Edison Mission Energy 2011 10K
 
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, 2011
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 x
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 x
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 x 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. x
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 x
 
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 x
Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 30, 2011: $0. Number of shares outstanding of the registrant's Common Stock as of February 29, 2012: 100 shares (all shares held by an affiliate of the registrant).
The registrant meets the conditions set forth in General Instruction I.(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K under the reduced disclosure format.
DOCUMENTS INCORPORATED BY REFERENCE
None
 



TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

ii

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Walnut Creek Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
 

iii

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

iv

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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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
ACI
activated carbon injection
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
CSAPR
Cross-State Air Pollution Rule
EIA
Energy Information Administration
EME
Edison Mission Energy
EMMT
Edison Mission Marketing & Trading, Inc.
ERCOT
Electric Reliability Council of Texas
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FGD
flue gas desulfurization
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
ISO(s)
independent system operator(s)
Lehman
Lehman Brothers Commodity Services, Inc. and Lehman Brothers Holdings, Inc.
LIBOR
London Interbank Offered Rate
MATS
Mercury and Air Toxics Standards
Midwest Generation
Midwest Generation, LLC
MISO
Midwest Independent Transmission System Operator
MMBtu
million British thermal units

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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
NID
Novel Integrated Desulfurization
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
US EPA
United States Environmental Protection Agency
U.S. Treasury grants
Cash grants, under the American Recovery and Reinvestment Act of 2009
VIE(s)
variable interest entity(ies)



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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:
•
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;
•
volatility of market prices for energy and capacity;
•
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;
•
EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and payment agreements with EME's respective affiliates;
•
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, including compliance with the CPS at Midwest Generation and CAIR or CSAPR (as applicable) and the MATS rule at Midwest Generation and Homer City;
•
EME's significant cash requirements and its limited ability to borrow funds and access the capital markets on reasonable terms;
•
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 availability and creditworthiness of counterparties, and the resulting effects on liquidity in the power and fuel markets in which EME and its subsidiaries operate and/or the ability of counterparties to pay amounts owed to EME in excess of collateral provided in support of their obligations;
•
governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including the market structure rules applicable to each market and price mitigation strategies adopted by ISOs and RTOs;
•
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;
•
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;
•
completion of permitting and construction of EME's capital projects;
•
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;
•
competition in all aspects of EME's business;

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•
operating risks, including equipment failure, availability, heat rate, output, costs of repairs and retrofits, and availability and cost of spare parts;
•
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 ability to attract and retain skilled people.
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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PART I

ITEM 1. BUSINESS

Overview
Edison Mission Energy 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 incorporated under the laws of the State of Delaware. EME is an indirect subsidiary of Edison International, which 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 and gas-fired generating facilities, and renewable energy facilities, (primarily wind projects). As of December 31, 2011, EME's subsidiaries and affiliates owned or leased interests in 43 operating projects with an aggregate net physical capacity of 11,504 MW of which EME's pro rata share was 10,379 MW. At December 31, 2011, EME's subsidiaries and affiliates also had one wind project and one natural gas-fired peaker plant under construction, totaling 80 MW and 479 MW, respectively, of net generating capacity.
At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility, and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at December 31, 2011, $500 million of which mature in 2013. Unless energy and capacity prices increase, EME expects that it will experience further reductions in cash flow and losses in 2012 and subsequent years. EME's liquidity will be strained by a continuation of recent adverse trends, combined with pending debt maturities, higher operating costs and the need to retrofit its coal-fired plants to comply with governmental regulations. To address such a scenario, EME would need to consider all options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EME and its subsidiaries.
Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process undertaken in the fourth quarter of 2011. Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both. For further discussion of these matters, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview."

Location and Available Information
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, 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 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 each 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 the construction of 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 EME and, in the case of utilities, may be 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. The CPS puts the Midwest Generation plants at a disadvantage compared with competing plants not subject to similar regulations, and federal air quality regulations such as CSAPR and the MATS rule will put EME's coal plants, particularly Homer City, at a disadvantage compared to plants utilizing other fuels. Potential future climate change regulations could also put EME's coal plants at a disadvantage compared to power plants utilizing other fuels as well as utilities that may be able to recover climate change compliance costs through rate-base mechanisms. The ability of EME's coal plants to compete can also be affected by future environmental regulations, by governmental and regulatory activities designed to support the construction and operation of power generation facilities fueled by renewable energy sources, and by developments such as shale gas technology that lower the price of other fuels.

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 sales of energy and capacity generated from the coal-fired power plants and a portfolio of natural gas and wind projects.

Overview of Facilities
As of December 31, 2011, EME's operations consisted of ownership or leasehold interests in the following operating projects:

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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)
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

Big Sky
 
Illinois
 
PJM
 
wind
 
100
%
 
240

 
240

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

Community Wind North
 
Minnesota
 
NSPC
 
wind
 
99
%
 
30

 
30

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

Laredo Ridge
 
Nebraska
 
NPPD
 
wind
 
100
%
 
80

 
80

Minnesota Wind projects4
 
Minnesota
 
NSPC/IPLC
 
wind
 
75-99%

3 
73

 
67

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

Pinnacle5
 
West Virginia
 
MDGS/USM
 
wind
 
100
%
 
55

 
55

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

Taloga
 
Oklahoma
 
OGEC
 
wind
 
100
%
 
130

 
130


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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)
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

CONTRACTED POWER PLANTS – International
Doga1
 
Republic of Turkey
 
TEDAS
 
natural gas
 
80
%
 
180

 
144

Total
 
 
 
 
 
 
 
 

 
11,504

 
10,379

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
 
OGEC
 
Oklahoma Gas and Electric Company
 
CECG
 
Constellation Energy Commodities Group, Inc.
 
PC
 
PacifiCorp
 
CSA
 
City of San Antonio
 
PG&E
 
Pacific Gas & Electric Company
 
ERCOT
 
Electric Reliability Council of Texas
 
PJM
 
PJM Interconnection, LLC
 
IPLC
 
Interstate Power and Light Company
 
PSCO
 
Public Service Company of Oklahoma
 
LIPA
 
Long Island Power Authority
 
SCE
 
Southern California Edison Company
 
MDGS
 
Maryland Department of General Services
 
SPS
 
Southwestern Public Service
 
MEC
 
Mid-American Energy Company
 
TEDAS
 
Türkiye Elektrik Dagitim Anonim Sirketi
 
MPC
 
Monongahela Power Company
 
USM
 
University System of Maryland
 
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 
Composed of six individual wind projects.
5 
Two-thirds of project achieved commercial operation in December 2011. The remaining one-third of project achieved commercial operation in January 2012.
At December 31, 2011, the fuel sources for these projects were as follows:
Fuel Source
 
Percentage of EME's
Generation Capacity
Coal
 
68%
Natural gas/oil
 
14%
Renewable energy
 
18%
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 "Item 7. Management's Discussion and Analysis of

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Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Energy Price Risk."
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

1 
Fisk Station
 
Chicago, Illinois
 
owned
 
coal
 
326

1 
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

2 

Will County Station
 
Romeoville, Illinois
 
owned
 
coal
 
761

3 

Peaking Units
 
 
 
 
 
 
 
 
 
Fisk
 
Chicago, Illinois
 
owned
 
oil
 
197

 
Waukegan
 
Waukegan, Illinois
 
owned
 
oil
 
108

 
Total
 
 
 
 
 
 
 
5,477

 

Non-Operating Plant or Site4
 
Location
Collins Station
 
Grundy County, Illinois
Crawford peaker
 
Chicago, Illinois
Joliet peaker
 
Joliet, Illinois
Calumet peaker
 
Chicago, Illinois
Electric Junction peaker
 
Aurora, Illinois
Lombard peaker
 
Lombard, Illinois
Sabrooke peaker
 
Rockford, Illinois
1 
In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014.
2 
The Waukegan Station is composed of Units 7 and 8. Midwest Generation shut down permanently Waukegan Station Unit 6 (100 MW) on December 21, 2007.
3 
The Will County Station is composed 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."
4 
Ceased operations before December 31, 2005.

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

Fuel Supply

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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 has historically ranged between 17 million to 19 million tons. Coal consumption in the current low natural gas price environment may be lower than the historical range. Coal is transported under transportation agreements with Union Pacific Railroad and various short-haul carriers. In late 2011, Midwest Generation signed new agreements, effective January 1, 2012, to provide such fuel transportation on a long-term basis. 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, 2011, Midwest Generation leased approximately 3,400 railcars to transport the coal from the mines to the generating stations under leases with remaining terms that range from one year to eight 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.

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. The business description of Homer City is presented for an understanding of the historical operations of generation from this plant. For a discussion of the status of the Homer City lease, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Homer City Lease."

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. 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. Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver a portion of Homer City's power into the NYISO. To the extent this arrangement is not utilized, Homer City's power is delivered into PJM.

Fuel Supply
Homer City's Units 1 and 2 have historically consumed approximately 2.8 million to 3.3 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 has historically consumed approximately 1.5 million to 2 million tons of coal per year and can consume either raw or ready-to-burn coal. Coal consumption in the current low natural gas price environment may be lower than the historical range. A wet scrubber FGD system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control. In general, the coal purchased for all three units is acquired locally. 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. The CAIR remains in effect until a replacement regulation becomes effective.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO2 or NOX emissions from plant operations will need to be matched by a sufficient amount of SO2 or NOX allowances that are either allocated or purchased in the open market. SO2 allowances under the federal Acid Rain Program cannot be used to satisfy the requirements under CSAPR. In December 2011, the United States Court of Appeals for the District of Columbia granted a stay of CSAPR pending completion of its review of the rule's validity. If the stay is lifted and CSAPR becomes effective, EME expects that additional SO2 allowances under CSAPR will be required for the Homer City plant. The availability and market prices for those allowances are uncertain, but the associated costs could be significant. For additional information, see "Environmental Matters and Regulations—Air Quality."

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Contracted Power Plants–Domestic

Natural Gas
In December 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 became effective on November 23, 2011. Per the settlement, existing co-generation facilities may continue to receive administratively set pricing under a power purchase agreement through July 2015 and participate in three competitive solicitations required to be conducted by each investor-owned utility for new seven-year contracts.

Big 4 Projects
EME owns partnership investments in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company. Because these projects have similar economic characteristics, EME views these projects collectively and refers to them as the Big 4 projects.

Kern River Project
Kern River Cogeneration sells electricity to SCE under an extension of its prior power purchase agreement, such extension having revised pricing. EME expects that this arrangement will be replaced by a new power purchase agreement pursuant to the settlement described above. The Kern River project may operate some of its turbines as merchant generators selling into the California ISO market. Kern River Cogeneration sells steam to Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc., under an agreement with a term equivalent to the power purchase agreement.

Midway-Sunset Project
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, such extension having revised pricing. EME expects that this arrangement will be replaced by a new power purchase agreement pursuant to the settlement described above. The Sycamore project may operate some of its turbines as merchant generators selling into the California ISO market. 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, such extension having revised pricing. EME expects that this arrangement will be replaced by a new power purchase agreement pursuant to the settlement described above. 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. These projects sell electricity to PG&E under power purchase agreements that expire in 2016. The power purchase agreements became effective in December 2011.

Sunrise Project
EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired combined cycle facility in Kern County, California, which EME refers to as the Sunrise project. Sunrise Power sells electricity under a power purchase agreement with the California Department of Water Resources that expires in June 2012. After expiration of that agreement, the Sunrise project may operate as a merchant generator selling into the California ISO market.

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Renewable Energy

Wind
EME owns interests in the following operating wind projects which either sell electricity pursuant to long-term power purchase agreements with third parties with original terms ranging from 10 to 30 years or are operated on a merchant basis. The table below provides the project's power purchase agreement expiration for each contracted wind project, the project's primary RTO or ISO for each merchant wind project, either the expiration of the project's production tax credits or an indication that EME elected to receive a U.S. Treasury grant, and the project's commercial operation or acquisition date.
Wind Plants
 
Power Purchase
Agreement
Expiration Year/RTO or ISO
 
Production Tax Credit Expiration Date
 
Commercial Operation
or Acquisition Date
Big Sky
 
PJM
 
Qualified for U.S. Treasury grant
 
February 2011
Buffalo Bear
 
2033
 
December 2018
 
December 2008
Cedro Hill
 
2030
 
Qualified for U.S. Treasury grant
 
November 2010
Community Wind North1
 
2031
 
Qualified for U.S. Treasury grant
 
May 2011
Crosswinds2
 
20225
 
June 2017
 
June 2007
Elkhorn Ridge
 
2029
 
December 2018
 
March 2009
Forward
 
2017
 
April 2018
 
April 2008
Goat Wind
 
ERCOT
 
Phase I - April 2018; Phase II - qualified for U.S. Treasury grant
 
April 2008/June 2009
Hardin3
 
2027
 
May 2017
 
May 2007
High Lonesome
 
2039
 
Qualified for U.S. Treasury grant
 
July 2009
Jeffers
 
2028
 
October 2018
 
October 2008
Laredo Ridge
 
2031
 
Qualified for U.S. Treasury grant
 
February 2011
Lookout
 
PJM
 
September 2018
 
October 2008
Minnesota4
 
2021-20346
 
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
Pinnacle
 
2031
 
Qualified for U.S. Treasury grant
 
December 2011/January 2012
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
Taloga
 
2031
 
Qualified for U.S. Treasury grant
 
July 2011
Wildorado
 
2027
 
April 2017
 
April 2007
1 
Twelve separate limited liability companies collectively form the wind farm.
2 
Ten separate limited liability companies collectively form the wind farm.
3 
Seven separate limited liability companies collectively form the wind farm.
4 
Thirty-six separate limited liability companies each own a small wind-powered electric generation facility.
5 
Agreement includes a five-year renewal option.
6 
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

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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 that expires in 2019. The Huntington project also sells electricity to Long Island Power Authority under a power purchase agreement that expires in October 2012.

Coal

American Bituminous Project
EME owns a 50% interest in American Bituminous Power Partners, L.P., which owns an 80 MW waste coal facility located in Grant Town, West Virginia, which EME refers to as the Ambit project. Ambit sells electricity to Monongahela Power Company under a power purchase agreement that expires in 2036.

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, after which date the facility is to be conveyed to the Ministry of Energy and Natural Resources of Turkey.

Construction and Development Activities

Walnut Creek Project
In March 2008, Walnut Creek Energy, a subsidiary of EME, was awarded a 10-year power sales agreement starting in 2013 for the output from its Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The contract was issued by SCE through a competitive bidding process. Construction began on the Walnut Creek project in June 2011. The Walnut Creek project is expected to achieve commercial operation in 2013.

Renewable Energy Projects
In the third quarter of 2011, EME acquired 100% of the Broken Bow I (80 MW) and the Crofton Bluffs (40 MW) wind projects located in Nebraska. Construction of the Broken Bow I wind project commenced during the third quarter of 2011 and EME expects the Crofton Bluffs wind project to commence construction in the second quarter of 2012. Each project has entered into a 20-year power purchase agreement with Nebraska Public Power District. EME anticipates that the projects will achieve commercial operation in the fourth quarter of 2012. As part of its plan to obtain third-party equity capital to finance the development of a portion of EME's wind portfolio, on February 13, 2012, Edison Mission Wind sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project and the Crofton Bluffs wind project for consideration expected to include $141 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and completion of project debt financing. The proceeds from outside investors net of costs on the projects to be completed are expected to be distributed to EME and available for general corporate purposes. For additional information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Categories of VIEs—Capistrano Wind Equity Capital-2012."
During the fourth quarter of 2011, EME reduced its development activities and development pipeline as a result of capital resource constraints and more limited market opportunities. For more information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—EME's Renewable Energy Activities."

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, natural 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 and sale of fuels, including natural gas and fuel oil, through intercompany contracts with EME's subsidiaries that own or lease EME's facilities. 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. The objective of these activities is to sell the output of the facilities on

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a forward basis or to hedge the risk of future changes in prices or price differences between different locations. Hedging activities include on-peak and off-peak periods and may include load service requirements contracts with local utilities. Transactions related to hedging activities are designated separately from EMMT's trading activities. Not all contracts entered into by EMMT for hedging purposes qualify as hedges for accounting purposes.
•
Trading—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.

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. 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 exempt wholesale generators 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 exempt wholesale generator 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

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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
EME's 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.

Environmental Matters and Regulations
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. 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."

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 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 Cross-State Air Pollution 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 a replacement regulation becomes effective.
On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule (CSAPR). CSAPR establishes emissions reductions for annual sulfur dioxide (SO2) emissions and annual and ozone season nitrogen oxide (NOx) emissions in two phases: a first phase originally scheduled to be effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.
In December 2011, the United States Court of Appeals for the District of Columbia granted a stay of CSAPR pending

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completion of its review of the rule's validity. Oral argument is scheduled for April 13, 2012, and a court decision is expected during the third quarter of 2012. The court directed the US EPA to continue administering the CAIR until its review is completed.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. If the stay is lifted and CSAPR becomes effective, the amount of actual SO2 or NOx emissions from plant operations will need to be matched by a sufficient amount of SO2 or NOx allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO2 and NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units will need to surrender allowances for each ton of SO2 and NOx emitted or face penalties.
With the staying of CSAPR, CAIR SO2 allowances have been provided and a sufficient supply is available for purchase to permit Homer City to continue operations consistent with 2011 levels. If the stay is lifted, the SO2 allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) would be significantly lower than the amount that would be required based on Homer City's historical emissions. It is unclear at this time whether Homer City would be able to acquire allowances in sufficient quantity to cover its normal operations during Phase I of CSAPR and whether it would be able to pass through the cost of such allowances in the marketplace. Accordingly, despite the stay, Homer City continues to evaluate alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.
Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. Based on preliminary estimates, Homer City expects the cost of such equipment to be approximately $700 million to $750 million. However, construction of these improvements is dependent upon funding from the owner-lessors or other third parties. For further discussion of the Homer City lease and environmental improvements, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Homer City Lease."

Revised 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. In June 2011, Pennsylvania and Illinois submitted their initial recommended attainment/nonattainment designations in connection with the standard. Pennsylvania recommended designating Indiana County, where the Homer City plant is located, as nonattainment for the SO2 NAAQS. Illinois recommended designating parts of Tazewell County (where the Powerton plant is located) and Will and Cook Counties as nonattainment with this standard. The recommended designation for parts of Will and Cook Counties included the area where the Will County plant is located, but not the areas where Midwest Generation's other plants in those counties are located.

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 CPS also specifies the control technologies that are to be installed on some units by specified dates. Midwest Generation must either install the required technology by the specified deadline or shut down the unit. 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. Midwest Generation substantially completed installation of SNCR equipment in 2011 for compliance with the emission limitations. Capital expenditures relating to these controls were $105 million.
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.
Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO2 emissions. Use of dry sorbent injection technology in conjunction with low sulfur coal is expected to require substantially less capital and time to construct 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 Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Midwest Generation Environmental Compliance Plans and Costs."

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Pennsylvania
The Homer City plant was subject to the federal CAIR during 2011 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 as it existed prior to the implementation of CSAPR, in the same manner in which it complies with the federal standards.

Mercury/Hazardous Air Pollutants

Mercury and Air Toxics Standards Rule
In December 2011, the US EPA announced the Mercury and Air Toxics Standards (MATS) rule, limiting emissions of hazardous air pollutants (HAPs) from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on February 16, 2012, and becomes effective on April 16, 2012. EME does not expect that these standards will require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. EME also does not expect that these standards will require Homer City to make additional capital expenditures beyond those that would be required for compliance with CSAPR Phase II.

Illinois
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 0.008 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 will 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.

Pennsylvania
Pennsylvania currently has no state-level mercury regulations.

Ozone

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. In September 2011, President Obama announced that the proposed revision was being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be required to develop and submit SIPs outlining how compliance with the 2008 NAAQS will be achieved. New primary and secondary ozone standards are expected in 2014.
In January 2012, the US EPA indicated that it intended to designate the counties in Illinois where Midwest Generation's coal-fired power plants are located as nonattainment with the 2008 NAAQS. In December 2011, the US EPA indicated that it intended to designate Indiana County, where the Homer City plant is located, as in attainment with the 2008 NAAQS.

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.
Both Pennsylvania and Illinois have submitted their proposed SIP revisions to the US EPA to address regional haze. Illinois proposed 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 proposed that the existing particulate matter emission limits on the Homer City plant, as well as the plant's participation in the CAIR,

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would satisfy the BART requirement in that state. Because the CAIR was scheduled to expire on December 31, 2011, the US EPA proposed, on December 30, 2011, a limited disapproval of Pennsylvania's SIP, as well as a Federal Implementation Plan that would allow the Homer City plant's participation in CSAPR to satisfy the BART requirement. It is unclear how the stay of CSAPR will affect the Pennsylvania SIP. EME believes that the control measures being undertaken to comply with other environmental regulations will likely satisfy the requirements of these SIPs.

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 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. In March 2011, the US EPA proposed standards under the federal Clean Water Act that would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and EME is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants, but are not expected to be material for the Homer City plant, which already has cooling towers.

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 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. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals that could result in their reclassification. For further discussion see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

Climate Change
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, which could adversely affect EME's business.

Federal Legislative/Regulatory Developments
In June 2010, the US EPA issued the Prevention of Significant Deterioration (PSD) 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.

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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 or emissions control requirements that could delay such projects. 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 and would propose performance standards for emissions from new and modified power plants and emissions guidelines for existing power plants. 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. EME's 2011 GHG emissions were approximately 43 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 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 2011, the CARB regulation was officially published, establishing a California cap-and-trade program. The first compliance period under the regulations is for 2013 GHG emissions. CARB regulations implementing a cap-and-trade program, and the cap-and-trade program itself, continue to be the subject of litigation. In December 2011, a federal district court enjoined the Low Carbon Fuel Standard, another AB 32 program regulating the carbon content of transportation fuels, on constitutional commerce clause grounds. Additional litigation challenging the cap-and-trade program on similar grounds is expected, though no suit has been filed to date.
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). EME believes that all of its California facilities meet the SB 1368 standards.

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. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

Employees
At December 31, 2011, EME and its subsidiaries employed 1,783 people, including:
•
approximately 702 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, 2013. 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 179 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, limited sources of capital and expect to incur substantial losses in 2012 and subsequent years.

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At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility, and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity.Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them.
As of December 31, 2011, EME's consolidated debt was approximately $4.9 billion, of which $1.2 billion was nonrecourse project debt of EME's subsidiaries and the balance was senior unsecured debt of EME. In addition, EME's subsidiaries had $2.6 billion of long-term, power plant lease obligations that are due over a period ranging up to 23 years. Compliance with current and forthcoming environmental requirements will add to EME's near-term liquidity needs.
Unless energy and capacity prices increase, EME expects that it will experience further losses and reductions in cash flow in 2012 and subsequent years. EME's liquidity will be strained by a continuation of recent adverse trends combined with pending debt maturities, higher operating costs and the need to retrofit its coal-fired plants to comply with governmental regulations. EME's and Midwest Generation's deteriorating financial results and 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 previous credit facilities, depending on market conditions. In the case of a further downgrade, EME expects that these negative effects would become more pronounced. If cash flow and other means for 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 pay its senior debt as it matures. If EME's credit facilities are not replaced, EME's ability to hedge its merchant coal exposure or carry out its trading activities may also be limited. 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. Homer City is currently restricted from making permitted distributions, including distributions in respect of the equity interests of Homer City or payments under intercompany loans, under the terms of its lease agreements. 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—Dividend Restrictions in Major Financings."
EME receives tax-allocation payments from Edison International only if, and only to the extent that, EME is included in the consolidated tax returns of Edison International and Edison International is able to utilize tax losses and credits generated by EME. EME may be required to make tax-allocation payments to Edison International.
EME's right to receive tax-allocation payments and the amount of and timing of those payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and other factors, including the amount of consolidated taxable income and net operating losses of Edison International, and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International. Edison International has not been able to fully utilize EME's consolidated tax losses and credits as a result of accelerated tax deductions taken by the consolidated group under the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act and SCE's priority over EME in the utilization of available tax benefits. Realization of EME's tax losses and tax credits is not expected to begin again until at least 2013, subject to future changes in tax laws and Edison International's taxable income, and it may take several years before such benefits can be fully utilized. As of December 31, 2011, EME had recorded deferred tax assets of $520 million related to loss carryforwards and unused credits. EME expects to make tax-allocation payments to Edison International during 2012 of approximately $185 million as a result of the reallocation of tax obligations from an expected Edison International consolidated net operating loss in 2011. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes—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 makes and receives tax-allocation payments may be terminated by the immediate parent company at any time, by notice given before the

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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 beginning prior to the notice. For further discussion, see "Liquidity and Capital Resources—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, emissions 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."
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.
EME is required to surrender emission allowances equal to emissions of specific substances in connection with the operation of its facilities. This may require the purchase of allowances, which are subject to price volatility and which could be unavailable.
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 EME's coal plants as a result of environmental regulations, including the CPS, may require material expenditures or unit shutdowns.
Capital expenditures relating to required environmental controls for EME's coal plants (including the CPS, to which all of Midwest Generation's coal-fired generating units are subject) are expected to be significant. In February 2012, EME decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014 and concluded it was less likely to

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install environmental controls at the Waukegan Station and Joliet Unit 6. EME may ultimately decide to shut down the Waukegan Station and Joliet Unit 6, and possibly other units, rather than make improvements. Unit shutdowns could have an adverse effect on EME's business, results of operation and financial condition. For more information about EME's plans for environmental compliance, see "Item 1. Business—Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Midwest Generation Environmental Compliance Plans and Costs," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
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.
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.
The generation and transmission of electricity are dangerous and involve inherent risks of injury to employees and the general public.
Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Injuries caused by such contact can subject EME to liability that, despite the existence of insurance coverage, can be significant. Such liabilities could be significant but are very difficult to predict. The range of possible liabilities includes amounts that could adversely affect EME's liquidity and results of operations.

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 and capacity have declined significantly due largely to lower natural gas prices and have been affected in recent years by increased use of demand response technology, changes in final demand for power during the economic slowdown, and technological developments that have increased access to natural gas shale reserves, resulting 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. 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."

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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 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 multi-year, long-term transportation contract. All of these factors may have an adverse effect on EME's financial condition and results of operations. For additional information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Coal and Transportation Price Risk."
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 capital projects may not be successful.
EME's capital projects are subject to risks including, without limitation, risks related to financing, construction, permitting, and governmental approvals. EME may be required to spend significant amounts before it can determine whether a project is feasible or economically attractive. The timing of such projects 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. 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 facilities that are subject to higher risks of failure or outage, 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 8,000 square feet and expires on November 30, 2016. 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.

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The following table shows, as of December 31, 2011, 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, excluding asset impairment charges, 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
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.

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."


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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 2011, 2010 and 2009. 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. Subsequent to the end of the fiscal year, EME terminated its corporate credit facility. For more information about dividend restrictions, 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,
 
2011
 
2010
 
2009
 
2008
 
2007
Operating Revenues
$
2,180

 
$
2,423

 
$
2,377

 
$
2,811

 
$
2,580

Operating Expenses
 
 
 
 
 
 
 
 
 
Fuel, plant operations and plant operating leases
1,685

 
1,641

 
1,552

 
1,544

 
1,444

Depreciation and amortization
310

 
248

 
236

 
194

 
162

Asset impairments and other charges
1,746

 
45

 
4

 
14

 
6

Administrative and general
180

 
182

 
196

 
207

 
204

 
3,921

 
2,116

 
1,988

 
1,959

 
1,816

Operating income (loss)
(1,741
)
 
307

 
389

 
852

 
764

Equity in income from unconsolidated affiliates
86

 
104

 
100

 
122

 
200

Interest and other income
46

 
30

 
24

 
48

 
103

Interest expense
(323
)
 
(263
)
 
(296
)
 
(279
)
 
(273
)
Loss on early extinguishment of debt
—

 
—

 
—

 
—

 
(160
)
Income (loss) from continuing operations before income taxes
(1,932
)
 
178

 
217

 
743

 
634

Provision (benefit) for income taxes
(856
)
 
19

 
16

 
243

 
219

Income (loss) from continuing operations
(1,076
)
 
159

 
201

 
500

 
415

Income (loss) from operations of discontinued subsidiaries, net of tax
(3
)
 
4

 
(7
)
 
1

 
(2
)
Net Income (Loss)
(1,079
)
 
163

 
194

 
501

 
413

Net Loss Attributable to Noncontrolling Interests
1

 
1

 
3

 
—

 
1

Net Income (Loss) Attributable to EME Common Shareholder
$
(1,078
)
 
$
164

 
$
197

 
$
501

 
$
414


BALANCE SHEET DATA
(in millions)
 
 
December 31,
 
2011
 
2010
 
2009
 
2008
 
2007
Current assets
$
1,941

 
$
1,859

 
$
1,862

 
$
2,661

 
$
1,734

Total assets
8,323

 
9,321

 
8,633

 
9,080

 
7,272

Current liabilities
548

 
524

 
549

 
635

 
454

Long-term debt net of current portion
4,855

 
4,342

 
3,929

 
4,638

 
3,806

Total EME common shareholder's equity
1,662

 
2,817

 
2,761

 
2,684

 
1,923



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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 merchant coal-fired power plants and a portfolio of natural gas and wind projects. EME's operating results were significantly lower in 2011 compared to 2010 due to lower realized energy and capacity prices and generation at the coal plants. Power prices fell in the fourth quarter of 2011 and have continued to fall in 2012, driven by an abundance of low-priced natural gas, weather conditions and a slow economic recovery. Moreover, the abundance of low-priced natural gas has resulted in increased competition from natural gas-fired generating units in the markets in which Midwest Generation operates, and generation from Midwest Generation's plants has been correspondingly affected. Also at the end of 2011, a favorable long-term rail contract that supplied Midwest Generation's fleet expired and was replaced by a higher priced contract. EME expects that Midwest Generation's average fuel cost ($/MWh) will increase by approximately one-third in 2012. Furthermore, Homer City is engaged in discussions with the owner-lessors regarding funding of retrofit expenditures for the Homer City plant that, if successful in providing funding, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Finally, as discussed below, EME recorded significant impairment charges during the fourth quarter of 2011.
At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility, and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at December 31, 2011, $500 million of which mature in 2013.
Unless energy and capacity prices increase, EME expects that it will incur further reductions in cash flow and losses in years subsequent to 2012 as well as in 2012, and a continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its plants to comply with governmental regulations will strain EME's liquidity. To address such scenario, EME would need to consider all options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EME and its subsidiaries. EME's current business plans are focused on liquidity and operating effectively through the current commodity price cycle and on environmental compliance as described below.

Highlights of Operating Results
Net income (loss) attributable to EME common shareholder is composed of the following components:
 
Years Ended
December 31,
 
 
 
Year Ended
December 31,
2009
(in millions)
2011
 
2010
 
Change
 
Net income (loss) attributable to EME common shareholder
$
(1,078
)
 
$
164

 
$
(1,242
)
 
$
197

Less: Non-Core Items - Net of Tax
 
 
 
 
 
 
 
Asset impairments and other charges


 


 


 
—

Homer City
(623
)
 
—

 
(623
)
 
—

Midwest Generation
(386
)
 


 
(386
)
 
—

Wind projects and other charges
(41
)
 
—

 
(41
)
 
—

Write-off of capitalized costs
—

 
(24
)
 
24

 
—

Gain on sale of March Point
5

 
—

 
5

 
—

Settlement of tax disputes
—

 
16

 
(16
)
 
6

Income (loss) from discontinued operations
(3
)
 
4

 
(7
)
 
(7
)
Total non-core items
(1,048
)
 
(4
)
 
(1,044
)
 
(1
)
Core Earnings (Loss)
$
(30
)
 
$
168

 
$
(198
)
 
$
198

EME's earnings (losses) are prepared in accordance with GAAP. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with analysts and

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investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as net income attributable to EME's shareholder excluding income (losses) 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.
EME had a core loss in 2011 compared to core earnings in 2010 primarily due to the following pre-tax items:
•
$206 million and $122 million decreases in Midwest Generation and Homer City income, respectively, primarily due to lower average realized energy and capacity prices and generation.
•
$60 million increase in interest expense due to new energy project financings ($33 million) and lower capitalized interest ($27 million).
•
$36 million decrease in energy trading due to reduced revenues from trading power contracts and the allocation to Homer City of benefits from an arrangement that allows EMMT to deliver a portion of Homer City's power into the NYISO (such decrease resulting from that allocation is offset by revenues recognized at Homer City).
•
The decrease was partially offset by an $18 million increase in renewable energy income due to the increase in wind projects in operation coupled with higher generation due to more favorable wind conditions, partially offset by lower realized energy prices at the merchant wind projects.
EME's 2010 core earnings were lower than 2009 primarily due to the following pre-tax items:
•
$36 million decreased income from Midwest Generation 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, a $24 million gain from the sale of bankruptcy claims against Lehman and lower average realized fuel costs. Energy and fuel related unrealized losses in 2010 were $13 million compared to unrealized gains of $45 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.
•
$72 million decreased income from Homer City primarily as a result of unrealized losses in 2010 compared to unrealized gains in 2009, higher coal costs, lower generation and higher plant maintenance costs in 2010, partially offset by higher capacity revenues. Energy related unrealized losses in 2010 were $20 million compared to unrealized gains of $15 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.
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 in 2011 included:
•
An after-tax earnings charge of $623 million ($1,032 million pre-tax) recorded in the fourth quarter of 2011 resulting from the write-off of prepaid rent and leasehold improvements related to the Homer City lease.
•
An after-tax earnings charge of $386 million ($640 million pre-tax) recorded in the fourth quarter of 2011 resulting from the impairment of the long-lived assets of Midwest Generation's Fisk, Crawford and Waukegan Stations.
•
An after-tax earnings charge of $18 million ($30 million pre-tax) recorded in the fourth quarter of 2011 related to the write-down of five wind projects, totaling 158 MW of generating capacity.
•
An after-tax earnings charge of $23 million ($36 million pre-tax) in 2011 resulting primarily from EME's decision to

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reduce its development pipeline and ongoing development activities.
•
An earnings benefits of $5 million in 2011 from the sale of the March Point project.
Non-core items in 2010 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 related to a change in air emissions control technology selection at the Powerton Station.
For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Asset Impairments and Other Charges."

Midwest Generation Environmental Compliance Plans and Costs
During 2011, Midwest Generation continued to advance necessary activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation does not anticipate a material change to its current approach in order to comply with the MATS rule. Midwest Generation expects to continue to develop and implement a compliance program that includes the operations of ACI systems, upgrades to particulate removal systems and the use of dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NOx and SO2 as well as for HAPs, such as mercury, acid gas and non-mercury metals.
A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. Decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2 emissions, including those that have received permits, are subject to a number of factors, such as market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation may also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Decisions about any particular combination of retrofits and shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable regulations. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014 and concluded it was less likely to retrofit the Waukegan Station rather than the larger Powerton, Joliet and Will County Stations. As a result, EME recorded an impairment charge of $640 million at December 31, 2011 related to the Crawford, Fisk and Waukegan Stations. For further discussion, see "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Midwest Generation Stations" and “Item 8. Edison Mission Energy Notes to Consolidated Financial Statements—Note 13. Asset Impairments and Other Charges.” Units that are not retrofitted may continue to operate until required to shut down by applicable regulations or operate with reduced output.
In connection with its decision to close the Fisk and Crawford Stations, Midwest Generation entered into a Memorandum of Understanding with the City of Chicago, acting through the Commissioner of Health, which acknowledges that the cessation of coal-fired electric generation at the Fisk and Crawford Stations will achieve the objectives of the proposed Chicago Clean Power Ordinance without a need to pass the proposed Clean Power Ordinance or similar ordinances (recognizing that such agreement cannot bind the Chicago City Council or its members). Midwest Generation and the City of Chicago have also agreed to collaborate with key stakeholders to consider potential future uses, ownership and sources of external funding to transition the sites for such uses. The closure of the Fisk and Crawford Stations will be subject to review for reliability by PJM Interconnection LLC, the regional transmission organization that controls the area where these plants are located. In total, Midwest Generation estimates 150 to 180 employees will be affected. The timing and amount of severance benefits, if any, will be determined after completion of review of personnel based on seniority and other factors and, in the case of the Crawford Station, the amount may be affected by the timing of the plant closure. Other obligations related to the Fisk and Crawford Stations could be affected by the plant closing, including sales of capacity, for which Midwest Generation is unable to reasonably estimate the impact, or range of impacts, that could be incurred. Midwest Generation does not expect to incur future capital expenditures to close these plants.
Based on work to date, Midwest Generation estimates the cost of retrofitting the large stations (Powerton, Joliet Units 7 and 8 and Will County) 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 up to approximately $628 million. The cost of

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retrofitting Joliet Unit 6 is not included in the large unit amounts as it is less likely that Midwest Generation will make retrofits for this unit. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. For further discussion related to EME's impairment policy on the unit of account, see "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets."
In February 2012, Midwest Generation received an extension of its permit to install a dry sorbent injection system at the Powerton Station.

Homer City Lease
Homer City engaged a financial advisor and conducted a bidding process to obtain capital funding from third parties during the second half of 2011 to partially finance the installation of the environmental improvements. During the fourth quarter of 2011, such efforts failed to obtain sufficient interest from market participants necessary to fund the capital needed to make such improvements under the current lease arrangement. Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete retrofits. EME is under no legal obligation to, and has chosen not to, provide funding. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Consequently, Homer City's ability to install environmental compliance equipment will be dependent on funding from the owner-lessors or third parties. Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both.
There is no assurance that an agreement will be reached with the owner-lessors or the existing secured lease obligation bondholders on funding the capital improvements. Homer City believes it is unlikely to meet the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2012 and will be unable to make the required equity rent payment. There is no assurance that subsequent rent payments will be made. Under the sale-leaseback documents, rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to secured lease obligation bondholders, while equity rent is paid to the owner-lessors. In order to pay equity rent, among other requirements, Homer City must meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). A failure to pay equity rent does not entitle the owner-lessors to foreclose upon Homer City's leasehold interest, but it does result in the suspension of Homer City's ability to make permitted distributions. Moreover, Homer City would be permanently restricted in its ability to make permitted distributions if a failure to pay equity rent when due was not cured within nine months, or even if cured, occurred more than one additional time during the term of the lease. Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. Also, failure by Homer City to pay equity rent when due in April 2012 could trigger termination of the $48 million senior rent reserve letter of credit. Homer City would then be required to fund the senior rent reserve, and failure to do so could entitle counterparties to seek available remedies under the sale-leaseback documents, including termination or foreclosure upon the leasehold interest. As a result of the expectation that EME is likely to lose substantially all beneficial economic interest in and material control of the Homer City plant, EME recorded an impairment charge of $1,032 million for the fourth quarter of 2011. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Asset Impairments and Other Charges."
Included in the consolidated financial statements are the assets and liabilities related to Homer City. In the event that EME no longer controls Homer City, EME will record a loss on disposition of assets and liabilities and likely classify Homer City as a discontinued operation. The loss on disposition will be determined based on the assets and liabilities at the date of disposition and an assessment whether any ongoing contingencies exist. For further discussion, see "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Homer City Plant" and “Item 8. Edison Mission Energy Notes to Consolidated Financial Statements—Note 13. Asset Impairments and Other Charges.”
As a result of the financial outlook of Homer City, as previously discussed, EME's subsidiary, EMMT, has ceased to enter into hedging activities related to future power sales, but continues to enter into energy and capacity transactions on behalf of Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer City. In the case of capacity, EMMT has sold Homer City capacity in the annual PJM base residual auctions through May 2015. If Homer City were to default on its obligations to supply capacity, then EMMT would be liable to PJM to supply that capacity, and failure to do so would expose EMMT to penalties under the PJM tariffs. If one or more of the Homer City units were to be

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unavailable as a capacity resource and EMMT did not fulfill this obligation through market transactions, then EMMT would be required to refund any capacity payments received and would be assessed by PJM a penalty equal to the greater of 20% of the capacity payments or $20 per MW-day.

Renewable Energy Activities
Recent developments related to EME's renewable financing and development activities include:
•
On December 21, 2011, EME closed a $242 million portfolio financing of three contracted wind projects representing 204 megawatts of generation capacity previously funded entirely with equity. Funding available in the amount of $110 million from the term loan facility, net of transaction costs, was distributed to EME in 2011 and approximately $95 million, net of transaction costs, of available funds is expected to be distributed in the first quarter of 2012 when the Pinnacle project achieves certain completion milestones.
•
As part of its plan to obtain third-party equity capital to finance the development of a portion of EME's wind portfolio, on February 13, 2012, Edison Mission Wind sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in Nebraska) for consideration expected to include $141 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and completion of project debt financing. The proceeds from outside investors net of costs on the projects to be completed are expected to be distributed to EME and available for general corporate purposes. For additional information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Categories of VIEs—Capistrano Wind Equity Capital-2012."
During the fourth quarter of 2011, EME significantly reduced development of renewable energy projects to conserve cash and in light of more limited market opportunities. As a result, EME reduced staffing and has undertaken efforts to reduce funding joint development projects, thereby reducing the development pipeline of potential wind projects to a projected installed capacity to approximately 1,300 megawatts. These changes triggered charges of $34 million. In addition, management has reviewed the Storm Lake project and four small wind projects in Minnesota, and based on an expected future increase in operating costs and declines in long-term power prices that the projects could potentially realize following the term of the power purchase agreements, EME has recorded an impairment charge of $30 million. For additional information on renewable energy projects, see "Liquidity and Capital Resources—Capital Investment Plan," "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Selected Wind Projects," and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Asset Impairments and Other Charges."

Environmental Regulation Developments
For additional discussion of environmental regulation developments, see “Item 1. Business—Environmental Matters and Regulations" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

RESULTS OF OPERATIONS

Results of Continuing Operations

Overview
EME operates in one line of business, independent power production. The following table shows the adjusted operating income (loss) (AOI) of EME's projects:

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Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Midwest Generation plants
$
(542
)
 
$
264

 
$
340

Homer City plant1
(1,040
)
 
114

 
186

Renewable energy projects
39

 
51

 
53

Energy trading1
74

 
110

 
49

Big 4 projects
44

 
52

 
46

Sunrise
32

 
33

 
37

Doga
26

 
15

 
8

March Point
8

 
17

 
11

Westside projects
7

 
1

 
4

Other projects
9

 
9

 
9

Other operating expense2
(36
)
 
—

 
—

 
(1,379
)
 
666

 
743

Corporate administrative and general
(140
)
 
(145
)
 
(163
)
Corporate depreciation and amortization
(24
)
 
(19
)
 
(15
)
AOI3
$
(1,543
)
 
$
502

 
$
565

1 
Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver a portion of Homer City's power into the NYISO. To the extent this arrangement is not utilized, Homer City's power is delivered into PJM.
2 
Primarily related to EME's decision to reduce its development pipeline and ongoing development activities. For additional information, see "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Selected Wind Projects" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 13. Asset Impairments and Other Charges."
3 
AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net 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 loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.
The following table reconciles AOI to operating income (loss) as reflected on EME's consolidated statements of operations:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
AOI
$
(1,543
)
 
$
502

 
$
565

Less:
 
 
 
 
 
Equity in income of unconsolidated affiliates
86

 
104

 
100

Dividend income from projects
30

 
19

 
12

Production tax credits
66

 
62

 
56

Other income, net
15

 
9

 
5

Net loss attributable to noncontrolling interests
1

 
1

 
3

Operating Income (Loss)
$
(1,741
)
 
$
307

 
$
389


Adjusted Operating Income from Consolidated Operations

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

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Years Ended December 31
(in millions)
2011
 
2010
 
2009
Operating Revenues
$
1,286

 
$
1,479

 
$
1,487

Operating Expenses
 
 
 
 
 
Fuel1
512

 
519

 
547

Plant operations
456

 
448

 
396

Plant operating leases
75

 
75

 
75

Depreciation and amortization
117

 
114

 
109

Asset impairments and other charges
650

 
42

 
2

Administrative and general
22

 
22

 
21

Total operating expenses
1,832

 
1,220

 
1,150

Operating Income
(546
)
 
259

 
337

Other Income
4

 
5

 
3

AOI
$
(542
)
 
$
264

 
$
340

Statistics2
 
 
 
 
 
Generation (in GWh)
 
 
 
 
 
Energy contracts
28,145

 
29,798

 
28,977

Load requirements services contract
—

 
—

 
1,333

Total
28,145

 
29,798

 
30,310

Aggregate plant performance
 
 
 
 
 
Equivalent availability
82.9
%
 
82.2
%
 
85.3
%
Capacity factor
62.2
%
 
62.3
%
 
63.3
%
Load factor
75.0
%
 
75.8
%
 
74.2
%
Forced outage rate
5.3
%
 
6.2
%
 
5.8
%
Average realized price/MWh
 
 
 
 
 
Energy contracts
$
36.83

 
$
40.12

 
$
41.17

Load requirements services contract
$
—

 
$
—

 
$
62.52

Capacity revenues only (in millions)
$
244

 
$
263

 
$
178

Average realized fuel costs/MWh
$
18.06

 
$
17.17

 
$
18.54

1 
Included in fuel costs were $3 million, $13 million and $63 million in 2011, 2010 and 2009, respectively, related to the net cost of emission allowances.
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 $806 million in 2011 compared to 2010, and decreased $76 million in 2010 compared to 2009. The 2011 decrease in AOI, excluding the $640 million impairment charge previously discussed in "Management's Overview—Highlights of Operating Results," was primarily attributable to lower energy and capacity revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation due to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS. The decline in capacity revenues was due to lower capacity prices from the RPM auction. In addition, the change in AOI was impacted by a $40 million pre-tax charge in 2010 related to the write-off of capitalized engineering and other costs related to a change in air emissions control technology at the Powerton Station and a $24 million gain from the sale of bankruptcy claims against Lehman. The claims originated from power contracts that were terminated in 2008 due to the bankruptcy of Lehman.
The 2010 decrease in AOI from 2009 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 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

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lower emission allowance costs partially offset by higher costs for activated carbon, which is used to reduce mercury emissions. The write-off of capitalized costs at the Powerton Station and the gain from the sale of bankruptcy claims against Lehman also affected the comparison of results between these periods.
Included in operating revenues were unrealized gains (losses) of $3 million, $(6) million and $30 million in 2011, 2010 and 2009, respectively. Unrealized gains (losses) were primarily attributable to economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations. In addition, $10 million and $14 million was reversed from accumulated other comprehensive income and recognized in 2010 and 2009, respectively, related to power contracts with Lehman that were dedesignated as cash flow hedges, subsequently terminated and recorded as unrealized losses in 2008. Unrealized gains (losses) also 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 $(4) million, $(7) million and $15 million in 2011, 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.

Homer City
The following table presents additional data for the Homer City plant:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Operating Revenues1
$
527

 
$
636

 
$
663

Operating Expenses
 
 
 
 
 
Fuel2
269

 
279

 
251

Plant operations
137

 
116

 
103

Plant operating leases
102

 
103

 
102

Depreciation and amortization
21

 
18

 
16

Asset impairments and other charges
1,032

 
1

 
1

Administrative and general
6

 
5

 
4

Total operating expenses
1,567

 
522

 
477

Operating Income (Loss)
(1,040
)
 
114

 
186

AOI
$
(1,040
)
 
$
114

 
$
186

Statistics3
 
 
 
 
 
Generation (in GWh)
9,428

 
11,028

 
11,446

Equivalent availability
75.8
%
 
79.7
%
 
84.7
%
Capacity factor
57.1
%
 
66.8
%
 
69.2
%
Load factor
75.4
%
 
83.8
%
 
81.7
%
Forced outage rate
13.8
%
 
10.8
%
 
9.4
%
Average realized energy price/MWh
$
46.36

 
$
49.04

 
$
48.85

Capacity revenues only (in millions)
$
84

 
$
114

 
$
89

Average fuel costs/MWh
$
28.58

 
$
25.26

 
$
21.89

1 
Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver a portion of Homer City's power into the NYISO. To the extent this arrangement is not utilized, Homer City's power is delivered into PJM.
2 
Included in fuel costs were $9 million, $7 million and $16 million in 2011, 2010 and 2009, respectively, related to the net cost of emission allowances.
3 
For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions."

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AOI from the Homer City plant decreased $1.2 billion in 2011 compared to 2010 and decreased $72 million in 2010 compared to 2009. The 2011 decrease in AOI, excluding the $1,032 million impairment charge as discussed in "Management's Overview—Highlights of Operating Results," was primarily attributable to lower energy revenues, driven by lower generation and average realized energy prices, lower capacity revenues, and higher plant maintenance costs from outages at Units 1 and 2, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts and lower fuel costs. The decline in fuel costs was primarily due to lower generation, mostly offset by higher coal costs. Coal costs increased due to higher coal prices. The Homer City plant continued to have a high forced outage rate during 2011 partially as a result of the steam pipe rupture on Unit 1 and the related precautionary maintenance on Unit 2.
The 2010 decrease in AOI from 2009 was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009 related to 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.
Included in operating revenues were unrealized gains (losses) from hedge activities of $5 million, $(20) million and $15 million in 2011, 2010 and 2009, respectively. Unrealized gains (losses) were primarily attributable to the ineffective portion of hedge contracts at the Homer City plant attributable to changes in the difference between energy prices at the 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).
For additional discussion, see "Management's Overview—Homer City Lease."

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.
Midwest Generation Plants
(in millions)
Years Ended December 31,
2011
 
2010
 
2009
Operating revenues
$
1,286

 
$
1,479

 
$
1,487

Less:
 
 
 
 
 
Load requirements services contract
—

 
—

 
(83
)
Unrealized (gains) losses
(3
)
 
6

 
(30
)
Capacity and other revenues1
(247
)
 
(290
)
 
(181
)
Realized revenues
$
1,036

 
$
1,195

 
$
1,193

Generation—energy contracts (in GWh)
28,145

 
29,798

 
28,977

Average realized energy price/MWh
$
36.83

 
$
40.12

 
$
41.17

Homer City Plant
(in millions)
Years Ended December 31,
2011
 
2010
 
2009
Operating revenues
$
527

 
$
636

 
$
663

Less:
 
 
 
 
 
Unrealized (gains) losses
(5
)
 
20

 
(15
)
Capacity and other revenues
(85
)
 
(115
)
 
(89
)
Realized revenues
$
437

 
$
541

 
$
559

Generation (in GWh)
9,428

 
11,028

 
11,446

Average realized energy price/MWh
$
46.36

 
$
49.04

 
$
48.85

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

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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 presented in the preceding table and renewable energy projects presented in "—Renewable Energy Projects" to consolidated operating revenues is set forth below:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Operating revenues
 
 
 
 
 
Midwest Generation plants
$
1,286

 
$
1,479

 
$
1,487

Homer City plant
527

 
636

 
663

Renewable energy projects
221

 
137

 
141

Other revenues
146

 
171

 
86

Consolidated operating revenues as reported
$
2,180

 
$
2,423

 
$
2,377


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:
Midwest Generation Plants
(in millions)
Years Ended December 31,
2011
 
2010
 
2009
Fuel costs
$
512

 
$
519

 
$
547

Add back:
 
 
 
 
 
Unrealized gains (losses)
(4
)
 
(7
)
 
15

Realized fuel costs
$
508

 
$
512

 
$
562

Generation (in GWh)
28,145

 
29,798

 
30,310

Average realized fuel costs/MWh
$
18.06

 
$
17.17

 
$
18.54

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 is set forth below:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Fuel costs
 
 
 
 
 
Midwest Generation plants
$
512

 
$
519

 
$
547

Homer City plant
269

 
279

 
251

Other
18

 
11

 
(2
)
Consolidated fuel costs as reported
$
799

 
$
809

 
$
796


Statistical Definitions
•
Load requirements services contract generation at the Midwest Generation plants represents a load requirements services contract with Commonwealth Edison, awarded as part of an Illinois auction. The contract commenced on January 1, 2007 and expired in May 2009. In 2010 and 2011, generation sold under load requirements services contracts at the Homer City

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

Renewable Energy Projects
The following table presents additional data for EME's renewable energy projects:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Operating Revenues
$
221

 
$
137

 
$
141

Production Tax Credits
66

 
62

 
56

 
287

 
199

 
197

Operating Expenses

 
 
 
 
Plant operations
78

 
55

 
55

Depreciation and amortization
141

 
89

 
92

Asset impairments and other charges
30

 
3

 
—

Administrative and general
4

 
3

 
3

Total operating expenses
253

 
150

 
150

Equity in income from unconsolidated affiliates
1

 
—

 
—

Other Income
3

 
2

 
3

Net Loss Attributable to Noncontrolling Interests
1

 
—

 
3

AOI1
$
39

 
$
51

 
$
53

Statistics2
 
 
 
 
 
Generation (in GWh)3
5,564

 
3,646

 
3,081

Aggregate plant performance3
 
 
 
 
 
Equivalent availability
91.7
%
 
91.8
%
 
88.7
%
Capacity factor
35.6
%
 
33.0
%
 
31.4
%
1 
AOI is equal to operating income (loss) under GAAP plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, 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

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substantially all of the renewable energy projects.
3 
Includes renewable energy projects that are unconsolidated at EME. Generation excluding unconsolidated projects was 4,816 GWh in 2011, 3,037 GWh in 2010 and 2,514 GWh in 2009.
AOI from renewable energy projects, excluding the $30 million impairment charge previously discussed in "Management's Overview—Highlights of Operating Results," increased $18 million in 2011, and decreased $2 million in 2010 compared to 2009. The 2011 increase was primarily attributable to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to favorable wind conditions during 2011, partially offset by lower realized prices from the merchant wind projects. EME's share of installed capacity of new wind projects that commenced operations during 2011, 2010 and 2009 was 295 MW, 150 MW and 223 MW, respectively.
AOI in 2010 and 2009 included payments from Suzlon Wind Energy Corporation (Suzlon) for availability losses of $2 million and $17 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
AOI from energy trading activities decreased $36 million in 2011 compared to 2010, and increased $61 million in 2010 compared to 2009. The 2011 decrease was partially due to reduced revenues from power trading contracts in 2011 compared to 2010, partially offset by increased congestion revenues due to outages in the PJM markets. The decrease is also partially due to the allocation to Homer City of the benefit of an arrangement that allows EMMT to deliver a portion of Homer City's power into the NYISO. 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 unseasonably cold weather and transmission outages in the New York and PJM markets.

Adjusted Operating Income from Other Projects
The CPUC-approved comprehensive settlement related to power sales from cogeneration facilities became effective in November 2011, and resulted in additional non-recurring adjusted operating income in 2011 totaling $11 million. For additional information, see "Item 1. Business—Contracted Power Plants–Domestic—Natural Gas."
Big 4 Projects.    AOI from the Big 4 projects decreased $8 million in 2011 compared to 2010, and increased $6 million in 2010 compared to 2009. The 2011 decrease was primarily due to lower energy margins at Watson and lower contracted capacity under Midway-Sunset's new power purchase agreement, partially offset by additional revenues due to the settlement agreement discussed above. The 2010 increase was driven by changes in natural gas prices affecting steam revenues and plant maintenance.
Westside Projects.    AOI from the Westside projects increased $6 million in 2011 compared to 2010, and decreased $3 million in 2010 compared to 2009. The 2011 increase was primarily attributable to the new power purchase agreements, which became effective upon the settlement discussed above, and provided higher capacity prices retroactive to 2010. The 2010 decrease was primarily due to higher fuel and maintenance costs partially offset by higher revenues.
Doga.    The 2011 increase in AOI was due to higher distributions resulting primarily from the elimination of restricted cash as a result of the repayment of the remaining project debt. The 2010 increase was 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.
March Point.    The 2011 income was due to the receipt of payment from the sale of the project. The 2010 AOI was primarily due to equity distributions received from the project prior to the sale of EME's ownership interest to its partner.

Corporate Administrative and General Expenses
Corporate administrative and general expenses were lower during the past two years as EME reduced development costs incurred pursuing renewable projects.

Interest Income (Expense)

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Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Interest income
$
1

 
$
2

 
$
7

Interest expense, net of capitalized interest

 

 

EME debt
(257
)
 
(229
)
 
(267
)
Nonrecourse debt
(66
)
 
(34
)
 
(29
)
 
$
(323
)
 
$
(263
)
 
$
(296
)
Interest income decreased $5 million in 2010 from 2009 primarily due to lower interest rates and, to a lesser extent, lower average cash balances.
EME's interest expense increased $60 million in 2011 from 2010 and decreased $33 million in 2010 from 2009. The 2011 increase in interest expense was primarily due to higher debt balances from new project financings and lower capitalized interest. 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. Capitalized interest was $27 million, $54 million and $19 million in 2011, 2010 and 2009, respectively. The 2011 decrease was due to completion of the renewable energy projects under construction in 2010 and 2011. The 2010 increase was the result of increased interest capitalization for renewable energy projects under construction.

Income Taxes
EME's effective tax rates were 44%, 11% and 7%, respectively, for the years ended December 31, 2011, 2010 and 2009. The effective tax rate for 2011 was impacted by production tax credits and estimated state income tax benefits allocated from Edison International. The effective tax rate for 2010 was impacted by production tax credits and the resolution of state tax issues from 1986 through 2002 discussed below. Income taxes in 2011, 2010 and 2009 included tax benefits from production tax credits of $66 million, $62 million and $56 million, respectively. Estimated state income tax benefits allocated from Edison International of $6 million, $7 million and $15 million were recognized for the years ended December 31, 2011, 2010 and 2009, respectively.
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 years 1986 through 2002.
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 results of discontinued operations include 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.

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 $277 million, $367 million and $366 million in 2011, 2010 and 2009, respectively. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Standby Letters of Credit" and "—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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Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity
The following table summarizes available liquidity at December 31, 2011:
(in millions)
Cash and Cash Equivalents
 
Available Under Credit Facilities1
 
Total Available Liquidity
EME as a holding company
$
738

 
$
498

 
$
1,236

EME subsidiaries without contractual dividend restrictions
213

 
—

 
213

EME corporate cash and cash equivalents
951

 
498

 
1,449

EME subsidiaries with contractual dividend restrictions
 

 
 

 
 

Midwest Generation2
213

 
497

 
710

Homer City
84

 
—

 
84

Other EME subsidiaries
52

 
—

 
52

Total
$
1,300

 
$
995

 
$
2,295

1 
Existing credit facilities mature in 2012. For further discussion, see "Management's Overview" and "Item 1A. Risk Factors—Liquidity Risks." The EME credit facility was terminated subsequent to year end.
2 
Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure requirements.
EME, as a holding company, does not directly operate any revenue-producing generation facilities. EME relies on cash distributions and tax payments from its projects and tax benefits received under a tax-allocation agreement with Edison International 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, including the current restrictions on distributions from the Homer City facility, see "—Dividend Restrictions in Major Financings."
The following table summarizes the status of the EME and Midwest Generation credit facilities, which mature in June 2012, at December 31, 2011:
(in millions)
EME
 
Midwest
Generation
Commitments
$
564

 
$
500

Outstanding borrowings
—

 
—

Outstanding letters of credit
(66
)
 
(3
)
Amount available
$
498

 
$
497

Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME may 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 information regarding EME's plan to obtain third-party capital to finance the development of a portion of EME's wind portfolio, see "Management's Overview—Renewable Energy Activities" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Categories of VIEs—Capistrano Wind Equity Capital-2012."

Capital Investment Plan
Forecasted capital expenditures through 2014 by EME's subsidiaries for existing projects and corporate activities are as follows:

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Table of Contents

(in millions)
2012
 
2013
 
2014
Midwest Generation Plants
 
 
 
 
 
Environmental1
$
35

 
$
102

 
$
311

Plant capital
21

 
46

 
16

Walnut Creek Project
229

 
40

 
—

Renewable Energy Projects
114

 
1

 
2

Other capital
22

 
19

 
15

Total
$
421

 
$
208

 
$
344

1 
For additional information, see "Management's Overview—Midwest Generation Environmental Compliance Plans and Costs."

Midwest Generation Capital Expenditures
Midwest Generation plants' projected environmental expenditures would retrofit Powerton Units 5 and 6, Joliet Units 7 and 8 and Will County Units 3 and 4, using dry scrubbing with sodium-based sorbents and upgrading particulate removal systems to comply with CPS requirements for SO2 emissions and the US EPA's regulation on HAP emissions. Decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2 emissions, including those that have received permits, 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. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable regulations. Furthermore, the timing of commencing capital projects may vary from the amounts set forth in the above table. For additional discussion, see "Management's Overview—Midwest Generation Environmental Compliance Plans and Costs."
Plant capital expenditures for Midwest Generation includes capital projects for boiler and turbine controls, major boiler components and electrical systems.

Homer City Capital Expenditures
The capital investment plan set forth above does not include environmental capital expenditures to retrofit the Homer City plant because Homer City does not have the funds for retrofits and has not yet been able to raise capital needed for such retrofits. The funding of Homer City's environmental expenditures will be dependent on external funding. See "Management's Overview—Homer City Lease." Plant capital expenditures for Homer City are projected to be $39 million, $23 million, and $14 million in 2012, 2013, and 2014, respectively.

Walnut Creek Capital Expenditures
In July 2011, EME secured $495 million in construction and term financing for the Walnut Creek project. For additional information, see “Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—2011 Project Financings—Walnut Creek."

Renewable Energy Projects
Construction of the 80 MW Broken Bow I wind project commenced during the third quarter of 2011 and EME expects the 40 MW Crofton Bluffs wind project to commence construction in the second quarter of 2012. Commercial operations of the Broken Bow I and the Crofton Bluffs projects are expected in the fourth quarter of 2012.
On December 21, 2011, EME closed a $242 million financing for a portfolio of three contracted wind projects representing 204 megawatts of generation capacity previously funded entirely with equity. For additional information, see “Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—2011 Project Financings—Tapestry Wind."
For information regarding third-party equity capital raised in February 2012 to finance the development of a portion of EME's wind portfolio, see "Management's Overview—Renewable Energy Activities" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Categories of VIEs—Capistrano Wind Equity Capital-2012."
During the fourth quarter of 2011, EME significantly reduced its development activities to conserve cash and in light of more

41
Table of Contents

limited market opportunities. As a result, EME reduced staffing and has undertaken efforts to reduce funding joint development projects, thereby reducing the development pipeline of potential wind projects to approximately 1,300 MW. 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.

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

Condensed Consolidated Statement of Cash Flows
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Operating cash flow from continuing operations
$
629

 
$
602

 
$
258

Operating cash flow from discontinued operations
(3
)
 
4

 
(7
)
Net cash provided by operating activities
626

 
606

 
251

Net cash provided by (used in) financing activities
277

 
235

 
(714
)
Net cash used in investing activities
(678
)
 
(562
)
 
(548
)
Net increase (decrease) in cash and cash equivalents
$
225

 
$
279

 
$
(1,011
)

Consolidated Cash Flows from Operating Activities
The 2011 increase in cash provided by operating activities from continuing operations was primarily attributable to an increase in U.S. Treasury grants received partially offset by a decrease in operating income due to declining energy prices, increasing operating costs, and higher interest payments due to new energy project financings.
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.

Consolidated Cash Flows from Financing Activities
The change in financing activities is primarily due to the timing of financings and repayment of debt as summarized in the following table:
(in millions)
2011
 
2010
 
2009
Long-Term Debt Financings
 
 
 
 
 
Renewable Energy Projects
$
294

 
$
211

 
$
189

Walnut Creek Project
187

 
—

 
—

Debt Repayments

 

 

Edison Mission Energy
—

 
—

 
(389
)
Midwest Generation
—

 
—

 
(475
)
Renewable Energy Projects
(89
)
 
(33
)
 
(15
)
Other Projects
(18
)
 
(15
)
 
(7
)
Short-Term Debt Financings

 

 

Renewable Energy Projects
32

 
96

 
—

Borrowing held in escrow pending completion of project construction
(97
)
 
—

 
—

Financing costs and others
(32
)
 
(24
)
 
(17
)
Total Cash Used in Financing Activities
$
277

 
$
235

 
$
(714
)

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Consolidated Cash Flows from Investing Activities
The change in investing activities is primarily due to the timing of capital expenditures and investments in other assets as reflected in the following table:
(in millions)
2011
 
2010
 
2009
Capital Expenditures
 
 
 
 
 
Midwest Generation Plants
 
 
 
 
 
Environmental
$
82

 
$
32

 
$
24

Plant capital
21

 
75

 
54

Homer City Plant
 
 
 
 
 
Environmental
4

 
—

 
7

Plant capital
10

 
18

 
19

Walnut Creek Project
258

 
—

 
—

Renewable Energy Projects
298

 
414

 
159

Other capital expenditures
13

 
35

 
20

Investments in other assets
30

 
7

 
279

Other investing activities
(38
)
 
(19
)
 
(14
)
Total Cash Used in Investing Activities
$
678

 
$
562

 
$
548

Credit Ratings
Credit ratings for EME, Midwest Generation and EMMT as of December 31, 2011 were as follows:
 
 
Moody's Rating
 
S&P Rating
 
Fitch Rating
EME1
 
Caa1
 
B-
 
CCC
Midwest Generation2
 
Ba3
 
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 a requirement 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.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

Hedging Activities
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. For further details, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities—Margin and Collateral Deposits."

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Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2011, 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, 2011 could increase by approximately $34 million over the remaining life of the contracts using a 95% confidence level.

Intercompany Tax-Allocation Agreement
EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME received net tax-allocation payments of $213 million, $116 million and $166 million in 2011, 2010 and 2009, respectively. However, EME expects to make tax-allocation payments to Edison International during 2012 of approximately $185 million as a result of the reallocation of tax obligations from an expected Edison International consolidated net operating loss in 2011. For further information, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes—Bonus Depreciation Impact on EME," and "Item 1A. Risk Factors—Liquidity Risks."

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. Except for certain of EME's wind projects in portfolio financings, 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, 2011 or for the 12 months ended December 31, 2011:
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
 
1.18 to 1
As indicated above, the actual senior rent service coverage ratio of Homer City was below the covenant threshold for the 12 months ended December 31, 2011, and Homer City also did not meet the threshold for the prospective two 12-month periods, which currently precludes Homer City from making distributions, including repayment of certain intercompany loans and from paying the equity portion of the rent payment. For additional information, see "Management's Overview—Homer City Lease."

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.


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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 in order to make the equity portion of the rent payment and other restricted payments. Homer City would be permanently restricted in its ability to make distributions if a failure to pay equity rent when due was not cured within nine months, or even if cured, occurred more than one additional time during the term of the lease. EME has not guaranteed Homer City's obligations under the leases. Homer City believes it is unlikely to meet the covenant requirements of its sale-leaseback agreements relating to the payment of equity rent at April 1, 2012, and will be unable to make the required equity rent payment. There is no assurance that subsequent rent payments will be made. For additional information, see "Management's Overview—Homer City Lease."

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 preceding the sale or disposition in question. At December 31, 2011, the maximum permissible sale or disposition of EME assets is calculated as follows:
(in millions)
 
Consolidated Net Tangible Assets
 
Total consolidated assets
$
8,323

Less:
 
Consolidated current liabilities
548

 
$
7,775

10% Threshold
$
778

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.

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, 2011.

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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
$
7,039

 
$
363

 
$
1,594

 
$
1,123

 
$
3,959

Power plant and other operating lease obligations2
2,851

 
337

 
637

 
320

 
1,557

Purchase obligations3:
 
 
 
 
 
 
 
 
 
Midwest Generation fuel supply contracts
518

 
223

 
295

 
—

 
—

Midwest Generation coal transportation agreements4
3,023

 
386

 
659

 
630

 
1,348

Homer City fuel supply contracts
267

 
214

 
53

 
—

 
—

Gas transportation agreements
46

 
7

 
14

 
15

 
10

Capital expenditures
305

 
286

 
19

 
—

 
—

Other contractual obligations
177

 
93

 
65

 
17

 
2

Employee benefit plan contribution5
120

 
21

 
48

 
51

 
—

Total Contractual Obligations6,7
$
14,346

 
$
1,930

 
$
3,384

 
$
2,156

 
$
6,876

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 $2.1 billion over the applicable period of the debt.
2 
At December 31, 2011, 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 
Years subsequent to 2012 represent contracts for minimum volumes without regard to payment of alternative liquidated damages or plant closures.
5 
Amount includes estimated contribution for pension plans and postretirement benefits other than pensions. The estimated contributions beyond 2016 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."
6 
At December 31, 2011, EME had a total net liability recorded for uncertain tax positions of $142 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."
7 
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, 2011, standby letters of credit under EME and its subsidiaries' credit facilities aggregated $177 million and were scheduled to expire as follows: $146 million in 2012 and $3 million in 2013, $10 million in 2017, and $18 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.

Contingencies
EME has contingencies related to the Midwest Generation NSR and other litigation, Homer City NSR and other litigation, and environmental remediation which 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

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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 "Management's Overview—Homer City Lease" and "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Power Plant and Other Lease Commitments."
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, 2011
(in millions)
 
Maturity Date of Lessor Debt
Powerton/Joliet
 
$
1,367

 
PSEG/Citigroup, Inc.
 
$
238

 
$ 460 Series B
 
2016
Homer City
 
$
1,591

 
GECC/Metropolitan Life
 
$
798

 
$ 183 Series A
 
2019
 
 
 

 
Insurance Company
 
 

 
$ 477 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)
2011
 
2010
 
2009
Cash payments under plant operating leases
 
 
 
 
 
Powerton and Joliet Stations
$
151

 
$
170

 
$
185

Homer City plant
160

 
155

 
151

Total cash payments under plant operating leases
$
311

 
$
325

 
$
336

Rent expense
 
 
 
 
 
Powerton and Joliet Stations
$
75

 
$
75

 
$
75

Homer City plant
102

 
103

 
102

Total rent expense
$
177

 
$
178

 
$
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, 2011 and 2010, aggregate prepaid rent on the Powerton and Joliet leases was $760 million and $683 million, respectively. To the extent that EME's cash rent payments are less than the amount levelized, EME reduces the amount of prepaid rent. For further discussion of the Homer City lease, see "Management's Overview—Homer City Lease."
In the event of a default under the leases, each owner-lessor can exercise all its rights under the applicable lease, including repossessing the power plant and seeking monetary damages. Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which generally declines over time and in the case of default may be reduced by the proceeds arising from the sale of the repossessed power plant. A default under the terms of the Powerton and Joliet or Homer City leases could result in a loss of EME's ability to use such power plant. In addition, a default under the terms of the Powerton and Joliet leases would trigger obligations under EME's guarantee of such leases. These events could have an adverse effect on EME's results of operations and financial position.


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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
2012
$
11

 
$
110

 
$
121

2013
12

 
109

 
121

2014
545

 
86

 
631

2015
283

 
40

 
323

2016
483

 
—

 
483

Total
$
1,334

 
$
345

 
$
1,679

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 an adverse effect on EME.


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Table of Contents

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 following table summarizes unrealized gains (losses) from non-trading activities:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Midwest Generation plants
 
 
 
 
 
Non-qualifying hedges
$
(2
)
 
$
(11
)
 
$
40

Ineffective portion of cash flow hedges
1

 
(2
)
 
5

Homer City plant
 
 
 
 
 
Non-qualifying hedges
(1
)
 
(1
)
 
1

Ineffective portion of cash flow hedges
6

 
(19
)
 
14

Total unrealized gains (losses)
$
4

 
$
(33
)
 
$
60

At December 31, 2011, cumulative unrealized gains of $7 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to 2012.

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 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 net fair value of commodity derivatives used for non-trading purposes at December 31, 2011 was $42 million. A 10% change in the market price of the underlying commodity at December 31, 2011 would increase or decrease the net fair value of non-trading commodity derivatives by approximately $26 million.
The net fair value of derivatives used for trading purposes at December 31, 2011 was $107 million. A 10% change in the market price of the underlying commodity at December 31, 2011 would increase or decrease the net fair value of trading contracts by approximately $19 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 56% and 11%, respectively, of derivative assets and liabilities measured at fair value before the impact of offsetting collateral and netting as of December 31, 2011.

Commodity Price Risk

Introduction

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Table of Contents

EME's merchant operations are exposed 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
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. Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and ERCOT.
The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated:
 
24-Hour Average Historical Market Prices1
 
2011
 
2010
 
2009
Midwest Generation plants
 
 
 
 
 
Northern Illinois Hub
$
33.21

 
$
33.12

 
$
28.68

Homer City plant
 
 
 
 
 
PJM West Hub
$
43.57

 
$
46.56

 
$
38.75

Homer City Busbar
39.58

 
39.18

 
34.27

1 
Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM West Hub using historical hourly day-ahead 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, 2011:
 
24-Hour Forward Energy Prices1
 
Northern
Illinois Hub
 
PJM West Hub
2012 calendar "strip"2
$
29.75

 
$
38.85

2013 calendar "strip"2
$
31.41

 
$
41.26

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.
Power prices at the Northern Illinois Hub fell in the fourth quarter of 2011 and continued to fall in 2012 due to an abundance of low-priced natural gas and the sales volume from the Midwest Generation plants has been correspondingly affected. 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.
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, 2011 for electricity expected to be generated in 2012 and 2013:
 
2012
 
2013
 
MWh (in
thousands)
 
Average
price/
MWh1
 
MWh (in
thousands)
 
Average
price/
MWh1
Midwest Generation plants2
7,185

 
$
38.76

 
1,020

 
$
40.43

Homer City plant3,4
 
 
 
 
 
 
 
PJM West Hub
432

 
52.34

 
—

 
—

Total
7,617

 
 

 
1,020

 
 


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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 Northern Illinois Hub and to a lesser extent the AEP/Dayton Hub, both in PJM, and the Indiana Hub in MISO.
3 
Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. 2012 includes 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.
4 
The average price/MWh includes 172 MW of capacity for periods ranging from January 1, 2012 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.
In January 2012, EMMT entered into 14.7 billion cubic feet of natural gas futures contracts (equivalent to approximately 1,610 GWh of energy only contracts using a ratio of 9.12 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks through December 2012 at an average price of $24.88/MWh.

Capacity Price Risk
Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for construction of capacity resources. The following table summarizes the status of capacity sales for Midwest Generation and Homer City at December 31, 2011:
 
 
 
 
 
 
 
RPM Capacity
Sold in Base
Residual Auction
 
Other Capacity Sales,
Net of Purchases3
 
Aggregate
Average
Price per
MW-day
 
 
Installed
Capacity
MW
 
Unsold
Capacity1
MW
 
Capacity
Sold2
MW
 
MW
 
Price per
MW-day
 
MW
 
Average
Price per
MW-day
 
 
January 1, 2012 to May 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
5,477

 
(555
)
 
4,922

 
4,582

 
$
110.00

 
340

 
$
98.92

 
$
109.23

 
Homer City
1,884

 
(163
)
 
1,721

 
1,771

 
110.00

 
(50
)
 
30.00

 
112.32

 
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 
June 1, 2014 to May 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
5,477

 
(852
)
 
4,625

 
4,625

 
125.99

 
—

 
—

 
125.99

 
Homer City
1,884

 
(190
)
 
1,694

 
1,694

 
136.50

 
—

 
—

 
136.50

 
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 172 MW of capacity for periods ranging from January 1, 2012 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

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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.
For additional information regarding capacity sold by Homer City, see "Management's Overview—Homer City Lease."

Basis Risk
Sales made from the coal plants in the real-time or day-ahead market receive the actual real-time 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 forward 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 and Indiana Hubs 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 2011, day-ahead prices at the Homer City busbar were lower than those at the PJM West Hub by an average of 9%, compared to 16% during 2010 and 12% during 2009, due to transmission congestion in PJM. During 2011, day-ahead prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub, Cinergy Hub and Northern Illinois Hub by an average of 14%, 4% and less than 1%, respectively, compared to 13%, 6% and less than 1%, respectively, during 2010, due to transmission congestion in PJM.
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 day-ahead prices for two delivery points in exchange for a fixed amount.

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, 2011 for the following three years:
 
Amount of Coal Under Contract
in Millions of Equivalent Tons1
 
2012
 
2013
 
2014
Midwest Generation plants
16.0

 
9.8

 
9.8

Homer City plant
3.3

 
0.8

 
—

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.
EME is subject to price risk for purchases of coal that are not under contract. Market prices of NAPP coal, which are related to the price of coal purchased for the Homer City plant, increased during the past two years. The market price of NAPP coal based on 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content was $73.30 per ton at December 30, 2011, compared to a price of $70 per ton and $52.50 per ton at December 31, 2010 and 2009, respectively, as reported by the EIA. In 2011, the price of NAPP coal ranged from $70 per ton to $78.20 per ton, as reported by the EIA. The 2011 increase in NAPP coal prices was primarily driven by the export market demand and global coal pricing.
Market prices of PRB coal based on 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content fluctuated between $12.35 per ton and $15.10 per ton during 2011, as reported by EIA. The December 30, 2011 price of $12.75 per ton compared to a price of $13.60 per ton and $9.25 per ton at December 31, 2010 and 2009, respectively, as reported by the EIA. The 2011 fluctuations in PRB coal prices were in line with normal market price volatility with the higher PRB prices reflecting the impact of the CSAPR before it was stayed.
Midwest Generation contracts with rail carriers to transport coal to its facilities. In anticipation of the expiration on December 31, 2011 of its existing rail transportation contracts, during the fourth quarter of 2011, Midwest Generation entered into new multi-year transportation contracts with Union Pacific Railroad and two short-haul carriers for a specified minimum and maximum amount of tons effective January 1, 2012. The estimated minimum annual costs of transportation of coal under these contracts, based on tonnage commitments, are $386 million during 2012, $326 million in 2013, and $333 million in 2014. However, all of the contracts have provisions that address the financial exposure of Midwest Generation related to a plant closure under certain circumstances as specified in the agreements. The contracts provide for quarterly and annual cost

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adjustments based on a number of factors that may increase the minimum payments.
EME believes Midwest Generation is fully contracted in 2012 based on its anticipated coal requirements for Midwest Generation. Based on Homer City's anticipated coal requirements in excess of the amount under contract, Homer City expects that a 10% change in the price of coal at December 31, 2011 would increase or decrease 2012 pre-tax income by approximately $4 million.

Emission Allowances Price Risk
If CSAPR becomes effective as issued, the amount of SO2 that a plant emits in its operation will need to be matched by a sufficient amount of SO2 allowances designated under this program (CSAPR SO2 allowances) that are either allocated to the plant under the CSAPR program or purchased in the open market. SO2 allowances under the federal Acid Rain Program cannot be used to satisfy the requirements under CSAPR. For additional information on CSAPR, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments—Cross-State Air Pollution Rule."

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, 2011, the balance sheet exposure as described above, by the credit ratings of EME's counterparties, was as follows:
 
December 31, 2011
(in millions)
Exposure2
 
Collateral
 
Net Exposure
Credit Rating1
 
 
 
 
 
A or higher
$
99

 
$
(2
)
 
$
97

A-
3

 
—

 
3

BBB+
4

 
—

 
4

BBB
—

 
—

 
—

BBB-
13

 
—

 
13

Below investment grade
51

 
(50
)
 
1

Total
$
170

 
$
(52
)
 
$
118

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 composed of $82 million of net accounts receivable and payables and $88 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. 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 $41 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.
The 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 69% of EME's consolidated operating revenues in 2011. At December 31, 2011, EME's account receivable due from PJM was $62 million.
EME's wind turbine supply agreements contain significant suppliers' obligations related to the 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

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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, 2011 would increase or decrease the fair value of the interest rate swap agreements by approximately $21 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 $3.7 billion at December 31, 2011, compared to the carrying value of $4.9 billion. A 10% increase in market interest rates at December 31, 2011 would result in a decrease in the fair value of total long-term debt by approximately $155 million. A 10% decrease in market interest rates at December 31, 2011 would result in an increase in the fair value of total long-term debt by approximately $172 million.


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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."

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 are evaluated for impairment whenever indicators 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 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.
In preparing long-term cash forecasts, EME includes assumptions about future prices for electricity, capacity, fuel and related products and services, as applicable, future operations and maintenance costs and future capital expenditure requirements under different scenarios. As appropriate, EME uses a probability weighted approach when determining whether impairment indicators exist. Assumptions included in the long-term cash flow forecasts for merchant projects include:
•
Observable market prices for electricity, fuel and related products and services to the extent available and long-term prices developed based on a fundamental price model;
•
Long-term capacity prices based on the assumption that capacity markets would continue consistent with their current structure, with expected increases in revenues as a result of declines in reserve margins beyond the price of the latest auctions;
•
Trends for additions and retirements for generation resources; and
•
Plans for compliance with both existing and possible future environmental regulations.
EME includes allocated acquired emission allowances as part of each power plant asset group. In the case of the Powerton and Joliet Stations and Homer City, 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.
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.


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Application to Homer City Plant
As described in "Management's Overview," Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process undertaken in the fourth quarter of 2011, and Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both. In connection with the preparation of its year end financial statements, EME concluded that these events combined with the current and projected financial condition of Homer City were indicators of impairment. The long-lived asset group subject to the impairment evaluation was determined to include the Homer City lease, leasehold improvements and prepaid rent. In assessing impairment, EME concluded that the future undiscounted cash flows through the period in which EME expects to continue to have significant economic interest and material control of the Homer City plant were insufficient to recover the carrying amount of the asset group. To measure the amount of impairment loss, the market and income approaches were considered the most appropriate and resulted in a zero fair value. EME viewed the lack of interest from market participants to provide sufficient funding for the capital improvements as indicative that the fair value of the asset group is zero. Furthermore, discounted cash flow analysis based on estimates of future energy, capacity and coal prices, operations and maintenance costs and operating lease payments along with the estimated costs of constructing the environmental control equipment also indicated a fair value of zero. Accordingly, EME recorded an impairment charge of $1,032 million for the fourth quarter of 2011.

Application to Midwest Generation Stations
A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. In connection with the preparation of its year end financial statements, EME concluded, based on the current energy price environment, it is less likely that Midwest Generation will install environmental controls required by the CPS at its Fisk, Crawford and Waukegan Stations; and such assessment was an indicator that these stations were impaired. Management updated the probability weighted future undiscounted cash flows expected to be received at these stations and concluded that such amounts did not recover the respective station's carrying amounts. As part of these alternative cash flow scenarios, management considered a shortened estimated useful life of each station if environmental improvements were not made and a forecasted reduction in generation from lower forward power prices. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014.
To measure the amount of the impairment loss, the income approach was considered the most relevant, but market data obtained prior to the significant decline in power prices was used to corroborate the income approach. The discounted cash flow analysis assumptions that have the most significant impact on fair value are forecasted energy and capacity prices. The discounted cash flow analysis indicated a fair value of zero. EME also concluded it was unlikely that a third party would consummate the purchase of the Fisk, Crawford or Waukegan Stations in the current economic and regulatory environment resulting in a determination that the fair value of each of these stations is zero. This resulted in an impairment charge of $115 million, $186 million and $339 million for Fisk, Crawford and Waukegan Stations, respectively. Environmental and other remediation or ongoing maintenance costs are expected to be offset by the salvage value of the asset groups.
The following table summarizes the net book value of the merchant coal-fired asset groups at December 31, 2011:
(in millions)
 
Joliet Station
$
732

Powerton Station
757

Will County Station
523


Application to Selected Wind Projects
In connection with the preparation of its year end financial statements, management has reviewed the Storm Lake project and four small wind projects in Minnesota for impairment in the fourth quarter of 2011 based on an expected future increase in operating costs and declines in long-term power prices that the projects could potentially realize following the term of the power purchase agreements. The probability weighted future undiscounted cash flows of each project are not expected to be sufficient to recover the respective carrying value of each of these long-lived assets ($53 million in aggregate). The income approach was utilized to determine fair value for these asset groups. The most significant assumptions used in determining fair

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value were discount rates, future wind generation, the future availability of the project to generate energy and future plant operations expense. The asset groups at each project consisted of property, plant and equipment and, where appropriate, deferred revenue. In aggregate, the fair value of these five asset groups was determined to be $23 million, resulting in an impairment charge of $30 million.

Merchant Wind Projects
In light of the decline in forecasted power prices since September 30, 2011, EME reviewed the long-term cash forecasts for the merchant wind projects in a manner consistent with the Key Assumptions and Approach Used described above. The expected future undiscounted cash flows of these projects recovered the carrying amount of these asset groups and, accordingly, no impairments were recorded. The expected future cash flows for these merchant wind projects are dependent upon a number of assumptions, the most significant of which are expected future power prices and operating costs. A decline in the forecasted cash flows in future periods could result in impairment, requiring a write-down of the carrying amount to fair value. The carrying values of the Goat Wind, Big Sky and Lookout asset groups at December 31, 2011 were $200 million, $344 million and $64 million, respectively.

Derivatives
EME uses derivative instruments to manage exposure to changes in electricity, fuel oil, gas 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 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, 2011, Level 3 derivatives had a net fair value of $83 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 $21 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."

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

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consolidated balance sheets.
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 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."

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.
In addition, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation Company LLC for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in a supplemental agreement. The estimated liability is based on studies that estimate future losses based on claims experience and other available information. In calculating future losses, various assumptions were made, including, but not limited to, the settlement of future claims under the supplemental agreement, the distribution of exposure sites and that the filing date of asbestos claims will not be after 2044. At December 31, 2011, Midwest Generation had recorded a liability of $54 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."

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

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Condition and Results of Operations."


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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FINANCIAL STATEMENTS
 

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, 2011.

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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of January 1, 2010.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 29, 2012


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EDISON MISSION ENERGY AND SUBSIDIARIES
 

CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)

 
Years Ended December 31,
 
2011
 
2010
 
2009
Operating Revenues
$
2,180

 
$
2,423

 
$
2,377

Operating Expenses
 
 
 
 
 
Fuel
799

 
809

 
796

Plant operations
709

 
654

 
579

Plant operating leases
177

 
178

 
177

Depreciation and amortization
310

 
248

 
236

Asset impairments and other charges (Notes 1 and 13)
1,746

 
45

 
4

Administrative and general
180

 
182

 
196

Total operating expenses
3,921

 
2,116

 
1,988

Operating income (loss)
(1,741
)
 
307

 
389

Other Income (Expense)
 
 
 
 
 
Equity in income from unconsolidated affiliates
86

 
104

 
100

Dividend income
30

 
19

 
12

Interest income
1

 
2

 
7

Interest expense
(323
)
 
(263
)
 
(296
)
Other income (expense), net
15

 
9

 
5

Total other expense
(191
)
 
(129
)
 
(172
)
Income (loss) from continuing operations before income taxes
(1,932
)
 
178

 
217

Provision (benefit) for income taxes
(856
)
 
19

 
16

Income (Loss) From Continuing Operations
(1,076
)
 
159

 
201

Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 14)
(3
)
 
4

 
(7
)
Net Income (Loss)
(1,079
)
 
163

 
194

Net Loss Attributable to Noncontrolling Interests
1

 
1

 
3

Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder
$
(1,078
)
 
$
164

 
$
197

Amounts Attributable to Edison Mission Energy Common Shareholder
 
 
 
 
 
Income (loss) from continuing operations, net of tax
$
(1,075
)
 
$
160

 
$
204

Income (loss) from discontinued operations, net of tax
(3
)
 
4

 
(7
)
Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder
$
(1,078
)
 
$
164

 
$
197




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 (LOSS)
(in millions)
 
Years Ended December 31,
 
2011
 
2010
 
2009
Net Income (Loss)
$
(1,079
)
 
$
163

 
$
194

Other comprehensive income (loss), net of tax
 
 
 
 
 
Pension and postretirement benefits other than pensions:
 
 
 
 
 
Prior service adjustment, net of tax
—

 
(7
)
 
1

Net gain (loss) adjustment, net of tax expense (benefit) of $(10), $(10) and $6 for 2011, 2010 and 2009, respectively
(15
)
 
(14
)
 
10

Amortization of net loss and prior service adjustment included in expense, net of tax
2

 
1

 
2

Unrealized gains (losses) on derivatives qualified as cash flow hedges:
 
 
 
 
 
Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(7), $37 and $36 for 2011, 2010 and 2009, respectively
(12
)
 
55

 
43

Reclassification adjustments included in net income (loss), net of income tax benefit of $25, $96 and $124 for 2011, 2010 and 2009, respectively
(38
)
 
(144
)
 
(178
)
Other comprehensive loss, net of tax
(63
)
 
(109
)
 
(122
)
Comprehensive Income (Loss)
(1,142
)
 
54

 
72

Comprehensive Loss Attributable to Noncontrolling Interests
1

 
1

 
3

Comprehensive Income (Loss) Attributable to Edison Mission Energy Common Shareholder
$
(1,141
)
 
$
55

 
$
75




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,
 
2011
 
2010
Assets
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
1,300

 
$
1,075

Accounts receivable—trade
107

 
170

Receivables from affiliates
4

 
192

Inventory
274

 
236

Derivative assets
40

 
46

Restricted cash and cash equivalents
103

 
2

Margin and collateral deposits
41

 
59

Prepaid expenses and other
72

 
79

Total current assets
1,941

 
1,859

Investments in Unconsolidated Affiliates
523

 
557

Property, Plant and Equipment, less accumulated depreciation of $1,295 and $1,759 at respective dates
4,472

 
5,332

Other Assets
 
 
 
Deferred financing costs
71

 
54

Long-term derivative assets
59

 
70

Restricted deposits
48

 
44

Rent payments in excess of levelized rent expense under plant operating leases
760

 
1,187

Deferred taxes
205

 
—

Other long-term assets
244

 
218

Total other assets
1,387

 
1,573

Total Assets
$
8,323

 
$
9,321



EDISON MISSION ENERGY AND SUBSIDIARIES
 

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

 
December 31,
 
2011
 
2010
Liabilities and Shareholder's Equity
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
99

 
$
90

Payables to affiliates
188

 
18

Accrued liabilities
168

 
201

Derivative liabilities
1

 
6

Interest payable
33

 
31

Deferred taxes
2

 
34

Current portion of long-term debt
57

 
48

Short-term debt
—

 
96

Total current liabilities
548

 
524

Long-term debt net of current portion
4,855

 
4,342

Deferred taxes and tax credits
—

 
836

Deferred revenues
530

 
160

Long-term derivative liabilities
90

 
19

Other long-term liabilities
636

 
619

Total Liabilities
6,659

 
6,500

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 at each date)
64

 
64

Additional paid-in capital
1,327

 
1,336

Retained earnings
365

 
1,448

Accumulated other comprehensive loss
(94
)
 
(31
)
Total Edison Mission Energy common shareholder's equity
1,662

 
2,817

Noncontrolling Interests
2

 
4

Total Equity
1,664

 
2,821

Total Liabilities and Equity
$
8,323

 
$
9,321




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
 
 
 
 
 
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Non-
controlling Interests
 
Total Equity
Balance at December 31, 2008
$
64

 
$
1,335

 
$
1,085

 
$
200

 
$
80

 
$
2,764

Net income (loss)
—

 
—

 
197

 
—

 
(3
)
 
194

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
64

 
1,339

 
1,280

 
78

 
76

 
2,837

Impact of consolidation and deconsolidation of variable interest entities (Note 3)
—

 
—

 
10

 
—

 
(71
)
 
(61
)
Net income (loss)
—

 
—

 
164

 
—

 
(1
)
 
163

Other comprehensive loss, net of tax
—

 
—

 
—

 
(109
)
 
—

 
(109
)
Payments to Edison International for stock purchases related to stock-based compensation
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Excess tax benefits related to stock option exercises
 
 
1

 
 
 


 
 
 
1

Other stock transactions, net
—

 
6

 
—

 
—

 
—

 
6

Purchase of noncontrolling interests
—

 
(10
)
 
—

 
—

 
—

 
(10
)
Balance at December 31, 2010
64

 
1,336

 
1,448

 
(31
)
 
4

 
2,821

Net income (loss)
—

 
—

 
(1,078
)
 
—

 
(1
)
 
(1,079
)
Other comprehensive loss, net of tax
—

 
—

 
—

 
(63
)
 
—

 
(63
)
Payments to Edison International for stock purchases related to stock-based compensation
—

 
—

 
(5
)
 
—

 
—

 
(5
)
Excess tax benefits related to stock option exercises
—

 
2

 
—

 
—

 
—

 
2

Other stock transactions, net
—

 
4

 
—

 
—

 
—

 
4

Purchase of noncontrolling interests
—

 
(15
)
 
—

 
—

 
(1
)
 
(16
)
Balance at December 31, 2011
$
64

 
$
1,327

 
$
365

 
$
(94
)
 
$
2

 
$
1,664



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,
 
2011
 
2010
 
2009
Cash Flows From Operating Activities
 
 
 
 
 
Net income (loss)
$
(1,079
)
 
$
163

 
$
194

(Income) loss from discontinued operations
3

 
(4
)
 
7

Income (loss) from continuing operations, net
(1,076
)
 
159

 
201

Adjustments to reconcile income (loss) to net cash provided by operating activities:
 
 
 
 
 
Equity in income from unconsolidated affiliates
(85
)
 
(104
)
 
(100
)
Distributions from unconsolidated affiliates
82

 
91

 
76

Depreciation and amortization
330

 
260

 
246

Deferred taxes and tax credits
(903
)
 
162

 
275

Asset impairments and other charges
1,746

 
45

 
4

Gain on sale of assets
(8
)
 
—

 
—

Proceeds from U.S. Treasury grants
388

 
92

 
—

Changes in operating assets and liabilities:
 
 
 
 
 
(Increase) decrease in margin and collateral deposits
18

 
61

 
(32
)
(Increase) decrease in receivables
251

 
(65
)
 
(35
)
Increase in inventory
(38
)
 
(37
)
 
(8
)
Decrease in prepaid expenses and other
7

 
6

 
53

(Increase) decrease in restricted cash and cash equivalents
(4
)
 
68

 
(69
)
Increase in rent payments in excess of levelized rent expense
(136
)
 
(149
)
 
(160
)
Increase (decrease) in payables and other current liabilities
178

 
(93
)
 
(109
)
(Increase) decrease in derivative assets and liabilities
1

 
18

 
(168
)
(Increase) decrease in other operating—assets
(78
)
 
(9
)
 
16

Increase (decrease) in other operating—liabilities
(44
)
 
97

 
68

Operating cash flow from continuing operations
629

 
602

 
258

Operating cash flow from discontinued operations
(3
)
 
4

 
(7
)
Net cash provided by operating activities
626

 
606

 
251

Cash Flows From Financing Activities
 
 
 
 
 
Borrowings on long-term debt
481

 
211

 
189

Payments on debt
(107
)
 
(48
)
 
(886
)
Borrowings under short-term debt
32

 
96

 
—

Borrowing held in escrow pending completion of project construction
(97
)
 
—

 
—

Cash contributions from noncontrolling interests
—

 
—

 
2

Cash dividends to noncontrolling interests
—

 
—

 
(3
)
Payments to affiliates related to stock-based awards
(8
)
 
(6
)
 
(2
)
Excess tax benefits related to stock-based exercises
2

 
1

 
—

Financing costs
(26
)
 
(19
)
 
(14
)
Net cash provided by (used in) financing activities from continuing operations
277

 
235

 
(714
)
Cash Flows From Investing Activities
 
 
 
 
 
Capital expenditures
(686
)
 
(574
)
 
(283
)
Proceeds from return of capital and loan repayments and sale of assets
55

 
34

 
30

Purchase of interest of acquired companies
(3
)
 
(4
)
 
(22
)
Investments in and loans to unconsolidated affiliates
(10
)
 
(7
)
 
—

Maturities of short-term investments
—

 
1

 
3

(Increase) decrease in restricted deposits
(4
)
 
(5
)
 
3

Investments in other assets
(30
)
 
(7
)
 
(279
)
Net cash used in investing activities from continuing operations
(678
)
 
(562
)
 
(548
)
Net increase (decrease) in cash and cash equivalents
225

 
279

 
(1,011
)
Cash and cash equivalents at beginning of period
1,075

 
796

 
1,807

Cash and cash equivalents at end of period
$
1,300

 
$
1,075

 
$
796


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.
At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility, and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at December 31, 2011, $500 million of which mature in 2013. Unless energy and capacity prices increase, EME expects that it will experience further reductions in cash flow and losses in 2012 and subsequent years. EME's liquidity will be strained by a continuation of recent adverse trends, combined with pending debt maturities, higher operating costs and the need to retrofit its coal-fired plants to comply with governmental regulations. To address such a scenario, EME would need to consider all options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EME and its subsidiaries.
Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process undertaken in the fourth quarter of 2011. Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both. For discussion of asset impairment recorded with respect to the Homer City plant, see Note 13—Asset Impairments and Other Charges.
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 (VIEs) in which EME is not deemed to be the primary beneficiary, are mainly accounted for by the equity method. For a discussion of EME's VIEs, 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 accounting principles generally accepted in the United States of America (GAAP) requires EME to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates.
The consolidated statement of cash flows for the year ended December 31, 2010 was revised to correct an error in the presentation of vendor financed property, plant and equipment in the amount of $190 million. This correction, to present the amount on a net rather than gross basis, decreased cash flows used in investing activities and cash flows provided by financing activities by this amount, but had no impact on the net change in cash and cash equivalents. Management believes the revision does not have a material impact on the prior year financial statements.
Cash Equivalents
Cash equivalents included money market funds totaling $1.2 billion and $813 million at December 31, 2011 and 2010, respectively. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months.
Restricted Cash and Cash Equivalents, and Restricted Deposits

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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 $48 million and $44 million at December 31, 2011 and 2010, respectively, related to lease payments, debt service, collateral reserves, or other. The restricted cash and cash equivalents at December 31, 2011 also included $97 million of cash proceeds received from a wind financing that was held in escrow at December 31, 2011 and is expected to be released in the first quarter of 2012 when the Pinnacle project achieves certain completion milestones. For a discussion of the Tapestry wind financing, see Note 5—Debt and Credit Agreements—2011 Project Financings—Tapestry Wind.
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. 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 or if the inventory is determined to be obsolete. Inventory consisted of the following:
 
December 31,
(in millions)
2011
 
2010
Coal, fuel oil and other raw materials
$
188

 
$
163

Spare parts, materials and supplies
86

 
73

Total inventory
$
274

 
$
236

Purchased Emission Allowances, Exemptions and Offsets
Purchased emission allowances are stated at the lower of weighted-average cost or market. Purchased emission allowances are recorded at cost when purchased and then expensed at weighted-average cost as used. Cost is reduced to market value if the market value of emission allowances has declined and it is probable that revenues earned from the generation of power will not cover the amounts recorded in the ordinary course of business. Purchased emission allowances are classified as current or long-term assets based on the time the allowances are expected to be used. The following table summarizes the amount of current and noncurrent purchased emission allowances, exemptions and offsets and the line item on the consolidated balance sheets.
 
December 31,
(in millions)
2011
 
2010
Purchased emission allowances


 
 
Current (included in prepaid expenses and other)
$
20

 
$
29

Noncurrent (included in other long-term assets)
92

 
31

Property, Plant and Equipment
Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are principally composed of EME's consolidated 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.
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 are 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 to10 years
The remaining estimated useful life or lease term at December 31, 2011 for the Midwest Generation coal plants is as follows:

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Joliet Unit 6
 
18 years
Joliet Units 7 and 81
 
19 years
Powerton Station1
 
22 years
Will County Station
 
18 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 $27 million, $54 million and $19 million in 2011, 2010 and 2009, respectively.
Impairment of Long-Lived Assets
EME evaluates the impairment of its 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. 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. 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 for the excess of the carrying amount over fair value. Fair value is determined via market, cost and income based valuation techniques, as appropriate. For further discussion, see Note 13—Asset Impairments and Other Charges.
EME also evaluates investments in unconsolidated affiliates for potential impairment. If the carrying value of an unconsolidated affiliate exceeds its fair value, an impairment loss is recorded if the decline is other than temporary.
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. Amortization of deferred financing costs charged to interest expense was $15 million, $5 million and $3 million in 2011, 2010 and 2009, 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

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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 statements of operations.
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.
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 2011, EME received a total of $388 million of U.S. Treasury grants (cash grants, under the American Recovery and Reinvestment Act of 2009).
Power Purchase Agreements
EME, generally as the seller, enters into long-term power purchase agreements in the normal course of business. A power purchase agreement may be considered a variable interest in a VIE. Under this classification, the power purchase agreement is evaluated to determine if EME is the primary beneficiary in the VIE, 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 in which EME is considered the lessor. These agreements are classified as operating leases. EME records rental income under these contracts as electricity is delivered at rates defined in power sales agreements. Revenues from these power sales agreements were $109 million, $81 million and $83 million in 2011, 2010 and 2009, 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.
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 loss 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. Generally, Edison International does not issue new common stock for settlement of equity awards. Rather, a third party is used to purchase shares from the market and deliver 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, awards are generally settled half in cash and

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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 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. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME's current tax liability or benefit is determined on a "with and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding EME's taxable income or loss and state apportionment factors. This method is similar to a separate company return, except that EME recognizes, without regard to separate company limitations, additional tax liabilities or benefits based on the impact to the combined group including EME's taxable income or losses and state apportionment factors. At December 31, 2011 amounts included in other long-term assets and payables to affiliates associated with the tax-allocation agreements were $86 million and $174 million, respectively. At December 31, 2010, amounts included in receivables from affiliates and other long-term assets associated with the tax-allocation agreements totaled $199 million.
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. At December 31, 2011, Edison Mission Energy had net federal and state deferred tax assets of $203 million. A significant portion of the deferred tax assets recognized relate to net operating loss and tax credit carryforwards. Realization is dependent on generating sufficient consolidated taxable income by the Edison International consolidated group prior to expiration of the loss and credit carryforwards. Although realization is not assured, management believes it is more likely than not that all of the deferred tax assets will be realized.
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, 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. Certain of EME's wind projects also qualify for state tax credits, which are accounted for similarly to federal production tax credits.
Interest income, interest expense and penalties associated with income taxes are reflected in provision (benefit) for income taxes on EME's consolidated statements of operations. For further information regarding income taxes, see Note 7—Income Taxes.
New Accounting Guidance
Accounting Guidance Adopted in 2011
Revenue-Multiple-Deliverables
In October 2009, the Financial Accounting Standards Board (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 required to be applied prospectively to new or significantly modified revenue arrangements. EME adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on EME's consolidated results of operations, financial position or cash flows.
Fair Value Measurements and Disclosures
The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements.

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Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. EME adopted this guidance effective January 1, 2011.
Accounting Guidance Not Yet Adopted
Fair Value Measurement
In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. EME will adopt this guidance in the first quarter of 2012. The adoption of this standards update is not expected to have a material impact on EME's consolidated financial position.
Presentation of Comprehensive Income
In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. EME will adopt this guidance in the first quarter of 2012. EME currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.
Derecognition of In-substance Real Estate Subsidiary
In December 2011, the FASB issued an accounting standards update which provides guidance on the timing of deconsolidation if the parent of an in-substance real estate subsidiary ceases to have a controlling interest due to default by the subsidiary on nonrecourse debt. The guidance requires that deconsolidation occur when the subsidiary is released from the nonrecourse debt and title transfers to the lender. If the parent provides a guarantee or the lender has recourse to the parent, the parent would need to assess the nature of the continuing involvement in order to determine when deconsolidation is applicable. In-substance real estate includes real estate with property improvements or integral equipment. This standard is applicable to fiscal years or interim periods beginning on or after June 15, 2012, and early adoption is permitted. At December 31, 2011, there were no current defaults on the debt of EME's subsidiaries that may be classified as in-substance real estate subsidiaries.
Offsetting Assets and Liabilities
In December 2011, the FASB issued an accounting standards update modifying disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. EME will adopt this guidance effective January 1, 2013. The guidance impacts disclosure only.

Note 2. Property, Plant and Equipment
Property, plant and equipment consisted of the following:
 
December 31,
(in millions)
2011
 
2010
Power plant facilities
$
4,596

 
$
4,478

Leasehold improvements
4

 
177

Emission allowances
672

 
1,305

Construction in progress1
366

 
1,036

Equipment, furniture and fixtures
129

 
95

 
5,767

 
7,091

Less accumulated depreciation and amortization
1,295

 
1,759

Net property, plant and equipment
$
4,472

 
$
5,332

1 
Included $357 million and $888 million at December 31, 2011 and 2010, respectively, for new gas and wind projects under construction.

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EME recorded $1.7 billion of impairment charges in 2011. For additional information on these charges, see Note 13—Asset Impairments and Other Charges.
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 $1.6 billion and $203 million, respectively, at December 31, 2011.
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 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)
2011
 
2010
 
2009
Beginning balance
$
54

 
$
43

 
$
34

Accretion expense
6

 
3

 
3

Revisions
(1
)
 
—

 
—

Liabilities added
19

 
9

 
6

Transfers out1
—

 
(1
)
 
—

Ending balance
$
78

 
$
54

 
$
43

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
A variable interest entity (VIE) is defined 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 residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE 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 VIE. The primary beneficiary is required to consolidate the VIE unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs 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 VIEs to conduct its business as described below.
Description of Use of VIEs
EME and its subsidiaries and affiliates have used variable interest entities as part of joint development agreements and constructing or acquiring full or partial interests in power generation facilities and ancillary facilities, referred to by EME as a

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project. EME's subsidiaries and affiliates have financed the development and construction or acquisition of its projects by capital contributions from EME and the incurrence of debt or lease obligations by its subsidiaries and affiliates owning the operating facilities. These project level debt or lease obligations are generally 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 VIEs
Projects or Entities that are Consolidated
At December 31, 2011 and 2010, EME consolidated 13 and 14 projects, respectively, with a total generating capacity of 570 MW and 580 MW, respectively, that have minority interests held by others. In April 2011, EME sold its 75% ownership interest in a Minnesota wind project. In determining that EME was the primary beneficiary of the projects that are consolidated, key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses of the VIEs.
The following table presents summarized financial information of the projects that were consolidated by EME:
 
December 31,
(in millions)
2011
 
2010
Current assets
$
36

 
$
26

Net property, plant and equipment
675

 
739

Other long-term assets
5

 
6

Total assets
$
716

 
$
771

Current liabilities
$
28

 
$
25

Long-term debt net of current portion
57

 
71

Deferred revenues
69

 
71

Other long-term liabilities
22

 
21

Total liabilities
$
176

 
$
188

Noncontrolling interests
$
2

 
$
4

Assets serving as collateral for the debt obligations had a carrying value of $136 million and $163 million at December 31, 2011 and 2010, respectively, and primarily consist of property, plant and equipment. The consolidated statements of operations and cash flows for the years ended December 31, 2011 and 2010 includes $22 million and $13 million of pre-tax losses, respectively, and $40 million and $54 million of operating cash flows, respectively, related to VIEs that are consolidated. Effective January 1, 2010, EME adopted new accounting guidance issued by the FASB related to the consolidation of VIEs. As a result of this guidance, EME prospectively consolidated the Ambit project (a 50% interest in American Bituminous Power Partners, L.P.) and deconsolidated the Elkhorn Ridge and San Juan Mesa wind projects. The impact of adopting this guidance resulted in a cumulative effect adjustment that increased retained earnings by $10 million.
During 2011, EME purchased the remaining interests in Pinnacle Wind Force, LLC and Broken Bow I, LLC and all assets of the Crofton Bluffs project. During 2010, EME purchased a noncontrolling interest in Laredo Ridge. All these projects are now 100% owned by EME. The purchases of the noncontrolling interest were accounted for as equity transactions between controlling and noncontrolling interest holders.
Capistrano Wind Equity Capital-2012
As part of its plan to obtain third-party equity capital to finance the development of a portion of EME's wind portfolio, on February 13, 2012, Edison Mission Wind sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in Nebraska) for consideration expected to include $141 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and completion of project debt financing. The proceeds from outside investors net of costs on the projects to be completed are expected to be distributed to EME and available for general corporate purposes.
An indirect subsidiary of EME, Edison Mission Wind, and EME's parent company, Mission Energy Holding Company (MEHC), own 100% of the Class A equity interests in Capistrano Wind Partners, and the Class B preferred equity interests are

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held by outside investors. Under the terms of the formation documents, preferred equity interests receive 100% of the cash available for distribution, up to a scheduled amount to target a return and thereafter cash distributions are shared. Cash available for distribution includes 90% of the tax benefits realized by MEHC and contributed to Capistrano Wind Partners.
Edison Mission Wind retains indirect beneficial ownership of the common equity in the projects, net of a $4 million preferred investment made by MEHC, and retains responsibilities for managing the operations of Capistrano Wind Holdings and its projects, and accordingly, EME will continue to consolidate these projects. The amount contributed by the third-party interests will be reflected as a noncontrolling interest in EME's consolidated financial statements. Edison Mission Wind plans to distribute to EME the amounts received from the sale of the projects, net of costs on the projects to be completed, which will then be available to EME for general corporate purposes.
Projects that are not Consolidated
EME accounts for the majority of its investments in domestic gas and wind energy projects in which it has less than a 100% ownership interest, and does not have both the right to direct the commercial and operating activities and the obligation to absorb losses or receive benefits from the VIEs, under the equity method. As of December 31, 2011 and 2010, EME had significant variable interests in five natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EME operates three of the four Big 4 projects and the Sunrise project and EME's partner provides the fuel management services for the Big 4 projects. In addition, the executive director of these gas projects is provided by EME's partner. Commercial and operating activities of these gas projects are jointly controlled by a management committee of each VIE. Accordingly, EME accounts for its variable interests in these projects under the equity method.
At December 31, 2011, EME accounted for its interest in the Community Wind North wind project, which achieved commercial operation on May 28, 2011, under the equity method. The commercial and operating activities of this entity are jointly directed by representatives of each partner. Thus EME is not the primary beneficiary of this project.
The following table presents the carrying amount of EME's investments in unconsolidated VIEs and the maximum exposure to loss for each investment:
 
December 31, 2011
(in millions)
Investment
 
Maximum
Exposure
Natural gas-fired projects
$
315

 
$
315

Wind projects
208

 
208

EME's exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these entities. At December 31, 2011 and 2010, outstanding debt for projects that are not consolidated consisted of long-term debt that was secured by a pledge of project entity assets, but does not provide for recourse to EME. At December 31, 2011, such outstanding indebtedness was $62 million, of which $16 million was proportionate to EME's ownership in the project. At December 31, 2010, such outstanding indebtedness was $116 million, of which $41 million was proportionate to EME's ownership interest in the 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)
2011
 
2010
 
2009
Revenues
$
769

 
$
828

 
$
936

Expenses
601

 
653

 
734

Net income
$
168

 
$
175

 
$
202


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December 31,
(in millions)
2011
 
2010
Current assets
$
289

 
$
296

Noncurrent assets
758

 
850

Total assets
$
1,047

 
$
1,146

Current liabilities
$
103

 
$
157

Noncurrent liabilities
88

 
74

Equity
856

 
915

Total liabilities and equity
$
1,047

 
$
1,146

The difference between the carrying value of these equity investments and the underlying equity in the net assets was $10 million at December 31, 2011. The difference is being amortized over the life of the projects. The majority of noncurrent liabilities are composed of project financing arrangements that are nonrecourse to EME. The undistributed earnings of equity method investments were $19 million and $28 million at December 31, 2011 and 2010, respectively.
The following table presents, as of December 31, 2011, the investments in unconsolidated affiliates accounted for by the equity method that represent at least 5% of EME's loss before tax, excluding asset impairment charges, or in which EME has an investment balance greater than $50 million:
Unconsolidated
Affiliates
 
Location
 
Investment at
December 31,
2011
(in millions)
 
Ownership
Interest at
December 31,
2011
 
Operating Status
San Juan Mesa
 
Elida, NM
 
$
84

 
75%
 
Operating wind-powered facility
Elkhorn Ridge
 
Bloomfield, NE
 
81

 
67%
 
Operating wind-powered facility
Sunrise
 
Fellows, CA
 
173

 
50%
 
Operating gas-fired facility
Sycamore
 
Bakersfield, CA
 
34

 
50%
 
Operating cogeneration facility
Kern River
 
Bakersfield, CA
 
21

 
50%
 
Operating cogeneration facility
Watson
 
Carson, CA
 
42

 
49%
 
Operating cogeneration facility
The following table presents summarized financial information of the investments in unconsolidated affiliates:
 
December 31,
(in millions)
2011
 
2010
Investments in Unconsolidated Affiliates
 
 
 
Equity investments
$
515

 
$
548

Cost investments
8

 
9

Total
$
523

 
$
557

At December 31, 2011 and 2010, EME had a 38% ownership interest in a small biomass project that it accounted for under the cost method of accounting as it does not have a significant influence over the project's operating and financial activities.
At December 31, 2011 and 2010, 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.

Note 4. Fair Value Measurements
Recurring 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, 2011 and 2010.
EME categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive fair value.

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The hierarchy, established by authoritative accounting guidance, 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:
 
December 31, 2011
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting and
Collateral1
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds2
$
1,207

 
$
—

 
$
—

 
$
—

 
$
1,207

Derivatives contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
66

 
$
95

 
$
(62
)
 
$
99

Natural gas
4

 
—

 
—

 
(4
)
 
—

Fuel oil
4

 
—

 
—

 
(4
)
 
—

Total commodity contracts
8

 
66

 
95

 
(70
)
 
99

Total assets
$
1,215

 
$
66

 
$
95

 
$
(70
)
 
$
1,306

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivatives contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
8

 
$
12

 
$
(19
)
 
$
1

Interest rate contracts
—

 
90

 
—

 
—

 
90

Total liabilities
$
—

 
$
98

 
$
12

 
$
(19
)
 
$
91


 
December 31, 2010
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting and
Collateral1
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds2
$
813

 
$
—

 
$
—

 
$
—

 
$
813

Derivative contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
70

 
$
107

 
$
(61
)
 
$
116

Natural gas
1

 
—

 
—

 
(1
)
 
—

Fuel oil
8

 
—

 
—

 
(8
)
 
—

Total commodity contracts
9

 
70

 
107

 
(70
)
 
116

Total assets
$
822

 
$
70

 
$
107

 
$
(70
)
 
$
929

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts
 
 
 
 
 
 
 
 
 
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

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 
Money market funds are included in cash and cash equivalents and in restricted cash and cash equivalents at December 31, 2011 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:

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Derivatives
(in millions)
2011
 
2010
Fair value, net assets at beginning of period
$
91

 
$
173

Total realized/unrealized gains (losses):
 
 
 
Included in earnings1
(19
)
 
64

Included in accumulated other comprehensive loss
1

 
2

Purchases
34

 
28

Settlements2
(22
)
 
(171
)
Transfers in or out of Level 3
(2
)
 
(5
)
Fair value, net assets at end of period
$
83

 
$
91

Change during the period in unrealized gains related to assets and liabilities, net held at end of period1
$
16

 
$
13

1 
Reported in operating revenues on EME's consolidated statements of operations
2 
2010 includes impact of load requirements services contracts settled when offsetting purchases of energy derivative contracts were classified as Level 2.
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 2011, 2010 and 2009.
Valuation Techniques used to Determine Fair Value
Level 1
Level 1 includes financial 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 and interest rate swaps.
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), 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 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

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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.
Non-Recurring Fair Value Measurements
For a discussion of non-recurring fair value measurements, see Note 13—Asset Impairments and Other Charges.
Long-term Debt
The carrying amounts and fair values of EME's long-term debt were as follows:
 
December 31, 2011
 
December 31, 2010
(in millions)
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Long-term debt, including current portion
$
4,912

 
$
3,716

 
$
4,390

 
$
3,670

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 fair value of EME's long-term debt is classified as Level 2.
The carrying amount of short-term debt approximates fair value.

Note 5. Debt and Credit Agreements
Long-Term Debt
Long-term debt includes both corporate debt and nonrecourse project debt, whereby lenders rely on specific project assets to repay such obligations. At December 31, 2011, recourse debt to EME totaled $3.7 billion and nonrecourse project debt totaled $1.2 billion. The following table summarizes long-term debt (rates and terms as of December 31, 2011):

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December 31,
(in millions)
2011
 
2010
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



 

Nonrecourse

 

Big Sky Wind, LLC
Vendor financing loan due 2014 (LIBOR1 plus 3.5%) (4.05%)
211

 
190

Viento Funding II, Inc.
Term Loan due 2020 (LIBOR plus 2.75%) (3.56%)
207

 
150

American Bituminous Power Partners, L.P.
Bonds due 2017 (Floating 0.24%)
55

 
63

Cedro Hill Wind, LLC
Term Loan due 2025 (LIBOR plus 3.0%) (3.58%)
131

 
135

High Lonesome Mesa, LLC
Bonds Series 2010A and 2010B due 2017 (6.85%)
72

 
75

Walnut Creek Energy
Construction Loan due 2013 (LIBOR + 2.25%) (2.546%)
138

 
—

WCEP Holdings, LLC
Construction Loan due 2013 (LIBOR + 4%) (4.296%)
49

 
—

Laredo Ridge
Term Loan due 2026 (LIBOR + 2.75%) (3.33%)
74

 
—

Tapestry Wind, LLC
Term Loan due 2021 (LIBOR + 2.5%) (3.08%)
214

 
—

Other
61

 
77

Subtotal
$
4,912

 
$
4,390

Less current portion of long-term debt
57

 
48

Long-term debt net of current portion
$
4,855

 
$
4,342

1 
London Interbank Offered Rate (LIBOR)
Long-term debt maturities at December 31, 2011, for the next five years are summarized as follows: $57 million in 2012, $755 million in 2013, $284 million in 2014, $72 million in 2015, and $566 million in 2016.
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 to Midwest Generation's hedging activities and the pledge of the intercompany notes from EME (approximately $1.3 billion at December 31, 2011). The net book value of assets pledged or mortgaged was $2.3 billion at December 31, 2011. 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 wind financing set forth below, payment obligations are generally secured by pledges of its direct and indirect ownership interests in the projects, project agreements and reserve accounts, if applicable. 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

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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. 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
At December 31, 2011, total borrowing commitments under EME's secured credit facility maturing in June 2012 were $564 million. The credit facility contains financial covenants which require EME to maintain an interest coverage ratio not less than 1.20 and a corporate debt to corporate capital ratio not more than 0.75. A failure to meet a ratio threshold could trigger other provisions and require a prepayment of the outstanding borrowings. At December 31, 2011, the interest coverage ratio was 2.87 for the year ended December 31, 2011 and the corporate debt to corporate capital ratio was 0.59.
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. Subsequent to the end of the fiscal year, EME terminated its secured credit facility.
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, 2011, 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, 2011:
(in millions)
EME
 
Midwest
Generation
Commitments
$
564

 
$
500

Outstanding borrowings
—

 
—

Outstanding letters of credit
(66
)
 
(3
)
Amount available
$
498

 
$
497

Any replacement of the above credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them.
Viento Funding II Wind Financing Amendment
In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 nonrecourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255 million, which included a $227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5 million seven-year working capital facility. At December 31, 2011, $207 million was outstanding under this loan. The amount of outstanding letters of credit was $23 million. Interest under the term loan accrues at LIBOR plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary. Viento Funding II, Inc. entered into interest rate swap agreements at 3.415% to hedge the majority of the variable interest rate under the term loan. Approximately $79 million under the swap agreements entered in connection with the 2009 financing were left unchanged at 3.175% and were outstanding at December 31, 2011. The effective interest rate as of December 31, 2011 was 5.81%. In conjunction with the foregoing, EME expensed $3 million of deferred financing costs and incurred a loss of $2 million from the termination of interest rate swaps, included as part of interest expense on the consolidated statement of

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operations.
Distributions from Viento Funding II are subject to compliance with the terms and conditions of its credit agreement, including a 12-month historic debt service coverage ratio test as specified in the agreements of 1.20 to 1.00. The debt service coverage ratio was 3.12 at December 31, 2011.
American Bituminous Project
EME consolidated the Ambit project on January 1, 2010. At December 31, 2011, this project had $55 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, 2011 was $20 million and was under funded by $13 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:
•
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. Based on historical operating history, the loan could mature as early as February 2013.
Big Sky's repayment obligations were guaranteed by EME until certain conditions are met, including commercial operations. On February 1, 2012, the lender agreed that all conditions have been satisfied and released EME from such guarantee.
High Lonesome
In November 2010, EME completed through its subsidiary, High Lonesome Mesa, LLC, a nonrecourse 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. In June 2011, High Lonesome Mesa, LLC entered into a $7 million letter of credit reimbursement agreement to provide credit support for a power purchase and sale agreement.
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, 2011, there were $47 million and $25 million outstanding under the Series 2010A bonds and Series 2010B bonds, respectively, and $12 million of outstanding letters of credit.
Distributions from High Lonesome are subject to compliance with the terms and conditions of its trust indentures, including a 12-month historic debt service coverage ratio test as specified in the agreements of 1.20 to 1.00. The debt service coverage ratio was 1.42 at October 31, 2011, the last payment date.
Laredo Ridge
In July 2010, EME completed through its subsidiary, Laredo Ridge Wind, LLC, a nonrecourse financing of its interests in the Laredo Ridge wind project. The financing included: a $75 million construction loan that was converted to a 15-year amortizing term loan on March 18, 2011; a $53 million bridge loan, secured by the expected U.S. Treasury grant, that was repaid in full on July 22, 2011; a $9 million letter of credit facility; and a $3 million working capital facility.
Interest under 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 on March 18, 2011 upon conversion of the construction loan to the term loan. As of December 31, 2011, there was $74 million outstanding under the term loan at an effective interest rate of 5.92% classified as long-term debt on EME's consolidated balance sheet, and $8 million of outstanding letters of credit. As of December 31, 2010, short-term debt on EME's consolidated balance sheet consisted of $53 million under the bridge loan and $43 million under the construction loan, at weighted average rates of 2.76% and 3.01%, respectively.
Distributions from Laredo Ridge are subject to compliance with the terms and conditions of its financing agreement, including

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a 12-month historic debt service coverage ratio test as specified in the agreements of 1.20 to 1.00. The debt service coverage ratio was 1.70 at December 31, 2011.
Cedro Hill
In March 2010, EME completed through its subsidiary, Cedro Hill Wind, LLC, a nonrecourse 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. As of December 31, 2011, there was $131 million outstanding under the term loan at an effective interest rate of 6.92% classified as long-term debt on EME's consolidated balance sheet and $10 million of outstanding letters of credit.
Distributions from Cedro Hill are subject to compliance with the terms and conditions of its financing agreement, including a 12-month historic debt service coverage ratio test as specified in the agreements of 1.20 to 1.00. The debt service coverage ratio was 2.05 at December 31, 2011.
2011 Project Financings
Tapestry Wind
In December 2011, EME completed, through its subsidiary, Tapestry Wind, LLC, a nonrecourse financing of its interests in the Taloga, Buffalo Bear and Pinnacle wind projects. The financing included a $214 million 10-year partially amortizing term loan (expiring in December 2021), a $12 million 10-year debt service reserve letter of credit facility, an $8 million 10-year project letter of credit facility and an $8 million 10-year working capital facility. Interest under the term loans accrues at LIBOR plus 2.5% initially, with the rate increasing 0.125% on the fourth and eighth anniversary of the closing date. Tapestry Wind, LLC entered into interest rate swap agreements at 2.21% to hedge the majority of the variable interest rate under the term loan. Tapestry Wind LLC also entered into forward starting interest rate swap agreements at 3.57% to hedge the forecasted refinancing of the final maturity payment of the term loan, effective December 21, 2021. A total of $97 million of cash proceeds received was deposited into an escrow account as of December 31, 2011 and is expected to be released in the first quarter of 2012 when the Pinnacle project achieves certain completion milestones.
Distributions from Tapestry Wind, LLC are subject to compliance with the terms and conditions of its credit agreements, including a 12-month historic debt service coverage ratio test as specified in the agreements of 1.2 to 1.0. At December 31, 2011, $214 million was outstanding under this loan at an effective interest rate of 4.55%. The amount of outstanding letters of credit was $13 million.
Walnut Creek
In July 2011, EME completed, through wholly owned subsidiaries, nonrecourse financings to fund construction of the Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The financings included floating rate construction loans totaling $495 million that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions, and also included $122 million of letter of credit ($40 million outstanding at December 31, 2011) and working capital facilities.
The nonrecourse financings were completed in two parts: the first of which was a construction plus term loan financing of $442 million that initially accrues interest at LIBOR plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries of the term conversion date that was obtained by Walnut Creek Energy. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.8135% beginning November 30, 2011 through May 31, 2013. The effective rate for the outstanding loan of $138 million was 2.75 % at December 31, 2011. Under the swap agreement for majority of the term loan, the fixed interest rate will be 3.5429% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 6.045%.
A second construction plus term loan financing of $53 million was obtained by WCEP Holdings, LLC that accrues interest at LIBOR plus 4.00% over the entire term. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.79% beginning July 29, 2011 through May 31, 2013. The effective rate for the outstanding loan of $49 million was 4.54% at December 31, 2011. Under the swap agreement for the majority of the term loan, the fixed interest rate will be 4.0025% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 8.00%.
In May 2011, EME purchased, through wholly owned subsidiaries, select equipment at AES Southland Funding, LLC and its affiliates' (AES's) Huntington Beach facilities and leased such equipment back to an AES affiliate until its planned

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decommissioning at the end of 2012 for which AES retained the ARO. The transaction resulted in an exemption for 90% of emission reduction credits needed to complete permitting activities for the Walnut Creek project. The $56 million of notes payable for the purchase was paid in July 2011.
Other Letters of Credit Facilities
As of December 31, 2011, a subsidiary of EME had a $10 million letter of credit facility with $2 million outstanding letters of credit.
Standby Letters of Credit
Letters of credit under EME's and its subsidiaries' credit facilities aggregated $177 million and were scheduled to expire as follows: $146 million in 2012, $3 million in 2013, $10 million in 2017, and $18 million in 2018. Standby letters of credit include $40 million issued in connection with the power purchase agreement with SCE, an affiliate of EME, under the Walnut Creek credit facility. Certain letters of credit are subject to automatic annual renewal provisions.

Note 6. Derivative Instruments and Hedging Activities
EME uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, transmission rights and 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 as derivative assets or liabilities with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized on EME's consolidated balance sheets as derivative assets or liabilities with offsetting changes in fair value, to the extent effective, recognized in accumulated other comprehensive loss until reclassified into earnings when the related forecasted transaction occurs. The portion of a cash flow hedge that does not offset the change in the fair value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.
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, with offsetting changes recognized in operating revenues on the consolidated statements of operations.
The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows.
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.
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
December 31, 2011
 
 
 
 
 
 
 
 
Hedging Activities
 
 
 
Commodity
 
Instrument
 
Classification
 
Unit of
Measure
 
Cash Flow
Hedges
 
Economic
Hedges
 
Trading
Activities
 
Electricity
 
Forwards/Futures
 
Sales, net
 
GWh
 
8,320

1 
425

3 
—

  
Electricity
 
Forwards/Futures
 
Purchases, net
 
GWh
 
—

 
—

 
2,926

  
Electricity
 
Capacity
 
Sales, net
 
MW-Day
(in thousands)
 
89

2 
—

  
—

 
Electricity
 
Capacity
 
Purchases, net
 
MW-Day
(in thousands)
 
—

 
—

  
184

2 
Electricity
 
Congestion
 
Purchases, net
 
GWh
 
—

  
2,528

4 
230,798

4 
Natural gas
 
Forwards/Futures
 
Sales, net
 
bcf
 
—

  
—

  
0.2

  
Fuel oil
 
Forwards/Futures
 
Purchases, net
 
barrels
 
—

  
240,000

  
—

  

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At December 31, 2011, EME had interest rate contracts with notional values totaling $644 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, EME had forward starting interest rate contracts with notional values totaling $506 million that will convert floating rate LIBOR-based debt to fixed rates of 3.5429%, 3.57% and 4.0025%. These contracts have effective dates of June 2013 and December 2021 and expire May 2023 and December 2029.
December 31, 2010
 
 
 
 
 
 
 
 
Hedging Activities
  
 
  
Commodity
 
Instrument
 
Classification
 
Unit of
Measure
 
Cash Flow
Hedges
  
Economic
Hedges
  
Trading
Activities
  
Electricity
 
Forwards/Futures
 
Sales, net
 
GWh
 
16,391

1 
—

 
—

  
Electricity
 
Forwards/Futures
 
Purchases, net
 
GWh
 
—

 
475

3 
3,039

  
Electricity
 
Capacity
 
Sales, net
 
MW-Day
(in thousands)
 
182

2 
—

  
—

 
Electricity
 
Capacity
 
Purchases, net
 
MW-Day
(in thousands)
 
—

 
—

  
283

2 
Electricity
 
Congestion
 
Purchases, net
 
GWh
 
—

  
1,007

4 
175,669

4 
Natural gas
 
Forwards/Futures
 
Purchases, net
 
bcf
 
—

  
—

  
3.7

  
Fuel oil
 
Forwards/Futures
 
Purchases, net
 
barrels
 
—

  
240,000

  
—

  
Coal
 
Forwards/Futures
 
Purchases, net
 
tons
 
—

  
—

  
15,000

  
1 
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.
2 
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.
3 
These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.
4 
Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.
At December 31, 2010, EME had interest rate contracts with notional values totaling $328 million that converted floating rate LIBOR-based debt to fixed rates ranging from 3.175% to 4.29%. These contracts expire June 2016 through March 2026.
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 3,332 GWh, 3,944 GWh and 3,791 GWh during 2011, 2010 and 2009, respectively.
Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EME's consolidated balance sheets:
December 31, 2011
 
Derivative Assets
 
Derivative Liabilities
 
 
(in millions)
Short-term
 
Long-term
 
Subtotal
 
Short-term
 
Long-term
 
Subtotal
 
Net Assets (Liabilities)
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
41

 
$
1

 
$
42

 
$
2

 
$
3

 
$
5

 
$
37

Interest rate contracts
—

 
—

 
—

 
—

 
90

 
90

 
(90
)
Economic hedges
31

 
1

 
32

 
26

 
1

 
27

 
5

Trading activities
276

 
142

 
418

 
232

 
79

 
311

 
107

 
348

 
144

 
492

 
260

 
173

 
433

 
59

Netting and collateral received1
(308
)
 
(85
)
 
(393
)
 
(259
)
 
(83
)
 
(342
)
 
(51
)
Total
$
40

 
$
59

 
$
99

 
$
1

 
$
90

 
$
91

 
$
8


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December 31, 2010
 
Derivative Assets
 
Derivative Liabilities
 
 
(in millions)
Short-term
 
Long-term
 
Subtotal
 
Short-term
 
Long-term
 
Subtotal
 
Net Assets (Liabilities)
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges
 
 
 
 


 
 
 
 
 


 


Commodity contracts
$
54

 
$
2

 
$
56

 
$
10

 
$
9

 
$
19

 
$
37

Interest rate contracts
—

 
—

 
—

 
—

 
16

 
16

 
(16
)
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

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 cash flow hedge activity as part of accumulated other comprehensive loss:
 
Cash Flow Hedge Activity1
 
 
 
2011
 
2010
 
 
(in millions)
Commodity Contracts
 
Interest Rate Contracts
 
Commodity Contracts
 
Interest Rate Contracts
 
Income Statement
Location
Beginning of period derivative gains (losses)
$
43

 
$
(16
)
 
$
177

 
$
(2
)
 
 
Effective portion of changes in fair value
55

 
(74
)
 
106

 
(14
)
 
 
Reclassification to earnings
(63
)
 
—

 
(240
)
 
—

 
Operating revenues
End of period derivative gains (losses)
$
35

 
$
(90
)
 
$
43

 
$
(16
)
 
 
1 
Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at December 31, 2011 and 2010 for commodity and interest rate contracts were $21 million and $(55) million and $26 million and $(10) million, respectively.
For additional information, see Note 11—Accumulated Other Comprehensive Income (Loss).
EME recorded net gains (losses) of $11 million, $(4) million and $24 million in 2011, 2010 and 2009, respectively, in operating revenues on the consolidated statements of operations 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 operations is presented below:
 
 
 
Years Ended December 31,
(in millions)
 
Income Statement Location
2011
 
2010
Economic hedges
 
Operating revenues
$
21

 
$
8

 
 
Fuel
3

 
2

Trading activities
 
Operating revenues
76

 
114

Energy Trading Derivative Instruments
The change in the fair value of energy trading derivative instruments was as follows:

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(in millions)
2011
 
2010
Fair value of trading contracts at beginning of period
$
110

 
$
122

Net gains from energy trading activities
76

 
114

Amount realized from energy trading activities
(84
)
 
(131
)
Other changes in fair value
5

 
5

Fair value of trading contracts at end of period
$
107

 
$
110

Contingent Features
Certain derivative instruments contain margin and collateral deposit requirements. Since EME's and its subsidiaries' credit ratings are below investment grade, EME and its subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. Future increases in power prices could expose EME, Midwest Generation or EMMT to additional collateral postings. Furthermore, EMMT 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 adverse development affecting the other party.
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 on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:
 
December 31,
(in millions)
2011
 
2010
Collateral provided to counterparties
 
 
 
Offset against derivative liabilities
$
2

 
$
4

Reflected in margin and collateral deposits
41

 
59

Collateral received from counterparties
 
 
 
Offset against derivative assets
53

 
52

Commodity Price Risk Management
EME's merchant operations are exposed 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 and 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

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trade obligation, EME would be exposed to the risk of possible loss associated with market price changes occurring since the original contract was executed if the nonperforming counterparty were unable to pay the resulting damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.
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 manage credit risk, EME evaluates the risk of potential defaults by counterparties. 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 69%, 66% and 48% of EME's consolidated operating revenues for the years ended December 31, 2011, 2010 and 2009, 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, 2011 and 2010, EME's account receivable due from PJM was $62 million and $64 million, respectively.
For the years ended December 31, 2011 and 2010, a second customer, Constellation Energy Commodities Group, Inc. accounted for less than 10% and, in 2009, 16% 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, 2011 and 2010, EME's account receivable due from Constellation was $7 million and $32 million, respectively.

Note 7. Income Taxes
Current and Deferred Taxes
The provision (benefit) for income taxes is composed of the following:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Continuing Operations
 
 
 
 
 
Current
 
 
 
 
 
Federal
$
50

 
$
(288
)
 
$
(176
)
State
(45
)
 
18

 
(35
)
Total current
5

 
(270
)
 
(211
)
Deferred
 
 
 
 
 
Federal
$
(731
)
 
$
278

 
$
187

State
(130
)
 
11

 
40

Total deferred
(861
)
 
289

 
227

Provision (benefit) for income taxes from continuing operations
(856
)
 
19

 
16

Discontinued operations
4

 
9

 
(2
)
Total
$
(852
)
 
$
28

 
$
14

EME recorded a tax benefit of $16 million in 2010 resulting from acceptance by the California Franchise Tax Board of the tax

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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)
2011
 
2010
 
2009
Continuing operations
$
(1,932
)
 
$
178

 
$
217

Discontinued operations
1

 
13

 
(9
)
Total
$
(1,931
)
 
$
191

 
$
208

The components of net accumulated deferred income tax asset (liability) were:
 
December 31,
(in millions)
2011
 
2010
Deferred tax assets
 
 
 
Accrued charges and liabilities
$
303

 
$
201

Net operating loss carryforwards
326

 
—

Production tax and other credit carryforwards
194

 
60

Derivative instruments
49

 
—

Other
—

 
2

Total
872

 
263

Deferred tax liabilities
 
 
 
Basis differences in property
$
638

 
$
1,117

Deferred investment tax credit
5

 
4

State taxes
20

 
9

Other
6

 
3

Total
669

 
1,133

Deferred tax assets and (liabilities), net
$
203

 
$
(870
)
Classification of net accumulated deferred income taxes
 
 
 
Included in other assets
$
205

 
$
—

Included in current liabilities
$
2

 
$
34

Included in deferred taxes and tax credits
$
—

 
$
836

As of December 31, 2011, EME had $903 million of federal net operating loss carryforwards which expire in 2031, $169 million of state net operating loss carryforwards which expire between 2015 and 2031, if unused. Additionally, there were $194 million of federal tax credit carryforwards of which $179 million expire between 2029 and 2031, if unused, and the remainder have no expiration date. These net operating loss carryforwards and federal tax credit carryforwards resulted in $520 million of deferred tax assets at December 31, 2011.
Effective Tax Rate
The table below provides a reconciliation of income tax expense (benefit) computed at the federal statutory income tax rate to the income tax provision (benefit):

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Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Income (loss) from continuing operations before income taxes
$
(1,932
)
 
$
178

 
$
217

Provision (benefit) for income taxes at federal statutory rate of 35%
$
(676
)
 
$
62

 
$
76

Increase (decrease) in income tax from:
 
 
 
 
 
State tax-net of federal benefit1
(104
)
 
9

 
7

Production tax credits, net
(66
)
 
(61
)
 
(55
)
Qualified production deduction
(6
)
 
15

 
(2
)
Deferred tax adjustments
(8
)
 
6

 
—

Resolution of 1986-2002 state tax issues
—

 
(16
)
 
—

Other
4

 
4

 
(10
)
Total provision (benefit) for income taxes from continuing operations
$
(856
)
 
$
19

 
$
16

Effective tax rate
44
%
 
11
%
 
7
%
1 
Excludes state tax settlement in 2010.
Accounting for Uncertainty in Income Taxes
Unrecognized Tax Benefits
The following table provides a reconciliation of unrecognized tax benefits:
(in millions)
2011
 
2010
 
2009
Balance at January 1
$
153

 
$
115

 
$
144

Tax positions taken during the current year
 
 
 
 
 
Increases
9

 
—

 
—

Decreases
—

 
—

 
—

Tax positions taken during a prior year
 
 
 
 
 
Increases
9

 
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
$
171

 
$
153

 
$
115

As of December 31, 2011 and 2010, $166 million and $148 million, respectively, of the unrecognized tax benefits, if recognized, would impact the effective tax rate. EME believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $10 million within the next 12 months.
Edison International's federal income tax returns and 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 and penalties related to EME's income tax liabilities was $47 million and $32 million as of December 31, 2011 and 2010, respectively.
The net after-tax interest and penalties recognized in income tax expense was $10 million, $19 million and $(45) million for

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2011, 2010 and 2009, respectively.
Tax Dispute
The Internal Revenue Service examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included a proposed adjustment related to EME. The EME-related proposed adjustment increases the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $193 million, including interest and penalties through December 31, 2011 (the Internal Revenue Service has asserted a 40% penalty for understatement of tax liability related to this matter). Edison International disagrees with the proposed adjustment and filed a protest with the Internal Revenue Service in the first quarter of 2011. The disputed tax matter is currently being considered in appeals.
Bonus Depreciation Impact on EME
The Small Business Jobs Act of 2010 and the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (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. As a result of these provisions, Edison International has a consolidated net operating loss for federal income tax purposes for 2011. EME does not expect tax benefits to be fully utilized by Edison International on a consolidated basis for several years. In the third quarter of 2011, EME received tax-allocation payments of $182 million as a result of the carryback of Edison International consolidated net operating losses for 2010. However, EME expects to make tax-allocation payments to Edison International during 2012 of approximately $185 million as a result of the reallocation of tax obligations from an expected Edison International consolidated net operating loss in 2011.

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 $15 million in 2011, $14 million in 2010 and $13 million in 2009.
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 $18 million for the year ended December 31, 2012.
The funded position of the company's pension is very sensitive to changes in market conditions. Changes in overall interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund the company's long-term pension are affected by movements in the equity and bond markets. The market value of the investments (reflecting investment returns, contributions and benefit payments) within the plan trusts declined 35% during 2008. This reduction in value of plan assets combined with increased liabilities has resulted in a change in the pension plan funding status from a surplus to a material deficit, which will result in increased future expense and cash contributions. The company pension remains underfunded as liabilities have increased significantly as a result of steady declines in interest rates.
Information on plan assets and benefit obligations is shown below:

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Years Ended December 31,
(in millions)
2011
 
2010
Change in projected benefit obligation
 
 
 
Projected benefit obligation at beginning of year
$
287

 
$
243

Service cost
16

 
16

Interest cost
14

 
14

Actuarial loss
12

 
22

Benefits paid
(13
)
 
(8
)
Projected benefit obligation at end of year
$
316

 
$
287

Change in plan assets
 
 
 
Fair value of plan assets at beginning of year
$
164

 
$
128

Actual return on plan assets
2

 
20

Employer contributions
24

 
24

Benefits paid
(13
)
 
(8
)
Fair value of plan assets at end of year
$
177

 
$
164

Funded status at end of year
$
(139
)
 
$
(123
)
Amounts recognized on consolidated balance sheets:
 
 
 
Long-term liabilities
$
(139
)
 
$
(123
)
Amounts recognized in accumulated other comprehensive income:
 
 
 
Prior service cost
$
1

 
$
1

Net loss
69

 
47

Accumulated benefit obligation at end of year
$
278

 
$
245

Pension plans with an accumulated benefit obligation in excess of plan assets:
 
 
 
Projected benefit obligation
$
316

 
$
287

Accumulated benefit obligation
278

 
245

Fair value of plan assets
177

 
164

Weighted-average assumptions used to determine obligations at end of year:
 
 
 
Discount rate
4.50
%
 
5.25
%
Rate of compensation increase
4.50
%
 
4.5% to 6.0%

Expense components and other amounts recognized in other comprehensive (income) loss
Expense components:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Service cost
$
16

 
$
16

 
$
15

Interest cost
14

 
14

 
13

Expected return on plan assets
(12
)
 
(10
)
 
(8
)
Net amortization
3

 
2

 
4

Total expense
$
21

 
$
22

 
$
24

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

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Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Net loss (gain)
$
25

 
$
12

 
$
(7
)
Prior service cost
—

 
—

 
—

Amortization of net loss
(3
)
 
(2
)
 
(4
)
Total in other comprehensive (income) loss
$
22

 
$
10

 
$
(11
)
Total in expense and other comprehensive (income) loss
$
43

 
$
32

 
$
13

The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2012 are $0.1 million for prior service costs and $5.4 million for net loss.
The following are weighted-average assumptions used to determine expenses:
 
Years Ended December 31,
 
2011
 
2010
 
2009
Discount rate
5.25
%
 
6.00
%
 
6.25
%
Rate of compensation increase
4.5% to 6.0%

 
4.5% to 6.0%

 
5.0% to 6.0%

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)
 
2012
$
12

2013
14

2014
16

2015
18

2016
20

2017-2021
121

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 $3 million for the year ended December 31, 2012.
Information on plan assets and benefit obligations is shown below:

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Years Ended December 31,
(in millions)
2011
 
2010
Change in benefit obligation
 
 
 
Benefit obligation at beginning of year
$
122

 
$
94

Service cost
3

 
2

Interest cost
6

 
5

Amendments
—

 
11

Actuarial loss
1

 
12

Benefits paid
(2
)
 
(2
)
Benefit obligation at end of year
$
130

 
$
122

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
$
(130
)
 
$
(122
)
Amounts recognized on consolidated balance sheets:
 
 
 
Long-term liabilities
$
(130
)
 
$
(122
)
Amounts recognized in accumulated other comprehensive income:
 
 
 
Prior service cost (credit)
$
8

 
$
8

Net loss
23

 
23

Weighted-average assumptions used to determine obligations at end of year:
 
 
 
Discount rate
4.75
%
 
5.5
%
Assumed health care cost trend rates:
 
 
 
Rate assumed for following year
9.50
%
 
9.75
%
Ultimate rate
5.25
%
 
5.5
%
Year ultimate rate reached
2019

 
2019

Expense components and other amounts recognized in other comprehensive (income) loss
Expense components:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Service cost
$
3

 
$
2

 
$
2

Interest cost
6

 
6

 
5

Amortization of prior service credit
(1
)
 
(2
)
 
(1
)
Amortization of net loss
1

 
1

 
1

Total expense
$
9

 
$
7

 
$
7

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

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Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Net loss (gain)
$
—

 
$
12

 
$
(8
)
Prior service cost (credit)
—

 
11

 
(2
)
Amortization of prior service credit
1

 
1

 
1

Amortization of net loss
(1
)
 
(1
)
 
(1
)
Total in other comprehensive (income) loss
$
—

 
$
23

 
$
(10
)
Total in expense and other comprehensive (income) loss
$
9

 
$
30

 
$
(3
)
The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2012 are $0.2 million for prior service credit and $1.3 million for net loss.
The following are weighted-average assumptions used to determine expense:
 
Years Ended December 31,
 
2011
 
2010
 
2009
Discount rate
5.50
%
 
6.00
%
 
6.25
%
Assumed health care cost trend rates:
 
 
 
 
 
Current year
9.75
%
 
8.25
%
 
8.75
%
Ultimate rate
5.50
%
 
5.5
%
 
5.5
%
Year ultimate rate reached
2019

 
2016

 
2016

Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of December 31, 2011, by $22 million and annual aggregate service and interest costs by $2 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated benefit obligation as of December 31, 2011, by $19 million and annual aggregate service and interest costs by $1 million.
The following benefit payments are expected to be paid:
Years Ending December 31,
(in millions)
Before
Subsidy1
 
Net
2012
$
3

 
$
3

2013
3

 
3

2014
4

 
4

2015
5

 
5

2016
5

 
5

2017-2021
38

 
37

1 
Medicare Part D prescription drug benefits.
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 U.S. equities, 16% for non-U.S. 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 is measured against targets. Edison International also monitors the stability of its investment managers' organizations.
Allowable investment types include:
•
United States Equities: Common and preferred stocks of large, medium, and small companies which are predominantly

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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 portion of the fixed income positions may be held in debt securities that are below investment grade.
Opportunistic, Alternative and Other Investments:
•
Opportunistic: Investments in short to intermediate term market opportunities. Investments may have fixed income and/or equity characteristics and may be either liquid or illiquid.
•
Alternative: Limited partnerships that invest in non-publicly traded entities.
•
Other: Investments diversified among multiple asset classes such as global equity, fixed income currency and commodities markets. Investments are made in liquid instruments within and across markets. The investment returns are expected to approximate the plans' expected investment returns.
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
Our capital markets return forecast methodologies primarily use a combination of historical market data, current market conditions, proprietary forecasting expertise, complex models to develop asset class return forecasts and a building block approach. The forecasts are developed using variables such as real risk-free interest, inflation, and asset class specific risk premiums. For equities, the risk premium is based on an assumed average equity risk premium of 6% over cash. The forecasted return on private equity and opportunistic investments are estimated at a 3% premium above public equity, reflecting a premium for higher volatility and liquidity. For fixed income, the risk premium is based off of a comprehensive modeling of credit spreads.
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 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. Futures contracts trade on an exchange and therefore are 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

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at footnote 7 to the pension plan master trust investments table below.
Edison International reviews the process/procedures of both the pricing services and the trustee to gain an understanding of the inputs/assumptions and valuation techniques used to price each asset type/class. For further discussion see Note 4—Fair Value Measurements.
Pension Plan
The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2011 by asset class and level within the fair value hierarchy:
(in millions)
Level 1
 
Level 2
 
Level 3
 
Total
Corporate stocks1
$
642

 
$
—

 
$
—

 
$
642

Partnerships/joint ventures2
—

 
140

 
448

 
588

Common/collective funds3
—

 
582

 
—

 
582

Corporate bonds4
—

 
497

 
—

 
497

U.S. government and agency securities5
104

 
351

 
—

 
455

Other investment entities6
—

 
247

 
—

 
247

Registered investment companies7
79

 
29

 
—

 
108

Interest-bearing cash
5

 
—

 
—

 
5

Other
(1
)
 
69

 
—

 
68

Total
$
829

 
$
1,915

 
$
448

 
$
3,192

Receivables and payables, net
 

 
 

 
 

 
(39
)
Net plan assets available for benefits
 

 
 

 
 

 
3,153

EME's share of net plan assets
 
 
 
 
 
 
$
177

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

Partnerships/joint ventures2
—

 
155

 
345

 
500

Common/collective funds3
—

 
600

 
—

 
600

Corporate bonds4
—

 
555

 
—

 
555

U.S. government and agency securities5
84

 
316

 
—

 
400

Other investment entities6
—

 
236

 
—

 
236

Registered investment companies7
84

 
92

 
—

 
176

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

1 
Corporate stocks are diversified. For 2011 and 2010, respectively, performance is primarily benchmarked against the Russell Indexes (60% and 63%) and Morgan Stanley Capital International (MSCI) index (40%and 37%).
2 
Partnerships/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. At December 31, 2011 and 2010, respectively, approximately 55% and 60% of the Level 3 partnerships are invested in (1) asset backed securities, including distressed mortgages and (2) commercial and residential loans and debt and equity of banks. 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 US and non-US fund-of-funds.

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3 
At December 31, 2011 and 2010, 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 29%), Russell 200 and Russell 1000 indexes (27% and 28%) and the MSCI Europe, Australasia and Far East (EAFE) Index (10% and 11%). A non-index U.S. equity fund representing 23% of this category for both 2011 and 2010 is actively managed. Another fund representing 8% of this category for both 2011 and 2010 is a global asset allocation fund.
4 
Corporate bonds are diversified. At December 31, 2011 and 2010, respectively, this category includes $53 million and $65 million for collateralized mortgage obligations and other asset backed securities of which $10 million and $17 million are below investment grade.
5 
Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal National Mortgage Association and the Federal Home Loan Mortgage Corporation.
6 
Other investment entities were primarily invested in (1) emerging market equity securities, (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, and (3) domestic mortgage backed securities.
7 
Level 1 of registered investment companies consisted of a global equity mutual fund which seeks to outperform the MSCI World Total Return Index. Level 2 primarily consisted of short-term, emerging market, high yield bond funds and government inflation-indexed bonds.
At both December 31, 2011 and 2010, approximately 69% 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 2011 and 2010:
(in millions)
2011
 
2010
Fair value, net at beginning of period
$
345

 
$
240

Actual return on plan assets:
 
 
 
Relating to assets still held at end of period
6

 
42

Relating to assets sold during the period
22

 
24

Purchases
130

 
108

Dispositions
(55
)
 
(69
)
Transfers in and /or out of Level 3
—

 
—

Fair value, net at end of period
$
448

 
$
345

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 and 2011, is 49.5 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, 2011, Edison International had approximately 30 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 "Stock-Based Compensation" in Note 1. Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the option term. Stock options granted in 2007 and later have no dividend equivalent rights except for options granted to Edison International's Board of Directors in 2007. Unless transferred to nonqualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.
The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table:

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Years Ended December 31,
 
2011
 
2010
 
2009
Expected terms (in years)
7.0

 
7.3

 
7.4

Risk-free interest rate
1.4% - 3.1%

 
2.0% to 3.2%

 
2.8% to 3.5%

Expected dividend yield
3.1% - 3.5%

 
3.3% to 4.0%

 
3.6% to 5.0%

Weighted-average expected dividend yield
3.4
%
 
3.8
%
 
5.0
%
Expected volatility
18% - 19%

 
19% to 20%

 
20% to 21%

Weighted-average volatility
18.9
%
 
19.8
%
 
20.6
%
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 length of the options expected term for 2011. The volatility period used was 84 months, 87 months and 84 months at December 31, 2011, 2010 and 2009, 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, 2010
3,492,437

 
$
32.57

 
 

 
 

Granted
617,284

 
38.05

 
 

 
 

Expired
(103,075
)
 
48.38

 
 

 
 

Transferred to affiliates
(113,421
)
 
32.25

 
 

 
 

Forfeited
(78,777
)
 
31.12

 
 

 
 

Exercised
(469,837
)
 
26.07

 
 

 
 

Outstanding, December 31, 2011
3,344,611

 
34.05

 
5.62

 
 

Vested and expected to vest at December 31, 2011
3,259,991

 
34.05

 
5.56

 
$
28,845,778

Exercisable at December 31, 2011
1,907,003

 
34.10

 
3.77

 
18,246,955

At December 31, 2011, 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 years.
Performance Shares
A target number of contingent performance shares were awarded to executives in March 2009, March 2010 and March 2011, and vest at the end of December 2011, 2012 and 2013, 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.

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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,
 
2011
 
2010
 
2009
Equity awards
 
 
 
 
 
Grant date risk-free interest rate
1.2
%
 
1.3
%
 
1.3
%
Grant date expected volatility
20.4
%
 
21.6
%
 
21.4
%
Liability awards1
 
 
 
 
 
Expected volatility
15.9
%
 
20.6
%
 
21.9
%
Risk-free interest rate
 
 
 
 
 
2011 awards
0.3
%
 
—

 
—

2010 awards
0.2
%
 
0.6
%
 
—

2009 awards
—
%
 
0.3
%
 
1.1
%
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 with terms nearest to the remaining term of the performance shares 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.
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, 2010
83,750

 
$
29.84

 
83,750

 
 

Granted
27,836

 
31.14

 
27,836

 
 

Forfeited1
(23,777
)
 
40.10

 
(23,777
)
 
 

Transferred to affiliates
(3,496
)
 
26.90

 
(3,496
)
 
 

Nonvested at December 31, 2011
84,313

 
27.50

 
84,313

 
$
29.48

1 
Includes performance shares that expired with zero value as performance targets were not met.
The current portion of nonvested performance shares classified as liability awards is reflected in accrued liabilities and the long-term portion is reflected in other long-term liabilities on the consolidated balance sheets.
At December 31, 2011, there was $0.7 million (based on the December 31, 2011 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.
Restricted Stock Units
Restricted stock units were awarded to executives in March 2009, March 2010 and March 2011 and vest and become payable in January 2012, 2013 and 2014, 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.
The following is a summary of the status of Edison International nonvested restricted stock units granted to EME employees:

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Restricted
Stock Units
 
Weighted-Average
Grant-Date
Fair Value
Nonvested at December 31, 2010
127,392

 
$
32.23

Granted
45,592

 
38.03

Forfeited
(3,223
)
 
33.16

Paid Out
(33,264
)
 
44.93

Affiliate transfers—net
(6,747
)
 
30.56

Nonvested at December 31, 2011
129,750

 
32.11

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, 2011, there was $1.4 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $ 0.4 million in 2012 and $1 million in 2013.
Supplemental Data on Stock-Based Compensation

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Years Ended December 31,
(in millions, except per award amounts)
2011
 
2010
 
2009
Stock-based compensation expense (benefit)1
 
 
 
 
 
Stock options
$
2

 
$
4

 
$
3

Performance shares
1

 
2

 
1

Restricted stock units
2

 
1

 
1

Other
2

 
2

 
3

Total stock-based compensation expense (benefit)
$
7

 
$
9

 
$
8

Income tax benefits related to stock compensation expense
$
3

 
$
4

 
$
3

Excess tax benefits2
1

 
1

 
—

Stock options
 
 
 
 
 
Weighted average grant date fair value per option granted
$
5.61

 
$
4.92

 
$
3.00

Fair value of options vested
3

 
3

 
3

Cash used to purchase shares to settle options
18

 
11

 
1

Cash from participants to exercise stock options
12

 
6

 
1

Value of options exercised
6

 
4

 
0.4

Tax benefits from options exercised
2

 
2

 
0.2

Performance shares3 classified as equity awards
 
 
 
 
 
Weighted average grant date fair value per share granted
$
31.14

 
$
32.50

 
$
21.06

Fair value of shares vested
0.8

 
0.9

 
0.2

Restricted stock units
 
 
 
 
 
Weighted average grant date fair value per unit granted
$
38.03

 
$
33.30

 
$
24.99

Value of shares settled
$
2

 
$
—

 
$
—

Tax benefits realized from settlement of awards
$
1

 
$
—

 
$
—

1 
Reflected in administration and general on the consolidated statements of operations.
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 
There were no settlements of awards for performance shares in 2011, 2010 and 2009 as performance targets were not met.
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 2039.
Future minimum payments for operating leases at December 31, 2011 are:

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Years Ending December 31,
(in millions)
Homer City
Plant
 
Powerton and
Joliet Power
Stations
 
Other Operating
Leases
2012
$
160

 
$
151

 
$
26

2013
149

 
151

 
30

2014
138

 
151

 
18

2015
107

 
67

 
17

2016
89

 
26

 
14

Thereafter
1,171

 
241

 
145

Total future commitments
$
1,814

 
$
787

 
$
250

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 $213 million, $217 million and $209 million in 2011, 2010 and 2009, 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 an owner-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.
Under the sale-leaseback documents, Homer City rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to secured lease obligation bondholders, while equity rent is paid to the owner-lessors. In order to pay equity rent, among other requirements, Homer City must meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). The senior rent service coverage ratio of 1.18 to 1 for the 12 months ended December 31, 2011 was below the covenant threshold and Homer City also did not meet the threshold for the prospective two 12-month periods, which currently precludes Homer City from making distributions, including repayment of certain intercompany loans and from paying the equity portion of the rent payment. A failure to pay equity rent does not entitle the owner-lessors to foreclose upon Homer City's leasehold interest, but it does result in the suspension of Homer City's ability to make permitted distributions. Moreover, Homer City would be permanently restricted in its ability to make permitted distributions if a failure to pay equity rent when due was not cured within nine months, or even if cured, occurred more than one additional time during the term of the lease. Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. Also, failure by Homer City to pay equity rent when due in April 2012 could trigger termination of the $48 million senior rent reserve letter of credit. Homer City would then be required to fund the senior rent reserve, and failure to do so could entitle counterparties to seek available remedies under the sale-leaseback documents, including termination or foreclosure upon the leasehold interest. As a result of the expectation that EME is likely to lose substantially all beneficial economic interest in and material control of the Homer City plant, EME recorded an impairment charge of $1,032 million for the fourth quarter of 2011. For further discussion, see Note 13—Asset Impairments and Other Charges.
On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power stations 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 station, EME has a right of first refusal to acquire the interest at fair market value. The gain on the sale of the power stations 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, 2011, Midwest Generation met these covenants. In addition, the lease agreements and the Midwest Generation credit agreement contain covenants that include restrictions on the ability of these subsidiaries 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.

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Other Commitments
Certain other minimum commitments are estimated as follows:
(in millions)
2012
 
2013
 
2014
 
2015
 
2016
Midwest Generation fuel supply contracts
$
223

 
$
145

 
$
150

 
$
—

 
$
—

Midwest Generation coal transportation agreements1
386

 
326

 
333

 
315

 
315

Homer City fuel supply contracts
214

 
53

 
—

 
—

 
—

Gas transportation agreements
7

 
7

 
7

 
7

 
8

Capital expenditures
286

 
19

 
—

 
—

 
—

Other contractual obligations
93

 
46

 
19

 
12

 
5

 
$
1,209

 
$
596

 
$
509

 
$
334

 
$
328

1 
In years 2013 through 2016, represents contracts for minimum volumes without regard to payment of alternative liquidated damages or plant closures.
Fuel Supply Contracts and Coal Transportation Agreements
At December 31, 2011, Midwest Generation and Homer City had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. In addition, Midwest Generation had contractual agreements for the transportation of coal. The commitments under these contracts are based on either actual coal purchases derived from committed coal volumes set forth in fuel supply contracts or minimum quantities as set forth in the transportation agreements. The transportation agreements have provisions that address the financial exposure of Midwest Generation related to a plant closure under certain circumstances as specified in the agreements.
Gas Transportation Agreements
At December 31, 2011, 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 six years, is estimated to aggregate $36 million in the next five years. EME has entered into agreements to re-sell the transportation under this agreement which aggregates $45 million over the same period.
Capital Commitments
At December 31, 2011, EME's subsidiaries had firm commitments for capital expenditures primarily related to the Walnut Creek project and the construction of wind projects. EME intends to fund these expenditures through project-level financing, U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from operations.
Other Contractual Obligations
At December 31, 2011, 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 indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.
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 indemnification obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the owner-lessors for specified environmental liabilities. These indemnities are not limited in term or amount. 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

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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 and Other Litigation." 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 Midwest Generation's 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. 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 2013. There were approximately 226 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at December 31, 2011. While the range of this liability is between $46 million and $64 million, Midwest Generation had recorded an estimated liability of $54 million and $56 million at December 31, 2011 and 2010, respectively, related to this contractual indemnity.
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. 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 owner-lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. EME has not recorded a liability related to this indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review and Other Litigation."
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. At December 31, 2011 and 2010, EME had recorded a liability of $36 million and $42 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, including for taxes imposed with respect to operations of the assets prior to the sale. Not all indemnities under the asset sale agreements have specific expiration dates. Due to the nature of these potential obligations, EME cannot determine a range of estimates and has not recorded a liability related to these indemnities.
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. Under certain of these tax indemnity agreements, Homer City and Midwest Generation, as the lessees in the sale-leaseback transactions agreed to indemnify the respective owner-lessors for specified adverse tax consequences that could result from certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. Although the Collins Station lease terminated in April 2004, Midwest Generation's indemnities in favor of its former lease equity investors are still in effect. EME provided similar indemnities in the sale-leaseback transactions related to the Powerton and Joliet Stations in Illinois. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a range of estimated obligation which would be triggered by a valid claim from the owner-lessors. EME has not recorded a liability for these matters.
In addition to the indemnity provided by Homer City, EME agreed to indemnify the owner-lessors in the sale-leaseback transaction related to the Homer City plant for certain negative federal income tax consequences should the rent payments be "levelized" for tax purposes and for potential foreign tax credit losses in the event that the owner-lessor's debt is characterized as recourse, rather than nonrecourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.
Other Indemnities
EME provides other indemnifications through contracts entered into in the normal course of business. These include, among other things, indemnities for specified environmental liabilities and for income taxes with respect to assets sold. EME's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances EME may have recourse against third parties. EME cannot determine a range of estimates and has not recorded a liability related to these

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indemnities.
Contingencies
In addition to the matters disclosed in these notes, EME is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. EME believes the outcome of these other proceedings, individually and in the aggregate, will not materially affect its results of operations or liquidity.
Midwest Generation New Source Review and Other Litigation
In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois 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) emission 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 called for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint and other remedies. 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 intervened in the case.
Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address 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. The dismissals have been certified as "partial final judgments" capable of appeal, and an appeal is pending before the Seventh Circuit Court of Appeals. The remaining claims are stayed pending the appeal.
In January 2012, two complaints were filed against Midwest Generation in Illinois state court by residents living near the Crawford and Fisk Stations on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages. The complaints are similar to two complaints previously filed in the Northern District of Illinois, which were dismissed in October 2011 for lack of federal jurisdiction.
Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Midwest Generation and EME. EME cannot predict the outcome of these matters or estimate the impact on the Midwest Generation plants, or its and Midwest Generation's results of operations, financial position or cash flows. EME has not recorded a liability for this matter.
Homer City New Source Review and Other Litigation
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 alleged violations of the PSD and Title V provisions of the CAA, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure 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 called for an injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint and for other remedies. The PADEP (Pennsylvania Department of Environmental Protection), the State of New York and the State of New Jersey intervened in the lawsuit. In October 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. An appeal of the dismissal is pending before the Third Circuit Court of Appeals.
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, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs sought to have their suit certified as a class action and requested injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and punitive damages. In October 2011, the claims in the purported class action lawsuit that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court

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should the plaintiffs choose to do so. EME does not know whether the plaintiffs will file a complaint in state court.
In February 2012, Homer City received a 60-day Notice of Intent to Sue indicating the Sierra Club’s intent to file a citizen lawsuit alleging violations of emissions standards and limitations under the CAA and the Pennsylvania Air Pollution Control Act.
Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows. EME has not recorded a liability for this matter.
Environmental Remediation
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 subsidiaries' 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.
With respect to potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as 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 a probable amount of approximately $9 million at December 31, 2011 for estimated environmental investigation and remediation costs for four stations at 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. EME also has identified sites for which a reasonable estimate cannot be made. 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.
Insurance
At December 31, 2011 and 2010, EME's subsidiaries had recorded receivables of $3 million and $10 million, respectively, primarily related to insurance claims from unplanned outages. During 2011, 2010 and 2009, $5 million, $2 million and $2 million, respectively, related to business interruption insurance coverage was recorded and has been reflected in other income (expense), net on EME's consolidated statements of operations. EME's subsidiaries received $16 million and $17 million in cash payments related to insurance claims during 2011and 2010, respectively.

Note 10. Environmental Developments
Midwest Generation Environmental Compliance Plans and Costs
During 2011, Midwest Generation continued to advance necessary activities for nitrogen oxide (NOx) and sulfur dioxide (SO2) controls to meet the requirements of the CPS. Midwest Generation has substantially completed the installation of selective non-catalytic reduction (SNCR) technology on multiple units to meet the NOx portion of the CPS and has received all necessary permits from the Illinois EPA for the installation of 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. In February 2012, Midwest Generation received an extension of its permit to install a dry sorbent injection system at the Powerton Station.
Decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2 emissions, including those that have received permits, are subject to a number of factors, such as market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation may also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Decisions about any particular combination of retrofits and shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable regulations. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014 and concluded it was less likely to retrofit the Waukegan Station rather than the larger Powerton, Joliet and Will County Stations. As a result, EME recorded an impairment charge of $640 million at December 31, 2011 related to the Crawford, Fisk and Waukegan Stations. For further discussion, see Note 13—Asset Impairments and Other Charges. Units that are not retrofitted may continue to operate until required to shut down by applicable regulations or operate with

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reduced output.
In connection with its decision to close the Fisk and Crawford Stations, Midwest Generation entered into a Memorandum of Understanding with the City of Chicago, acting through the Commissioner of Health, which acknowledges that the cessation of coal-fired electric generation at the Fisk and Crawford Stations will achieve the objectives of the proposed Chicago Clean Power Ordinance without a need to pass the proposed Clean Power Ordinance or similar ordinances (recognizing that such agreement cannot bind the Chicago City Council or its members). Midwest Generation and the City of Chicago have also agreed to collaborate with key stakeholders to consider potential future uses, ownership and sources of external funding to transition the sites for such uses. The closure of the Fisk and Crawford Stations will be subject to review for reliability by PJM Interconnection LLC, the regional transmission organization that controls the area where these plants are located. In total, Midwest Generation estimates 150 to 180 employees will be affected. The timing and amount of severance benefits, if any, will be determined after completion of review of personnel based on seniority and other factors and, in the case of the Crawford Station, the amount may be affected by the timing of the plant closure. Other obligations related to the Fisk and Crawford Stations could be affected by the plant closing, including sales of capacity, for which Midwest Generation is unable to reasonably estimate the impact, or range of impacts, that could be incurred. Midwest Generation does not expect to incur future capital expenditures to close these plants.
Based on work to date, Midwest Generation estimates the cost of retrofitting the large stations (Powerton, Joliet Units 7 and 8 and Will County) 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 up to approximately $628 million. The cost of retrofitting Joliet Unit 6 is not included in the large unit amounts as it is less likely that Midwest Generation will make retrofits for this unit. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. For further discussion related to EME's impairment policy on the unit of account, see Note 1—Summary of Significant Accounting Policies—Impairment of Long-Lived Assets.
Homer City Environmental Issues and Capital Resource Limitations
Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. Based on preliminary estimates, Homer City expects the cost of such equipment to be approximately $700 million to $750 million. However, construction of these improvements is dependent upon funding from the owner-lessors or other third parties. For additional information, see Note 13—Asset Impairments and Other Charges.
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, which could adversely affect EME's business.
Significant developments include the following:
•
In June 2010, the US EPA issued the Prevention of Significant Deterioration (PSD) 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 (and later, to 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 emissions control requirements that could delay such projects. 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.
•
Under a pending court settlement, the US EPA was to propose performance standards for GHG emissions from new and modified power plants. The specific requirements will not be known until the regulations are finalized.
•
In December 2011, the California Air Resources Board (CARB) regulation was officially published, establishing a California cap-and-trade program. The first compliance period under the regulations is for 2013 GHG emissions.
•
In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions the CAA authorizes displace federal common law nuisance claims that might arise from the emission of greenhouse gases. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the

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same circumstances.
•
An appeal before the Ninth Circuit of a federal district order dismissing a case against EME's parent company, Edison International, and other defendants, had been deferred pending the U.S. Supreme Court's ruling described above. In the case, which was brought by the Alaskan Native Village of Kivalina, the plaintiffs seek damages of up to $400 million for the cost of relocating the village, which they claim is no longer protected from storms because the Arctic sea ice has melted as the result of climate change. The stay of the appeal has been lifted and argument before the Ninth Circuit was held in November 2011.
•
In May 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming a large number of defendants, including EME and three of its wholly owned subsidiaries. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.
Cross-State Air Pollution Rule
On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule (CSAPR). CSAPR establishes emissions reductions for annual sulfur dioxide (SO2) emissions and annual and ozone season nitrogen oxide (NOx) emissions in two phases: a first phase originally scheduled to be effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.
In December 2011, the United States Court of Appeals for the District of Columbia granted a stay of CSAPR pending completion of its review of the rule's validity. Oral argument is scheduled for April 13, 2012, and a court decision is expected during the third quarter of 2012. The court directed the US EPA to continue administering the CAIR until its review is completed.
Hazardous Air Pollutant Regulations
In December 2011, the US EPA announced the Mercury and Air Toxics Standards (MATS) rule, limiting emissions of hazardous air pollutants (HAPs) from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on February 16, 2012, and becomes effective on April 16, 2012. EME does not expect that these standards will require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. EME also does not expect that these standards will require Homer City to make additional capital expenditures beyond those that would be required for compliance with CSAPR Phase II.

Water Quality
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. In March 2011, the US EPA proposed standards under the federal Clean Water Act that would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and EME is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants, but are not expected to be material for the Homer City plant, which already has cooling towers.
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 that could result in their reclassification. 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 as permit requirements) to be exclusively a matter of state law. Many of the proposed technical standards are similar under both proposed

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options (for example, surface impoundments may need to be retrofitted, depending on which standard is finally adopted), but the second approach is not expected to require the retrofitting of landfills used for the disposal of coal combustion residuals.

Note 11. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) consisted of the following:
(in millions)
Unrealized
Gains (Losses)on Cash
Flow Hedges
 
Unrecognized
Losses and Prior Service
Adjustments, Net1
 
Accumulated
Other
Comprehensive
Income (Loss)
Balance at December 31, 2009
$
105

 
$
(27
)
 
$
78

Change for 2010
(89
)
 
(20
)
 
(109
)
Balance at December 31, 2010
16

 
(47
)
 
(31
)
Change for 2011
(50
)
 
(13
)
 
(63
)
Balance at December 31, 2011
$
(34
)
 
$
(60
)
 
$
(94
)
1 
For further detail, see Note 8—Compensation and Benefit Plans.
Included in accumulated other comprehensive loss at December 31, 2011 was $21 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $55 million, net of tax, of unrealized losses related to interest rate hedges. 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 $22 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)
2011
 
2010
 
2009
Cash paid (received)
 
 
 
 
 
Interest (net of amount capitalized)1
$
290

 
$
239

 
$
301

Income taxes
(216
)
 
(96
)
 
(131
)
Cash payments under plant operating leases
311

 
325

 
336

Details of assets acquired
 
 

 

Fair value of assets acquired
$
1

 
$
1

 
$
14

Liabilities assumed
—

 
—

 
3

Net assets acquired
$
1

 
$
1

 
$
11

Non-cash activities from consolidation of VIEs
 
 

 

Assets
$
—

 
$
94

 
$
3

Liabilities
—

 
99

 
4

Non-cash activities from deconsolidation of variable interest entities
 
 

 

Assets
$
—

 
$
249

 
$
—

Liabilities
—

 
253

 
—

Non-cash activities from accrued capital expenditures
$
(46
)
 
$
32

 
$
(18
)
Non-cash activities from vendor financing
$
21

 
$
190

 
$
—


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1 
Interest capitalized for December 31, 2011, 2010 and 2009 was $27 million, $54 million and $19 million, respectively.
In connection with certain wind projects acquired during the past five years, the purchase price included payments that were due upon the completion of specific construction activities or the achievement of operational milestones. Accordingly, EME accrues for estimated payments when the obligation is probable. These incremental purchase price payments are capitalized.

Note 13. Asset Impairments and Other Charges
Asset impairments and other charges consisted of the following:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Homer City plant impairment
$
1,032

 
$
—

 
$
—

Midwest Generation Stations impairment
640

 
40

 
—

Wind projects impairment and other charges
64

 
—

 
—

Other
10

 
5

 
4

Asset impairments and other charges
$
1,746

 
$
45

 
$
4

Homer City Plant
Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process undertaken in the fourth quarter of 2011, and Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both. In connection with the preparation of its year end financial statements, EME concluded that these events combined with the current and projected financial condition of Homer City were indicators of impairment. The long-lived asset group subject to the impairment evaluation was determined to include the Homer City lease, leasehold improvements and prepaid rent. In assessing impairment, EME concluded that the future undiscounted cash flows through the period in which EME expects to continue to have significant economic interest and material control of the Homer City plant were insufficient to recover the carrying amount of the asset group. To measure the amount of impairment loss, the market and income approaches were considered the most appropriate and resulted in a zero fair value. EME viewed the lack of interest from market participants to provide sufficient funding for the capital improvements as indicative that the fair value of the asset group is zero. Furthermore, discounted cash flow analysis based on estimates of future energy, capacity and coal prices, operations and maintenance costs and operating lease payments along with the estimated costs of constructing the environmental control equipment also indicated a fair value of zero. Accordingly, EME recorded an impairment charge of $1,032 million for the fourth quarter of 2011. For additional information on the impairment of long-lived assets, see Note 1—Summary of Significant Accounting Policies—Impairment of Long-Lived Assets.
Included in the consolidated financial statements are the following assets and liabilities related to Homer City, excluding deferred taxes:

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(in millions)
At December 31, 2011
Cash
$
84

Restricted deposits
27

Inventory
105

Other assets
43

Total assets
259

Accounts payable and accrued liabilities
30

Pension and other postretirement benefits
49

Other liabilities
13

Total liabilities
92

Net assets
$
167

In addition, at December 31, 2011, EMMT had a $38 million intercompany accounts receivable from Homer City. In the event that EME no longer controls Homer City, EME will record a loss on disposition of assets and liabilities and classify Homer City as a discontinued operation. The loss on disposition will be determined based on the assets and liabilities at the date of disposition and an assessment whether any ongoing contingencies exist.
Midwest Generation Stations
A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. In connection with the preparation of its year end financial statements, EME concluded, based on the current energy price environment, it is less likely that Midwest Generation will install environmental controls required by the CPS at its Fisk, Crawford and Waukegan Stations; and such assessment was an indicator that these stations were impaired. The long-lived asset groups that were subject to the impairment evaluation were determined to include the property, plant and equipment of each station. Management updated the probability weighted future undiscounted cash flows expected to be received at these stations and concluded that such amounts did not recover the respective station's carrying amounts. As part of these alternative cash flow scenarios, management considered a shortened estimated useful life of each station if environmental improvements were not made and a forecasted reduction in generation from lower forward power prices. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014.
To measure the amount of the impairment loss, the income approach was considered the most relevant, but market data obtained prior to the significant decline in power prices was used to corroborate the income approach. The discounted cash flow analysis assumptions that have the most significant impact on fair value are forecasted energy and capacity prices. The discounted cash flow analysis indicated a fair value of zero. EME also concluded it was unlikely that a third party would consummate the purchase of the Fisk, Crawford or Waukegan Stations in the current economic and regulatory environment resulting in a determination that the fair value of each of these stations is zero. This resulted in an impairment charge of $115 million, $186 million and $339 million for Fisk, Crawford and Waukegan Stations, respectively. Environmental and other remediation or ongoing maintenance costs are expected to be offset by the salvage value of the asset groups. For additional information on the impairment of long-lived assets, see Note 1—Summary of Significant Accounting Policies—Impairment of Long-Lived Assets.
In the fourth quarter of 2010, Midwest Generation recorded a $40 million write-off of capitalized engineering and other costs related to a change in air emissions control technology selection at the Powerton Station.
Wind Projects
In connection with the preparation of its year end financial statements, management has reviewed the Storm Lake project and four small wind projects in Minnesota for impairment in the fourth quarter of 2011 based on an expected future increase in operating costs and declines in long-term power prices that the projects could potentially realize following the term of the power purchase agreements.The probability weighted future undiscounted cash flows of each project are not expected to be sufficient to recover the respective carrying value of each of these long-lived assets ($53 million in aggregate). The income approach was utilized to determine fair value for these asset groups. The most significant assumptions used in determining fair value were discount rates, future wind generation, the future availability of the project to generate energy and future plant operations expense. The asset groups at each project consisted of property, plant and equipment and, where appropriate,

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deferred revenue. In aggregate, the fair value of these five asset groups was determined to be $23 million, resulting in an impairment charge of $30 million. For additional information on the impairment of long-lived assets, see Note 1—Summary of Significant Accounting Policies—Impairment of Long-Lived Assets.
During the fourth quarter of 2011, EME significantly reduced development of renewable energy projects to conserve cash and in light of more limited market opportunities. As a result, EME reduced staffing and has undertaken efforts to reduce funding joint development projects, thereby reducing the development pipeline of potential wind projects to a projected installed capacity to approximately 1,300 megawatts. These changes triggered charges of $34 million.
Fair Value
The fair value of the long-lived assets and wind projects as determined using the discounted cash flow models discussed above qualified as Level 3 in the fair value hierarchy.

Note 14. Divestitures
Discontinued Operations
Summarized financial information for discontinued operations is as follows:
 
Years Ended December 31,
(in millions)
2011
 
2010
 
2009
Income (loss) before income taxes
$
1

 
$
13

 
$
(9
)
Provision (benefit) for income taxes
4

 
9

 
(2
)
Income (loss) from operations of discontinued foreign subsidiaries
$
(3
)
 
$
4

 
$
(7
)
The 2011 loss was primarily due to changes in foreign exchange rates and income taxes. The 2010 income was primarily attributable to the expiration of a contract indemnity and changes in foreign exchange rates. Tax indemnity payments of $4 million and $41 million were made in 2011 and 2010, respectively, related to EME's previous sale of an international project.
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 $60 million, $52 million and $55 million in 2011, 2010 and 2009, respectively. At both December 31, 2011 and 2010, the amount due to Edison International was $13 million.
EME participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. EME's insurance premiums are generally based on EME's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International.
Edison Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities and may also earn incentive compensation as set forth in the agreements. EME 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

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provide operation and maintenance services for the wind facilities. EME recorded revenues under the operation and maintenance agreements of $23 million for 2011, $23 million for 2010 and $26 million for 2009, reflected in operating revenues on EME's consolidated statements of operations. Receivables from affiliates for Edison Mission Operation & Maintenance totaled $3 million and $5 million at December 31, 2011 and 2010, 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 $277 million, $367 million and $366 million in 2011, 2010 and 2009, respectively. In addition, EME's Walnut Creek project was awarded by SCE, through a competitive bidding process, a 10-year power sales contract starting in 2013 for the output of its 479 MW gas-fired peaking facility. For further information on Walnut Creek related party transactions, see Note 5—Debt and Credit Agreements—Standby Letters of Credit.

Note 16. Quarterly Financial Data (unaudited)
(in millions)
First
 
Second
 
Third
 
Fourth
  
Total
2011
 
 
 
 
 
 
 
  
 
Operating revenues
$
550

 
$
536

 
$
595

 
$
499

  
$
2,180

Operating income (loss)
17

 
(54
)
 
55

 
(1,759
)
 
(1,741
)
Income (loss) from continuing operations
(18
)
 
(31
)
 
33

 
(1,060
)
 
(1,076
)
Income (loss) from operations of discontinued subsidiaries, net of tax
(2
)
 
(1
)
 
—

 
—

  
(3
)
Net income (loss)
(20
)
 
(32
)
 
33

 
(1,060
)
1 
(1,079
)
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
)
2 
163

1 
Reflects charges of $1,736 million pre-tax ($1,047 million, after tax) related to impairments. For more information, see Note 13—Asset Impairments and Other Charges.
2 
Reflects a $40 million pre-tax ($24 million, after tax) write-off of capitalized costs at the Powerton Station. For more information, see Note 13—Asset Impairments and Other Charges.


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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 ACCOUNTING FEES AND SERVICES
INDEPENDENT ACCOUNTANT FEES
The following table sets forth the aggregate fees billed to EME (consolidated total including EME and its subsidiaries), for the fiscal years ended December 31, 2011 and December 31, 2010, by PricewaterhouseCoopers LLP:
 
EME and Subsidiaries
(in thousands)
2011
 
2010
Audit fees
$
4,402

 
$
3,178

Audit related fees1
414

 
53

Tax fees2
382

 
343

All other fees
—

 
—

Total
$
5,198

 
$
3,574

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 meeting. The Committee has delegated such pre-approval responsibilities to the Committee Chair. All services performed by the independent accountants followed the above-referenced procedures and have been approved by the Edison International Audit Committee.


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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following documents have been filed as part of this report or, where noted, incorporated by reference:
(a)
(1) List of Financial Statements
See Index to Consolidated Financial Statements at Item 8 of this report.
(2)
List of Financial Statement Schedules
The following financial statement schedules are included in this report:

 
 
Page
 
 

All other schedules have been omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
(3)
List of Exhibits
The exhibit list below is incorporated herein by reference as the list of exhibits required as part of this report.
The agreements included or incorporated by reference as exhibits to this report contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of "materiality" that are different from "materiality" under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
EME acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this report not misleading.
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.

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Exhibit No.
Description
4.1
Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
4.1.1
First Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed May 10, 2007.
4.1.2
Second Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed May 10, 2007.
4.1.3
Third Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.3 to Edison Mission Energy's Form 8-K filed May 10, 2007.
4.1.4
Fourth Supplemental Indenture, dated as of August 22, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.4 to Edison Mission Energy's Form S-4 filed September 10, 2007.
4.2
Second Supplemental Indenture, dated as of April 30, 2007, between Edison Mission Energy and The Bank of New York, as trustee, supplementing the Indenture, dated as of June 28, 1999, pursuant to which Edison Mission Energy's 7.73% Senior Notes due 2009 were issued, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 1, 2007.
4.3
Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed June 8, 2006.
4.3.1
First Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed June 8, 2006.
4.3.2
Second Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed June 8, 2006.
4.4
Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.4.1
Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.4 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5
Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5.1
Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.5 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6
Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.12 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6.1
Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.6 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.7
Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

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Exhibit No.
Description
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.
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.

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Exhibit No.
Description
10.4.3
Third Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated June 29, 2007, among Midwest Generation, LLC and the Lenders referred to therein and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended June 30, 2007.
10.5
Security Agreement, dated as of June 15, 2006, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.2 to Edison Mission Energy's Form 8-K filed June 21, 2006.
10.6
Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.7
Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.16.4 to EME Homer City Generation L.P.'s Form 10-K for the year ended December 31, 2001.
10.8
Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
10.9
Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000.
10.10
Reimbursement Agreement, dated as of October 26, 2001, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.15 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.11*
Amended and Restated Tax Allocation Agreement, dated February 13, 2012, by and between Mission Energy Holding Company and Edison Mission Energy.
10.12*
Amended and Restated Administrative Agreement Re Tax Allocation Payments, dated February 13, 2012, among Edison International and subsidiary parties.
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, 2011, filed on February 29, 2012, formatted in XBRL: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Total Equity, (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
Senior Vice President and Chief Financial Officer
 
 
 
 
Date:
February 29, 2012

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
 
Director and President
(Principal Executive Officer)
 
February 29, 2012
 
 
 
 
 
 
 
 
 
 
/s/ Maria Rigatti
 
 
 
 
Maria Rigatti
 
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 
February 29, 2012
 
 
 
 
 
 
 
 
 
 
/s/ Aaron Moss
 
 
 
 
Aaron Moss
 
Vice President and Controller
(Controller or Principal Accounting Officer)
 
February 29, 2012
 
 
 
 
 
 
 
 
 
 
/s/ W. James Scilacci
 
 
 
 
W. James Scilacci
 
Director
 
February 29, 2012
 
 
 
 
 
 
 
 
 
 
/s/ Robert L. Adler
 
 
 
 
Robert L. Adler
 
Director
 
February 29, 2012


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SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
 

CONDENSED BALANCE SHEETS
(in millions)

 
December 31,
 
2011
 
2010
Assets
 
 
 
Cash and cash equivalents
$
738

 
$
427

Affiliate receivables
3

 
91

Other current assets
5

 
5

Total current assets
746

 
523

Investments in subsidiaries
6,408

 
7,792

Other long-term assets
199

 
316

Total Assets
$
7,353

 
$
8,631

Liabilities and Shareholder's Equity
 
 
 
Accounts payable and accrued liabilities
$
72

 
$
75

Affiliate payables
539

 
580

Total current liabilities
611

 
655

Long-term debt
3,700

 
3,700

Long-term affiliate debt
1,335

 
1,343

Deferred taxes and other
45

 
116

Total Liabilities
5,691

 
5,814

Total EME Common Shareholder's Equity
1,662

 
2,817

Total Liabilities and Shareholder's Equity
$
7,353

 
$
8,631




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 OPERATIONS
(in millions)

 
Years Ended December 31,
 
2011
 
2010
 
2009
Operating revenues
$
4

 
$
4

 
$
6

Operating expenses
(146
)
 
(114
)
 
(121
)
Operating loss
(142
)
 
(110
)
 
(115
)
Equity in income from continuing operations of subsidiaries
(788
)
 
463

 
488

Interest expense and other
(383
)
 
(355
)
 
(393
)
Loss before income taxes
(1,313
)
 
(2
)
 
(20
)
Benefit for income taxes
(235
)
 
(166
)
 
(217
)
Net income (loss) attributable to EME common shareholder
$
(1,078
)
 
$
164

 
$
197




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,
 
2011
 
2010
 
2009
Net cash provided by (used in) operating activities
$
(53
)
 
$
576

 
$
100

Net cash used in financing activities
(2
)
 
(245
)
 
(517
)
Net cash provided by (used in) investing activities
366

 
(84
)
 
(152
)
Net increase (decrease) in cash and cash equivalents
311

 
247

 
(569
)
Cash and cash equivalents at beginning of period
427

 
180

 
749

Cash and cash equivalents at end of period
$
738

 
$
427

 
$
180

Cash dividends received from subsidiaries
$
903

 
$
125

 
$
367




The accompanying notes are an integral part of these consolidated financial statements.
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The accompanying notes are an integral part of these consolidated financial statements.
124

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 senior notes, 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. Commitments 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, 2011
 
 
 
 
 
  
 
  
 
Uncollectible accounts
 
 
 
 
 
  
 
  
 
Customers
$
5

 
$
—

 
$
—

 
$
—

  
$
5

All others
—

 
—

 
—

  
—

 
—

Total
$
5

 
$
—

 
$
—

  
$
—

  
$
5

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

1 
Represents the consolidation of one coal project effective January 1, 2010. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities" of this report.
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.


126