decisions to the Edison International Audit Committee at its next

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meeting. The Committee has delegated such pre-approval responsibilities to the Committee Chair. The independent auditors must assure that all audit and non-audit services provided to EME and its subsidiaries have been approved by the Edison International Audit Committee.

During the fiscal year ended December 31, 2010, all services performed by the independent accountants were pre-approved by the Edison International Audit Committee, regardless of whether the services required pre-approval under the Securities Exchange Act.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents have been filed as part of this report or, where noted, incorporated by reference:

See Index to Consolidated Financial Statements at Item 8 of this report.

The following financial statement schedules are included in this report:

 
  Page
 

Schedule I—Condensed Financial Information of Parent

  168

Schedule II—Valuation and Qualifying Accounts

  172
 

All other schedules have been omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

The exhibit list below is incorporated herein by reference as the list of exhibits required as part of this report.

The agreements included or incorporated by reference as exhibits to this report contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of "materiality" that are different from "materiality" under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.

EME acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this report not misleading.

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Exhibit No.
  Description
 
    2.1   Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
    2.2   Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
    2.3   Purchase Agreement, dated July 20, 2004, between Edison Mission Energy and Origin Energy New Zealand Limited, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 8-K filed October 4, 2004.
    2.4   Purchase Agreement, dated July 29, 2004, by and among Edison Mission Energy, IPM Eagle LLP, International Power plc, Mitsui & Co., Ltd. and the other sellers on the signature page thereto, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2004.
    3.1   Certificate of Incorporation of Edison Mission Energy, dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K filed October 29, 2001.
    3.1.1   Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy, dated May 4, 2004, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
    3.1.2   Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy, dated August 8, 2007, incorporated by reference to Exhibit 3.1.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2007.
    3.2   Amended By-Laws of Edison Mission Energy, dated April 1, 2008, incorporated by reference to Exhibit 3.2 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2008.
    4.1   Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
    4.1.1   First Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
    4.1.2   Second Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed May 10, 2007.
    4.1.3   Third Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.3 to Edison Mission Energy's Form 8-K filed May 10, 2007.
    4.1.4   Fourth Supplemental Indenture, dated as of August 22, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.4 to Edison Mission Energy's Form S-4 filed September 10, 2007.
 

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Exhibit No.
  Description
 
    4.2   Second Supplemental Indenture, dated as of April 30, 2007, between Edison Mission Energy and The Bank of New York, as trustee, supplementing the Indenture, dated as of June 28, 1999, pursuant to which Edison Mission Energy's 7.73% Senior Notes due 2009 were issued, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 1, 2007.
    4.3   Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed June 8, 2006.
    4.3.1   First Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed June 8, 2006.
    4.3.2   Second Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed June 8, 2006.
    4.4   Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.4.1   Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.4 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.5   Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.5.1   Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.5 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.6   Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I,  LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.12 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.6.1   Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.6 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
 

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Exhibit No.
  Description
 
    4.7   Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I,  LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.7.1   Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.7 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
    4.8   Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
    4.8.1   Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.8 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
    4.9   Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
    4.9.1   Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
    4.9.2   Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.4.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2004.
    4.10   Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
    4.10.1   Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.10 hereto, incorporated by reference to Exhibit 4.9.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2003.
  10.1†   Purchase & Reservation Agreement, dated as of June 4, 2007, between Edison Mission Energy and Suzlon Wind Energy Corporation, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2007.
  10.2†   Supply Agreement, dated as of March 28, 2007, between Edison Mission Energy and Mitsubishi Power Systems Americas, Inc., incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2007.
 

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Exhibit No.
  Description
 
  10.3   Credit Agreement, dated as of June 15, 2006, between Edison Mission Energy, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 8-K filed June 21, 2006.
  10.3.1   Amendment No. 1 to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.3 herein), dated as of May 7, 2007, among Edison Mission Energy, the Lenders party thereto, the Issuing Lenders party thereto, and Citigroup North America Inc., as administrative agent, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
  10.4   Credit Agreement, dated as of April 27, 2004 among Midwest Generation, LLC, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 4.3 to Midwest Generation, LLC's Form 10-Q for the quarter ended March 31, 2004.
  10.4.1   First Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated as of April 18, 2005 among Midwest Generation, LLC, the Lenders referred to therein the Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended March 31, 2005.
  10.4.2   Second Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated as of December 15, 2005, among Midwest Generation, LLC, the Lenders referred to therein and Citicorp North America, Inc. as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.6.2 to Midwest Generation, LLC's Form 10-K for the year ended December 31, 2005.
  10.4.3   Third Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated June 29, 2007, among Midwest Generation, LLC and the Lenders referred to therein and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended June 30, 2007.
  10.5   Security Agreement, dated as of June 15, 2006, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.2 to Edison Mission Energy's Form 8-K filed June 21, 2006.
  10.6   Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
  10.7   Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.16.4 to EME Homer City Generation L.P.'s Form 10-K for the year ended December 31, 2001.
 

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Exhibit No.
  Description
 
  10.8   Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
  10.9   Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000.
  10.10   Reimbursement Agreement, dated as of October 26, 2001, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.15 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
  10.11   Tax Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.
  10.12   Administrative Agreement Re Tax Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.
  31.1*   Certification of the President pursuant to Section 302 of the Sarbanes-Oxley Act.
  31.2*   Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
  32*   Statement Pursuant to 18 U.S.C. Section 1350.
  101**   Financial statements from the annual report on Form 10-K of Edison Mission Energy for the year ended December 31, 2010, filed on February 28, 2011, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Total Equity, (iv) the Consolidated Statements of Comprehensive Income, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements tagged as blocks of text.
 
*
Filed herewith.

**
Furnished, not filed, pursuant to Rule 406T of SEC Regulation S-T.

Confidential treatment granted.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

    EDISON MISSION ENERGY
(REGISTRANT)

 

 

By:

 

/s/ Maria Rigatti

Maria Rigatti
Vice President, Chief Financial Officer and Treasurer

 

 

Date:

 

February 28, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

  Signature
  Title
  Date
   

 

 

 

 

 

 
  /s/ Pedro J. Pizarro

Pedro J. Pizarro
   
President
(Principal Executive Officer)
    
February 28, 2011

 

/s/ Maria Rigatti

Maria Rigatti

 

 
Vice President and Financial Officer
(Principal Financial Officer)

 

  
February 28, 2011

 

/s/ Joanne M. Collins

Joanne M. Collins

 

 
Vice President and Controller
(Controller or Principal Accounting Officer)

 

  
February 28, 2011

 

/s/ W. James Scilacci

W. James Scilacci

 

 
Director

 

  
February 28, 2011

 

/s/ Robert L. Adler

Robert L. Adler

 

 
Director

 

  
February 28, 2011

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Table of Contents

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT



CONDENSED BALANCE SHEETS
(in millions)

 
  December 31,  
 
  2010
  2009
 
   

 

 

 

 

 

 

 

 

Assets

             

Cash and cash equivalents

  $ 427   $ 180  

Affiliate receivables

    91     22  

Other current assets

    5     1  
       
 

Total current assets

   
523
   
203
 

Investments in subsidiaries

   
7,792
   
7,756
 

Other long-term assets

    316     469  
       

Total Assets

 
$

8,631
 
$

8,428
 
   

Liabilities and Shareholder's Equity

             

Accounts payable and accrued liabilities

  $ 75   $ 58  

Affiliate payables

    580     417  
       
 

Total current liabilities

   
655
   
475
 

Long-term debt

   
3,700
   
3,700
 

Long-term affiliate debt

    1,343     1,348  

Deferred taxes and other

    116     144  
       

Total Liabilities

   
5,814
   
5,667
 

Total EME Common Shareholder's Equity

   
2,817
   
2,761
 
       

Total Liabilities and Shareholder's Equity

 
$

8,631
 
$

8,428
 
   

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

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SCHEDULE I


EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT



CONDENSED STATEMENTS OF INCOME
(in millions)

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Operating revenues

  $ 4   $ 6   $ 9  

Operating expenses

    (114 )   (121 )   (124 )
       

Operating loss

    (110 )   (115 )   (115 )

Equity in income from continuing operations of subsidiaries

    463     488     809  

Interest expense and other

    (355 )   (393 )   (398 )
       

Income (loss) before income taxes

    (2 )   (20 )   296  

Benefit for income taxes

    (166 )   (217 )   (205 )
       

Net income attributable to EME common shareholder

  $ 164   $ 197   $ 501  
   

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

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SCHEDULE I


EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT



CONDENSED STATEMENTS OF CASH FLOWS
(in millions)

 
  Years Ended December 31,  
 
  2010
  2009
  2008
 
   

Net cash provided by operating activities

  $ 576   $ 100   $ 215  

Net cash provided by (used in) financing activities

    (245 )   (517 )   219  

Net cash used in investing activities

    (84 )   (152 )   (349 )
       

Net increase (decrease) in cash and cash equivalents

    247     (569 )   85  

Cash and cash equivalents at beginning of period

    180     749     664  
       

Cash and cash equivalents at end of period

  $ 427   $ 180   $ 749  
   

Cash dividends received from subsidiaries

  $ 125   $ 367   $ 206  
   

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

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SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT

Note 1. Basis of Presentation

EME (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements" of this report.


Note 2. Long-term Debt

For a description and details of long-term debt of EME, including the parent company only, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements" of this report.


Note 3. Commitments and Contingencies

For a description of all material contingencies and guarantees of EME, including the parent company only, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitment and Contingencies" of this report.

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SCHEDULE II

EDISON MISSION ENERGY AND SUBSIDIARIES


VALUATION AND QUALIFYING ACCOUNTS
(in millions)

 
   
  Additions    
   
 
Description
  Balance at
Beginning
of Year

  Charged to
Costs and
Expenses

  Charged to
Other
Accounts

  Deductions
  Balance
at End
of Year

 
   

Year Ended December 31, 2010

                               

Uncollectible accounts

                               
 

Customers

  $ 2   $   $ 3 1 $   $ 5  
 

All others

    48             48 2    
       

Total

  $ 50   $   $ 3   $ 48   $ 5  
   

Year Ended December 31, 2009

                               

Uncollectible accounts

                               
 

Customers

  $ 2   $   $   $   $ 2  
 

All others

    48                 48  
       

Total

  $ 50   $   $   $   $ 50  
   

Year Ended December 31, 2008

                               

Uncollectible accounts

                               
 

Customers

  $ 2   $   $   $   $ 2  
 

All others

            48 2       48  
       

Total

  $ 2   $   $ 48   $   $ 50  
   
1
Represents the consolidation of one coal project effective January 1, 2010. For further discussion, see Note 3—Variable Interest Entities.

2
EME filed bankruptcy claims in the amount of $48 million related to the contracts terminated with Lehman Brothers through the termination provisions of its master netting agreements with a Lehman Brothers subsidiary. Such claims were fully reserved and were included net in prepaid expenses and other on EME's consolidated balance sheet. In 2010, EME sold its bankruptcy claims.

172