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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PART IV
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
Commission File Number 333-68630
Edison Mission Energy
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) |
95-4031807 (I.R.S. Employer Identification No.) |
|
3 MacArthur Place, Suite 100 Santa Ana, California (Address of principal executive offices) |
92707 (Zip Code) |
Registrant's telephone number, including area code: (714) 513-8000
Securities registered pursuant to Section 12(b) of the Act:
None | Not Applicable | |
---|---|---|
(Title of Class) | (Name of each exchange on which registered) |
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share | ||||
(Title of Class) |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES o NO ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o NO ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "accelerated filer," "large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer ý | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO ý
Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 30, 2010: $0. Number of shares outstanding of the registrant's Common Stock as of February 28, 2011: 100 shares (all shares held by an affiliate of the registrant).
The registrant meets the conditions set forth in General Instruction I.(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K under the reduced disclosure format.
DOCUMENTS INCORPORATED BY REFERENCE
None
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This annual report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect Edison Mission Energy's (EME's) current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by EME that is incorporated in this annual report, or that refers to or incorporates this annual report, may also contain forward-looking statements. In this annual report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact EME or its subsidiaries, include but are not limited to:
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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 OperationsMarket 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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When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
AOI | adjusted operating income (loss) | |
ARO(s) | asset retirement obligation(s) | |
BACT | best available control technology | |
BART | best available retrofit technology | |
bcf | billion cubic feet | |
Big 4 | Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects | |
Btu | British thermal units | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
CAMR | Clean Air Mercury Rule | |
CARB | California Air Resources Board | |
CO2 | carbon dioxide | |
coal plants | Midwest Generation coal plants and Homer City electric generating station | |
Commonwealth Edison | Commonwealth Edison Company | |
CPS | Combined Pollutant Standard | |
CPUC | California Public Utilities Commission | |
EIA | Energy Information Administration | |
EME | Edison Mission Energy | |
EMMT | Edison Mission Marketing & Trading, Inc. | |
EWG(s) | exempt wholesale generator(s) | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FPA | Federal Power Act | |
GAAP | United States generally accepted accounting principles | |
GHG | greenhouse gas | |
GWh | gigawatt-hours | |
HAP(s) | hazardous air pollutant(s) | |
Homer City | EME Homer City Generation L.P. | |
Illinois EPA | Illinois Environmental Protection Agency | |
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ISO(s) | independent system operator(s) | |
Lehman Brothers | Lehman Brothers Commodity Services, Inc. (filed for bankruptcy on October 3, 2008) and Lehman Brothers Holdings, Inc. (filed for bankruptcy on September 15, 2008) | |
LIBOR | London Interbank Offered Rate | |
Midwest Generation | Midwest Generation, LLC | |
MMBtu | million British thermal units | |
Moody's | Moody's Investors Service, Inc. | |
MW | megawatts | |
MWh | megawatt-hours | |
NAAQS | National Ambient Air Quality Standard(s) | |
NAPP | Northern Appalachian | |
NERC | North American Electric Reliability Corporation | |
NOX | nitrogen oxide | |
NSR | New Source Review | |
NYISO | New York Independent System Operator | |
PADEP | Pennsylvania Department of Environmental Protection | |
PG&E | Pacific Gas & Electric Company | |
PJM | PJM Interconnection, LLC | |
PRB | Powder River Basin | |
PSD | Prevention of Significant Deterioration | |
RPM | Reliability Pricing Model | |
RTO(s) | regional transmission organization(s) | |
S&P | Standard & Poor's Ratings Services | |
SCE | Southern California Edison Company | |
SIP(s) | state implementation plan(s) | |
SNCR | selective non-catalytic reduction | |
SO2 | sulfur dioxide | |
Transport Rule | Clean Air Transport Rule | |
US EPA | United States Environmental Protection Agency | |
U.S. Treasury grants | Cash grants, under the American Recovery and Reinvestment Act of 2009 | |
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EME is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. Some of the facilities are operated on a merchant basis, with energy being sold into the marketplace, and others are operated under contracts calling for the delivery of energy to specific purchasers. EME also engages in hedging and energy trading activities in power markets through its EMMT subsidiary. EME was formed in 1986 and is an indirect subsidiary of Edison International. Edison International also owns SCE, one of the largest electric utilities in the United States.
EME's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power generation facilities and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. EME's operating projects primarily consist of coal-fired generating facilities, natural gas-fired generating facilities and renewable energy facilities, which include wind projects and one biomass project. As of December 31, 2010, EME's subsidiaries and affiliates owned or leased interests in 39 operating projects with an aggregate net physical capacity of 10,979 MW of which EME's pro rata share was 9,852 MW. At December 31, 2010, EME's subsidiaries and affiliates also owned four wind projects under construction totaling 480 MW of net generating capacity.
Location and Available Information
EME is incorporated under the laws of the State of Delaware. EME's headquarters and principal executive offices are located at 3 MacArthur Place, Suite 100, Santa Ana, California 92707, and EME's telephone number is (714) 513-8000. Unless indicated otherwise or the context otherwise requires, references to EME in this annual report are with respect to EME and its consolidated subsidiaries and the partnerships or limited liability entities through which EME and its partners own and manage their project investments.
EME's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports, are electronically filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and are available on the Securities and Exchange Commission's internet web site at http://www.sec.gov.
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.
EME's largest power plants are its coal power plants located in Illinois, which are collectively referred to as the Midwest Generation plants in this annual report, and the Homer City plant located in Pennsylvania. Collectively, EME refers to both the Midwest Generation plants and the Homer City plant as the coal plants. The coal plants sell power primarily into PJM, an RTO which includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. Sales may also be made from PJM into the Midwest Independent Transmission System Operator (MISO) RTO, which includes all or parts of Illinois, Wisconsin, Indiana, Michigan, Ohio, and other states in the region, and into the NYISO, which controls the transmission grid and energy and capacity markets for New York State.
PJM operates a wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators indicating the minimum prices at which a bidder is willing to dispatch energy at various incremental generation levels. PJM requires all load-serving entities and generators, such as Midwest Generation and Homer City, to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM's capacity markets have a single market-clearing price for each capacity zone. In May of every year, PJM conducts an annual capacity auction (RPM) to commit generation, energy efficiency and demand side resources three years forward, and to provide a long-term pricing signal for capacity resources.
EME is subject to competition from energy marketers, public utilities, government-owned power agencies, industrial companies, financial institutions, and other independent power producers. These companies may have competitive advantages as a result of scale, the location of their generation facilities or other factors. Some of EME's competitors have a lower cost of capital than most independent power producers and, in the case of utilities, are often able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments.
State and local environmental regulations, particularly those that impose stringent state specific emission limits, could put EME's coal plants at a disadvantage compared with competing power plants operating in nearby states and subject to less stringent state emission limits or to federal emission limits alone, and the CPS could put the Midwest Generation plants at a disadvantage compared with competing plants not subject to similar regulations. Potential future climate change regulations could also put EME's coal plants at a
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disadvantage compared to both power plants utilizing other fuels and utilities that may be able to recover climate change compliance costs through rate-base mechanisms. In addition, the ability of these plants to compete may be affected by governmental and regulatory activities designed to support the construction and operation of power generation facilities fueled by renewable energy sources.
EME operates in one line of business, independent power production, with all its continuing operations located in the United States, except the Doga project, which is located in the Republic of Turkey. Operating revenues are primarily derived from the sale of energy and capacity generated from the coal plants. EME is headquartered in Santa Ana, California, and its subsidiaries have offices located in Bolingbrook and Chicago, Illinois, and Boston, Massachusetts.
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As of December 31, 2010, EME's operations consisted of ownership or leasehold interests in the following operating projects:
Power Plants |
Location |
Primary Electric Purchaser2 |
Fuel Type |
Ownership Interest |
Net Physical Capacity (in MW) |
EME's Capacity Pro Rata Share (in MW) |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
MERCHANT POWER PLANTS |
||||||||||||||||||
Midwest Generation plants1 |
Illinois | PJM | coal | 100 | % | 5,172 | 5,172 | |||||||||||
Midwest Generation plants1 |
Illinois | PJM | oil | 100 | % | 305 | 305 | |||||||||||
Homer City plant1 |
Pennsylvania | PJM | coal | 100 | % | 1,884 | 1,884 | |||||||||||
Merchant Wind |
||||||||||||||||||
Goat Wind |
Texas | ERCOT | wind | 99.9% | 3 | 150 | 150 | |||||||||||
Lookout |
Pennsylvania | PJM | wind | 100 | % | 38 | 38 | |||||||||||
|
||||||||||||||||||
Natural Gas |
||||||||||||||||||
Big 4 Projects |
||||||||||||||||||
Kern River1 |
California | SCE | natural gas | 50 | % | 300 | 150 | |||||||||||
Midway-Sunset1 |
California | PG&E | natural gas | 50 | % | 225 | 113 | |||||||||||
Sycamore1 |
California | SCE | natural gas | 50 | % | 300 | 150 | |||||||||||
Watson |
California | SCE | natural gas | 49 | % | 385 | 189 | |||||||||||
Westside Projects1 |
||||||||||||||||||
Coalinga |
California | PG&E | natural gas | 50 | % | 38 | 19 | |||||||||||
Mid-Set |
California | PG&E | natural gas | 50 | % | 38 | 19 | |||||||||||
Salinas River |
California | PG&E | natural gas | 50 | % | 38 | 19 | |||||||||||
Sargent Canyon |
California | PG&E | natural gas | 50 | % | 38 | 19 | |||||||||||
Sunrise1 |
California | CDWR | natural gas | 50 | % | 572 | 286 | |||||||||||
Renewable Energy |
||||||||||||||||||
Buffalo Bear |
Oklahoma | WFEC | wind | 100 | % | 19 | 19 | |||||||||||
Cedro Hill |
Texas | CSA | wind | 100 | % | 150 | 150 | |||||||||||
Crosswinds |
Iowa | CBPC | wind | 99% | 3 | 21 | 21 | |||||||||||
Elkhorn Ridge |
Nebraska | NPPD | wind | 67 | % | 80 | 53 | |||||||||||
Forward |
Pennsylvania | CECG | wind | 100 | % | 29 | 29 | |||||||||||
Hardin |
Iowa | IPLC | wind | 99% | 3 | 15 | 15 | |||||||||||
High Lonesome |
New Mexico | APSC | wind | 100 | % | 100 | 100 | |||||||||||
Jeffers |
Minnesota | NSPC | wind | 99.9% | 3 | 50 | 50 | |||||||||||
Minnesota Wind projects4 |
Minnesota | NSPC/IPLC | wind | 75-99% | 3 | 83 | 75 | |||||||||||
Mountain Wind I |
Wyoming | PC | wind | 100 | % | 61 | 61 | |||||||||||
Mountain Wind II |
Wyoming | PC | wind | 100 | % | 80 | 80 | |||||||||||
Odin |
Minnesota | MRES | wind | 99.9% | 3 | 20 | 20 | |||||||||||
San Juan Mesa |
New Mexico | SPS | wind | 75 | % | 120 | 90 | |||||||||||
Sleeping Bear |
Oklahoma | PSCO | wind | 100 | % | 95 | 95 | |||||||||||
Spanish Fork |
Utah | PC | wind | 100 | % | 19 | 19 | |||||||||||
Storm Lake1 |
Iowa | MEC | wind | 100 | % | 108 | 108 | |||||||||||
Wildorado |
Texas | SPS | wind | 99.9% | 3 | 161 | 161 | |||||||||||
Huntington Waste-to- |
New York | LIPA | biomass | 38 | % | 25 | 9 | |||||||||||
Coal |
||||||||||||||||||
American Bituminous1 |
West Virginia | MPC | waste coal | 50 | % | 80 | 40 |
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Power Plants |
Location |
Primary Electric Purchaser2 |
Fuel Type |
Ownership Interest |
Net Physical Capacity (in MW) |
EME's Capacity Pro Rata Share (in MW) |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
CONTRACTED POWER PLANTS International |
|||||||||||||||||
Doga1 |
Republic of Turkey | TEDAS | natural gas | 80 | % | 180 | 144 | ||||||||||
Total |
10,979 | 9,852 | |||||||||||||||
APSC | Arizona Public Service Company | NPPD | Nebraska Public Power District | ||||
CBPC | Corn Belt Power Cooperative | NSPC | Northern States Power Company | ||||
CDWR | California Department of Water Resources | PC | PacifiCorp | ||||
CECG | Constellation Energy Commodities Group, Inc. | PG&E | Pacific Gas & Electric Company | ||||
CSA | City of San Antonio | PJM | PJM Interconnection, LLC | ||||
ERCOT | Electric Reliability Council of Texas | PSCO | Public Service Company of Oklahoma | ||||
IPLC | Interstate Power and Light Company | PSE | Puget Sound Energy, Inc. | ||||
LIPA | Long Island Power Authority | SCE | Southern California Edison Company | ||||
MEC | Mid-American Energy Company | SPS | Southwestern Public Service | ||||
MPC | Monongahela Power Company | TEDAS | Türkiye Elektrik Dagitim Anonim Sirketi | ||||
MRES | Missouri River Energy Services | WFEC | Western Farmers Electric Cooperative |
At December 31, 2010, the fuel sources for these projects were as follows:
Fuel Source |
Percentage of EME's Generation Capacity |
|||
---|---|---|---|---|
Coal |
72 | % | ||
Natural gas |
14 | % | ||
Renewable energy |
14 | % | ||
A description of EME's larger power plants and major investments in energy projects is set forth below. In addition to the facilities and power plants that EME owns, EME uses the term "its" in regard to facilities and power plants that EME or an EME subsidiary operates under sale-leaseback arrangements.
Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "Market Risk ExposuresCommodity Price RiskEnergy Price Risk Affecting Sales from the Coal Plants."
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EME's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.
The Midwest Generation plants consist of the following:
Operating Plant or Site |
Location |
Leased/ Owned |
Fuel |
Megawatts |
|||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Electric Generating Facilities |
|||||||||||
Crawford Station |
Chicago, Illinois | owned | coal | 532 | |||||||
Fisk Station |
Chicago, Illinois | owned | coal | 326 | |||||||
Joliet Unit 6 |
Joliet, Illinois | owned | coal | 290 | |||||||
Joliet Units 7 and 8 |
Joliet, Illinois | leased | coal | 1,036 | |||||||
Powerton Station |
Pekin, Illinois | leased | coal | 1,538 | |||||||
Waukegan Station |
Waukegan, Illinois | owned | coal | 689 | 1 | ||||||
Will County Station |
Romeoville, Illinois | owned | coal | 761 | 2 | ||||||
Peaking Units |
|||||||||||
Fisk |
Chicago, Illinois | owned | oil | 197 | |||||||
Waukegan |
Waukegan, Illinois | owned | oil | 108 | |||||||
Total |
5,477 | ||||||||||
Non-Operating Plant or Site |
Location |
|
---|---|---|
Collins Station3 | Grundy County, Illinois | |
Crawford peaker4 | Chicago, Illinois | |
Joliet peaker5 | Joliet, Illinois | |
Calumet peaker5 | Chicago, Illinois | |
Electric Junction peaker5 | Aurora, Illinois | |
Lombard peaker5 | Lombard, Illinois | |
Sabrooke peaker5 | Rockford, Illinois | |
Energy and capacity from the Midwest Generation plants are sold under terms, including price, duration and quantity, arranged by EMMT, an EME subsidiary engaged in power
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marketing and trading activities, with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Thus, EME is subject to market risks related to the price of energy and capacity from the Midwest Generation plants. Power generated at the Midwest Generation plants is primarily sold into the PJM market.
The Midwest Generation plants purchase coal from several suppliers located in the Southern PRB of Wyoming. The total volume of coal consumed annually is largely dependent on the amount of generation and ranges between 17.5 million to 19.5 million tons. Coal is transported under long-term transportation agreements with Union Pacific Railroad and various short-haul carriers. Midwest Generation's long-term rail transportation contract with Union Pacific Railroad expires at the end of 2011. For additional information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk ExposuresCommodity Price RiskCoal and Transportation Price Risk." As of December 31, 2010, Midwest Generation leased approximately 3,900 railcars to transport the coal from the mines to the generating stations, and the leases have remaining terms that range from less than one year to nine years, with options to extend the leases or purchase some railcars at the end of the lease terms.
Coal for the Fisk and Crawford Stations is typically shipped by rail to the Will County Station where it is transferred from the railcars, blended as necessary to meet station specifications, and loaded into river barges. These barges are towed to the stations by an independent contractor under a transportation agreement with Midwest Generation. Occasionally, third-party transloading facilities are utilized.
Midwest Generation has approximately 305 MW of peaking capacity in the form of simple cycle combustion turbines at the Fisk and Waukegan Stations. These units are fueled with distillate fuel oils.
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.
Energy and capacity from the Homer City plant are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Thus, EME is subject to market risks related to the price of energy and capacity from the Homer City plant. The Homer City plant is situated in the PJM control area and has direct, high voltage interconnections to PJM and also to the NYISO. Electric power generated at the Homer City plant is primarily sold into the PJM market.
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Homer City's Units 1 and 2 collectively consume approximately 3.3 million to 3.5 million tons of mid-range sulfur coal per year. Two types of coal are purchased, readyto-burn and raw coal. Readyto-burn coal is of the quality that can be burned directly in Units 1 and 2, whereas the raw coal purchased for consumption by Units 1 and 2 must be cleaned in the Homer City coal cleaning facility, which has the capacity to clean up to 5 million tons of coal per year. Unit 3 consumes approximately 2 million tons of coal per year and can consume either raw or ready-to-burn coal. A wet scrubber flue gas desulfurization system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control. In general, the coal purchased for all three units is acquired locally. Homer City purchases the majority of its coal under term contracts with the balance purchased in the spot market as needed. For additional information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk ExposuresCommodity Price RiskCoal and Transportation Price Risk."
Emission Allowances for the Coal Plants
The federal Acid Rain Program requires electric generating stations to hold SO2 allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, the coal plants are required to hold seasonal and annual NOx allowances. As part of the acquisition of the coal plants, EME obtained emission allowance rights that have been or are allocated to these facilities. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. Future regulations, including the Transport Rule, may impact future emission allowance allocations and may require EME to purchase additional allowances in amounts that could be significant.
EME owns two merchant wind projects as follows:
Merchant Wind Project |
Location |
Primary Electric Purchaser |
Commercial Operations Date |
Ownership Interest |
Net Physical Capacity (in MW) |
EME's Capacity Pro Rata Share (in MW) |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Goat Wind |
Texas | ERCOT1 | April 2008/June 2009 | 99.9% | 3 | 150 | 150 | |||||||||
Lookout |
Pennsylvania | PJM2 | October 2008 | 100 | % | 38 | 38 | |||||||||
Total |
188 | 188 | ||||||||||||||
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Contracted Power PlantsDomestic
EME owns partnership investments in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, as described in the table below. Because these projects have similar economic characteristics, EME views these projects collectively and refers to them as the Big 4 projects. On December 16, 2010, the CPUC approved a comprehensive settlement of various issues related to power sales from cogeneration facilities (including the Big 4 projects) that implements a mechanism to foster new power purchase agreements for such facilities, and provides transition power purchase agreements during implementation. The settlement will become effective if FERC approves a related filing.
Project |
Location |
Plant Description |
Primary Electric Purchaser |
Ownership Interest |
Net Physical Capacity (in MW) |
EME's Capacity Pro Rata Share (in MW) |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Kern River |
Bakersfield, CA | Natural gas-fired cogeneration |
Southern California Edison |
50 | % | 300 | 150 | |||||||||
Midway-Sunset |
Taft, CA | Natural gas-fired cogeneration |
Pacific Gas & Electric Company |
50 | % | 225 | 113 | |||||||||
Sycamore |
Bakersfield, CA | Natural gas-fired cogeneration |
Southern California Edison |
50 | % | 300 | 150 | |||||||||
Watson |
Carson, CA | Natural gas-fired cogeneration |
Southern California Edison |
49 | % | 385 | 189 | |||||||||
Kern River Cogeneration sells electricity to SCE under an agreement that expires in 2011. Kern River Cogeneration also sells steam to Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc., under an agreement with a term equivalent to the power purchase agreement. EME expects that these arrangements will be replaced by new power and steam purchase agreements, but cannot predict whether or when this will occur. The Kern River project may also operate as a merchant generator selling into the California ISO market.
Midway-Sunset 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 Cogeneration sells electricity to SCE under an extension of its prior power purchase agreement, with revised pricing. EME expects that this arrangement will eventually be replaced by a new power purchase agreement pursuant to the settlement referred to above,
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but cannot predict whether or when this will occur. Sycamore Cogeneration sells steam to Chevron North America Exploration and Production Company under an agreement that expires in 2013.
Watson Cogeneration sells electricity to SCE under an extension of its prior power purchase agreement, with revised pricing. EME expects that this arrangement will eventually be replaced by a new power purchase agreement, but cannot predict whether or when this will occur. Watson Cogeneration currently sells power and steam to BP West Coast Products LLC under agreements that expire in 2013 or upon the termination of the power purchase agreement executed between Watson and SCE, whichever is earlier.
EME owns 50% partnership interests in each of Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, and Sargent Canyon Cogeneration Company, each of which owns a 38 MW natural gas-fired cogeneration facility located in California. Due to similar economic characteristics, EME views these projects collectively and refers to them as the Westside projects. Currently, these projects sell electricity to PG&E under agreements that provide for sales at "as available" rates. On October 6, 2010, each of the Westside projects entered into power purchase agreements with PG&E that expire in 2016. The new power purchase agreements will become effective after CPUC approval, which is pending.
EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired facility in Kern County, California, which EME refers to as the Sunrise project. Sunrise Power sells electricity under a long-term power purchase agreement with the California Department of Water Resources that expires in 2012.
EME owns interests in the following operating wind projects which sell electricity pursuant to long-term power purchase agreements with third parties with original terms ranging from 10 to 30 years. The table below provides, for each contracted wind project, the project's power purchase agreement expiration, either the expiration of the project's production tax credits or
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an indication that EME elected to receive a U.S. Treasury grant, and the project's commercial operation or acquisition date.
Contracted Wind Plants |
Power Purchase Agreement Expiration Year |
Production Tax Credit Expiration Date |
Commercial Operation or Acquisition Date |
|||||
---|---|---|---|---|---|---|---|---|
Buffalo Bear |
2033 | December 2018 | December 2008 | |||||
Cedro Hill |
2030 | Qualified for U.S. Treasury grant | November 2010 | |||||
Crosswinds1 |
20224 | June 2017 | June 2007 | |||||
Elkhorn Ridge |
2029 | December 2018 | March 2009 | |||||
Forward |
2017 | April 2018 | April 2008 | |||||
Hardin2 |
2027 | May 2017 | May 2007 | |||||
High Lonesome |
2039 | Qualified for U.S. Treasury grant | July 2009 | |||||
Jeffers |
2028 | October 2018 | October 2008 | |||||
Minnesota3 |
2021-20345 | June 2009-July 2016 | April 2006 | |||||
Mountain Wind I |
2033 | July 2018 | July 2008 | |||||
Mountain Wind II |
2033 | September 2018 | September 2008 | |||||
Odin |
2028 | June 2018 | May 2008 | |||||
San Juan Mesa |
2025 | December 2015 | December 2005 | |||||
Sleeping Bear |
2032 | October 2017 | September 2007 | |||||
Spanish Fork |
2028 | July 2018 | July 2008 | |||||
Storm Lake |
2019 | June 2009 | May 1999 | |||||
Wildorado |
2027 | April 2017 | April 2007 | |||||
Huntington Waste-to-Energy Project
EME owns a 38% limited partnership interest in Covanta Huntington LP, which owns a 25 MW waste-to-energy facility located near the Town of Huntington, New York, which EME refers to as the Huntington project. The project processes waste materials under a solid waste disposal services agreement with the Town of Huntington, which is set to expire in 2012 with an option to renew. In 2010, the Town of Huntington exercised its renewal option to extend the disposal services agreement to 2019. The Huntington project also sells electricity to Long Island Power Authority under a power purchase agreement that expires in 2012.
EME owns a 50% interest in American Bituminous Power Partners, L.P., which owns an 80 MW waste coal facility located in Grant Town, West Virginia, which EME refers to as the
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Ambit project. Ambit sells electricity to Monongahela Power Company under a power purchase agreement that expires in 2035.
Contracted Power PlantsInternational
EME owns an 80% interest in Doga Enerji, which owns a 180 MW natural gas-fired cogeneration plant near Istanbul in the Republic of Turkey, which EME refers to as the Doga project. Doga Enerji sells electricity to Türkiye Elektrik Dagitim Anonim Sirketi, commonly known as TEDAS, under a power purchase agreement that expires in 2019.
Renewable Development Activities
At December 31, 2010, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW and had four projects totaling 480 MW under construction. Projects under construction at December 31, 2010 were as follows:
Wind Project |
Location |
Primary Electric Purchaser |
Ownership Interest |
EME's Capacity Pro Rata Share (in MW) |
|||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Big Sky |
Illinois | Merchant1 |
100 | % | 240 | ||||||
Taloga |
Oklahoma | Oklahoma Gas and Electric Company2 |
100 | % | 130 | ||||||
Laredo Ridge |
Nebraska | Nebraska Public Power District2 |
100 | % | 80 | ||||||
CWN |
Minnesota | Northern States Power Company2 |
99 | % | 30 | ||||||
Total |
480 | ||||||||||
Laredo Ridge and Big Sky achieved commercial operation on February 1, 2011 and February 18, 2011, respectively. EME anticipates that the remaining projects under construction will also achieve commercial operation in 2011. In addition to the projects under construction at December 31, 2010, EME expects the 55 MW Pinnacle project in West Virginia will commence construction in 2011 with anticipated commercial operation in 2011. For more information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview."
Asset Management and Trading Activities
EME's power marketing and trading subsidiary, EMMT, manages the energy and capacity of EME's merchant generating plants and, in addition, trades electric power, gas, oil and related commodity and financial products, including forwards, futures, options and swaps. EMMT segregates its activities into two categories:
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reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. The objective of these activities is to sell the output of the facilities on a forward basis or to hedge the risk of future changes in prices. Hedging activities include on-peak and off-peak periods and may include load service requirements contracts with local utilities. Transactions related to hedging activities are designated separately from EMMT's trading activities. Not all contracts entered into by EMMT for hedging purposes qualify as hedges for accounting purposes.
For a discussion of EME's significant customers, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 6. Derivative Instruments and Hedging ActivitiesCredit Risk."
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.
For a discussion of discontinued operations, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 14. Divestitures."
EME's operations are subject to extensive regulation. EME's operating projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with project development, ownership and operation, and the use of electric energy, capacity and related products, including ancillary services, from the projects. In addition, EME is subject to the market rules, procedures, and protocols of the markets in which it participates.
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The FERC has exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce (other than transmission that is "bundled" with retail sales), including ongoing, as well as initial, rate jurisdiction. Rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be workably competitive, may be market based. Previously approved rates may also be revoked or modified by the FERC after notice and opportunity for hearing.
The FERC also has jurisdiction over the sale or transfer of specified assets, including wholesale power sales contracts and generation facilities and, in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. Dispositions of EME's jurisdictional assets and certain types of financing arrangements may require FERC approval.
Each of EME's domestic generating facilities is either a qualifying facility, as determined by the FERC, or the subsidiary owning the facility is an EWG. Most qualifying facilities are exempt from the ratemaking and several other provisions of the FPA. EME's EWGs are subject to the FERC's ratemaking jurisdiction under the FPA, but have been authorized to sell power at market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, EME's power marketing subsidiaries, including EMMT, have been authorized by the FERC to make wholesale market sales of power at market-based rates and are subject to the FERC ratemaking regulation under the FPA.
If one of the projects in which EME has an interest were to lose its qualifying facility or EWG status, the project would no longer be entitled to the related exemptions from regulation and could become subject to rate regulation by the FERC and state authorities. Loss of status could also trigger defaults under covenants contained in the project's power sales agreements and financing agreements.
NERC establishes and enforces reliability standards for the bulk power system. EME believes it has taken appropriate steps to be compliant with current NERC reliability standards that apply to its operations.
Transmission of Wholesale Power
Generally, projects that sell power to wholesale purchasers other than the local utility to which the project may be interconnected require the transmission of electricity over power lines owned by others. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is subject to FERC jurisdiction.
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The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides the Commodity Futures Trading Commission and the Securities and Exchange Commission with jurisdiction to regulate financial derivative products, including swaps, options and other derivative products, collectively referred to in this annual report as "swaps." These agencies are required to issue rules and regulations that implement regulation of swaps markets by July 2011.
The Dodd-Frank Act subjects swaps to new mandatory clearing and trading requirements, if no exemption applies. It may also impose capital requirements on non-exempt market participants. The clearing and trading requirements could result in increased margining requirements which may increase the costs of hedging activity. EME and its subsidiaries, particularly EMMT, use swaps to hedge commercial risks associated with the generation, purchase and sale of electricity and fuel to wholesale customers. In addition, EMMT utilizes swaps as part of its proprietary trading business.
If new clearing, trading or other requirements are applicable to EME under the Dodd-Frank Act rules and regulations, the potential impact will depend on the content of those rules and regulations, which remains uncertain.
Environmental Matters and Regulations
Because EME does not own or operate any assets, other than the stock of its subsidiaries, it does not have any direct environmental obligations or liabilities. However, legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the environment impose numerous restrictions and requirements with respect to the operation of EME's existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by EME's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations. In addition, as discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and Contingencies," the US EPA and others have from time to time sought to involve EME in litigation related to facilities owned by EME's subsidiaries. The facilities of EME's subsidiaries which are most affected by environmental regulation are located in Illinois and Pennsylvania. EME continues to monitor legislative and regulatory developments and to evaluate possible strategies for compliance with environmental regulations. Additional information about environmental matters affecting EME, including projected environmental capital expenditures, is included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesCapital Investment Plan" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCritical Accounting Estimates and PoliciesImpairment of Long-Lived AssetsApplication to Merchant Coal-Fired Power Plants."
There have been a number of federal and state legislative and regulatory initiatives to reduce GHG emissions. Any climate change regulation or other legal obligation that would require substantial reductions in emissions of GHGs or that would impose additional costs or charges
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for the emission of GHGs could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, which could adversely affect EME.
Federal Legislative/Regulatory Developments
Efforts to pass comprehensive federal climate change legislation have not yet been successful. The timing, contents, and potential effects on EME of federal legislation imposing limits on GHG emissions remain uncertain. However, the US EPA has begun to issue federal GHG regulations that are likely to impact EME's operations.
In June 2010, the US EPA issued the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG emissions and newly modified existing major sources to the PSD air permitting program beginning in January 2011 (and later, to the Title V permitting program under the CAA); however, the GHG tailoring rule significantly increases the emissions thresholds that apply before facilities are subjected to these programs. The emissions thresholds for CO2 equivalents in the final rule vary from 75,000 tons per year to 100,000 tons per year depending on the date and whether the sources are new or modified.
A challenge to the GHG tailoring rule (along with other GHG regulations and determinations issued by the US EPA) is pending before the U.S. Court of Appeals for the D.C. Circuit. Regulation of GHG emissions pursuant to the PSD program could affect efforts to modify EME's facilities in the future, and could subject new capital projects to additional permitting and pollution control requirements that could delay such projects. If EME is required to install controls in the future or otherwise modify its operations in order to reduce GHG emissions, the potential impact of the GHG tailoring rule will depend on the nature and timing of the controls or modifications, which remain uncertain.
In December 2010, the US EPA announced that it had entered into a settlement with various states and environmental groups to resolve a long-standing dispute over regulation of GHGs from electrical generating units pursuant to the New Source Performance Standards in the CAA. Under the pending settlement, the US EPA will propose performance standards for GHG emissions from new and modified power plants and emissions guidelines for existing power plants in July 2011, and will finalize such regulations by May 2012, with compliance dates for existing power plants expected to be in 2015 or 2016. The specific requirements will not be known until the regulations are finalized.
Since January 2010, the US EPA's Final Mandatory Greenhouse Gas Reporting Rule has required all sources within specified categories, including electric generation facilities, to monitor emissions and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011. EME's 2010 GHG emissions were approximately 50.2 million metric tons.
Regional Initiatives and State Legislation
Regional initiatives and state legislation may also require reductions of GHG emissions, and it is not yet clear whether or to what extent any federal legislation would preempt them. If state
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and/or regional initiatives remain in effect after federal legislation is enacted, generators could be required to satisfy them in addition to federal standards.
EME's operations in California are subject to two laws governing GHG emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce GHG emissions. AB 32 requires the CARB to develop regulations, effective in 2012, that would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In December 2010, the CARB finalized regulations establishing a California cap-and-trade program, which include revisions to the CARB's mandatory GHG emissions reporting regulation. The regulations and the cap-and-trade program itself are being challenged by various citizens' groups under the California Environmental Quality Act.
The second law, SB 1368, required the CPUC and the California Energy Commission to adopt GHG emissions performance standards restricting the ability of California investor-owned and publicly owned utilities, respectively, to enter into long-term arrangements for the purchase of electricity. The standards that have been adopted prohibit these entities from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh (the performance of a combined-cycle gas turbine generator). Utility purchases of power generated by EME's California facilities are subject to the emissions performance standards established in SB 1368. EME believes that all of its California facilities meet the SB 1368 standards, but EME will continue to monitor the regulations, as they are developed, for potential impact on its existing facilities and its projects under development.
EME's operations in California may be also affected by the Western Climate Initiative, an agreement entered into by California, other western states and certain Canadian provinces, to develop strategies to reduce GHG emissions in the region to 15% below 2005 levels by 2020. In July 2010, the Initiative partners released a comprehensive strategy for a regional cap-and-trade program, with a planned start date of January 2012, to help achieve their reduction goal. Recent political developments make it uncertain whether this regional program will proceed and what form it might take. As noted above, California is implementing its own program to reduce GHG emissions.
EME's operations in Illinois may be affected by the Midwestern Greenhouse Gas Reduction Accord, by which six Midwestern states, including Illinois, and the Canadian province of Manitoba agreed to develop regional GHG emission reduction goals using a multi-sector cap-and-trade program. In May 2010, the Midwestern Greenhouse Gas Reduction Accord Advisory Group finalized recommendations and a model rule for emissions reduction targets and the design of a regional cap-and-trade program to serve as a basis for individual state legislative or regulatory action. However, there is substantial uncertainty as to whether the parties to the Midwestern Greenhouse Gas Reduction Accord intend to continue their efforts to develop or implement such a program, especially in light of the failure to pass a federal cap-and-trade program in the 111th Congress.
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Litigation alleging that GHG is a public and private nuisance may affect EME and its subsidiaries whether or not they are named as defendants. The law is unsettled on whether or not this litigation presents questions capable of judicial resolution or political questions that should be resolved by the legislative or executive branches.
In December 2010, the Supreme Court agreed to review a case in which an appellate panel had endorsed the availability of judicial remedies for nuisance allegedly caused by GHG emissions associated with climate change. Oral argument before the Supreme Court is scheduled for April 2011. Currently pending while the Supreme Court considers the matter before it is an appeal before the Ninth Circuit of a federal district order dismissing a case against EME's parent company, Edison International, and other defendants brought by the Alaskan Native Village of Kivalina in which the plaintiffs seek damages of up to $400 million for the cost of relocating the village, which the plaintiffs claim is no longer protected from storms because the Arctic sea ice has melted as the result of climate change. Edison International and the other defendants in the lawsuit recently requested the Ninth Circuit to defer oral argument on the appeal pending the Supreme Court's decision on related issues.
EME cannot predict whether the legal principles emerging from the U.S. Supreme Court or any of the cases in the appellate courts will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims.
The CAA, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of the coal plants. The CAA requires the US EPA to establish concentration levels in the ambient air for six criteria pollutants to protect public health and welfare. These concentration levels are known as National Ambient Air Quality Standards, or NAAQS. The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2.
Federal environmental regulations require states to adopt state implementation plans, known as SIPs, for certain pollutants, which detail how the state will attain the standards that are mandated by the relevant law or regulation. The SIPs must be equal to or more stringent than the federal requirements and must be submitted to the US EPA for approval. Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and to maintain good air quality in attainment areas. If the attainment status of areas changes, states may be required to develop new SIPs that address the changes. Many of EME's facilities are located in areas that have not attained NAAQS for ozone (affected by NOx emissions from power plants) and fine particulate matter (affected by SO2 and NOx emissions from power plants).
As described further below, on December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA, which was subsequently embodied in an Illinois rule called Combined Pollutant Standard or CPS, to reduce mercury, NOx and SO2 emissions at the
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Midwest Generation plants. The CPS requires Midwest Generation to achieve air emission reductions for NOx and SO2, and those reductions should contribute to or effect compliance with various existing US EPA ambient air quality standards. It is possible that if lower ozone, particulate matter, NOx or SO2 NAAQS are finalized by US EPA in the future, Illinois may implement regulations that are more stringent than those required by the CPS.
Nitrogen Oxide and Sulfur Dioxide
Clean Air Interstate and Transport Rules
The CAIR, issued by the US EPA on March 10, 2005, mandated significant reductions in NOx and SO2 emission allowance caps under the CAA in 28 eastern states and the District of Columbia. In 2008, the U.S. Court of Appeals for the D.C. Circuit initially vacated the CAIR, but later remanded the CAIR to the US EPA for the issuance of a revised rule. The CAIR remains in effect until the US EPA finalizes a revised regulation.
In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to reduce power plant emissions of NOx and SO2 substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the CAIR.
The US EPA has proposed allocating emission allowances based on historic and projected emissions data from power plants, along with three possible approaches to emission allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading of allowances would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state, an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units. In January 2011, the US EPA proposed two other possible approaches to emission allowance allocation. Both approaches would allocate allowances among units within each state based on each unit's proportional share of the state's total historic heat input, and the second approach would add a constraint based on a unit's reasonably foreseeable maximum emissions under the proposed Transport Rule trading programs.
The Transport Rule is scheduled to be finalized in 2011. The CAIR will remain in place until that time. Depending on the approach adopted, the Transport Rule may provide allowance allocations for the Midwest Generation plants which are adequate for the plants' needs or may require the Midwest Generation plants to procure additional allowances, based on projected emissions using the Illinois CPS allowable emission rates. The Transport Rule may require the installation of additional environmental equipment on Units 1 and 2 at the Homer City plant to reduce SO2 emissions and, depending on the approach adopted, may also require Homer City to procure a significant number of additional allowances pending such installation or curtail operations if it is unable to do so on acceptable terms. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and
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Results of OperationsManagement's OverviewEnvironmental DevelopmentsHomer City Environmental Issues and Capital Resource Limitations."
In June 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is being taken into account in EME's environmental compliance strategy. Revisions to SIPs to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014, with a compliance deadline of August 2017.
On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NOx and SO2 emissions at the Midwest Generation plants. The agreement has been embodied in the CPS. All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. The principal emission standards and control technology requirements for NOx and SO2 under the CPS are as described below:
NOx EmissionsBeginning in calendar year 2012 and continuing in each calendar year thereafter, Midwest Generation must comply with an annual and seasonal NOx emission rate of no more than 0.11 lbs/million Btu. In addition to these standards, Midwest Generation must install and operate SNCR equipment on Units 7 and 8 at the Crawford Station by December 31, 2015.
SO2 EmissionsMidwest Generation must comply with an overall SO2 annual emission rate beginning with 0.44 lbs/million Btu in 2013 and decreasing annually until it reaches 0.11 lbs/million Btu in 2019 and thereafter.
The CPS also specifies the control technologies that are to be installed on some units by specified dates. In these cases, Midwest Generation must either install the required technology by the specified deadline or shut down the unit. The CPS also required Midwest Generation to shut down Unit 6 at the Waukegan Station by December 31, 2007, and Units 1 and 2 at the Will County Station by December 31, 2010, which it has done.
During 2009, Midwest Generation conducted tests of NOx removal technology based on SNCR that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NOx portion of the CPS. Capital expenditures for installation of SNCR equipment are expected to be approximately $109 million in 2011.
Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO2 emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time than the use of spray dryer absorber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs. For additional discussion, see "Item 7. Management's
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Discussion and Analysis of Financial Condition and Results of OperationsManagement's OverviewEnvironmental DevelopmentsMidwest Generation Compliance Plans and Costs."
The Homer City plant was subject to the federal CAIR during 2010 and complied with both the NOx and SO2 requirements by using existing equipment and purchasing SO2 allowances. Pennsylvania adopted a state version of the CAIR, which the US EPA approved in December 2009. Homer City expects to comply with the Pennsylvania CAIR, which is substantially similar to the federal CAIR, in the same manner in which it complies with the federal CAIR.
Mercury/Hazardous Air Pollutants
Clean Air Mercury Rule/Hazardous Air Pollutant Regulations
The CAMR was established by the US EPA as an attempt to reduce mercury emissions from existing coal-fired power plants using a cap-and-trade program. In February 2007, the U.S. Court of Appeals for the D.C. Circuit vacated both the CAMR and the related US EPA decision to remove oil- and coal-fired power plants from the list of sources to be regulated under the provisions of the CAA governing emissions of HAPs.
In accordance with a consent decree entered in April 2010, the US EPA committed to proposing regulations by March 16, 2011 limiting emissions of HAPs from coal- and oil-fired electrical generating units that are major sources of HAPs, and to finalizing such regulations by November 2011. The emissions standards must be designed to achieve the maximum degree of emission reduction that the US EPA determines is achievable for the affected units, taking into account costs and non-air quality environmental and health benefits (also referred to as maximum achievable control technology, or MACT standard). Unlike the CAMR, the US EPA must regulate all of the HAPs emitted by these generating units. Compliance with the MACT standards will be required three years after the effective date of the final regulations. Until the US EPA's regulations are finalized, EME cannot determine whether the actions it is taking to comply with other legal requirements (including the CPS) will be sufficient to address its obligations under the new regulations.
Midwest Generation's compliance with the CPS supersedes the Illinois mercury regulations that would otherwise be applicable to the Midwest Generation plants. The CPS requires that, beginning in calendar year 2015, and continuing thereafter on a rolling 12-month basis, Midwest Generation must either achieve an emission standard of .008 lbs mercury/GWh gross electrical output or a minimum 90% reduction in mercury for each unit (except Unit 3 at the Will County Station, which will be included in calendar year 2016).
Midwest Generation installed required carbon injection equipment on all operating units in 2009 to achieve the necessary mercury reductions. Capital expenditures relating to these controls were $42 million. Midwest Generation will also be required to install cold side electrostatic precipitator or baghouse equipment on Unit 7 at the Waukegan Station by December 31, 2013, and on Unit 3 at the Will County Station by December 31, 2015. The
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Illinois EPA granted Midwest Generation a construction permit to install a cold-side electrostatic precipitator on Unit 7 at the Waukegan Station in November 2010.
Until Pennsylvania passes new legislation authorizing the adoption of mercury regulations or the US EPA finalizes a revised HAPs regulation that includes mercury limits, the Homer City plant will not be required to comply with Pennsylvania mercury limitations. The PADEP attempted to implement regulations that would have required coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015, as embodied in the Pennsylvania CAMR SIP. The rule did not allow the use of emissions trading to achieve compliance. The Pennsylvania Supreme Court upheld a decision by the Commonwealth Court declaring Pennsylvania's mercury rule unlawful, invalid and unenforceable, and enjoining the continued implementation and enforcement of the rule.
National Ambient Air Quality Standards
In January 2010, the US EPA proposed a revision to the primary and secondary NAAQS for 8-hour ozone that it had finalized in 2008. The 8-hour ozone standard established in 2008 was 0.075 parts per million. In January 2010, the US EPA proposed establishing a primary 8-hour ozone NAAQS between 0.060 and 0.070 parts per million and a distinct secondary standard to protect sensitive vegetation and ecosystems. The US EPA is expected to finalize the revision to the ozone NAAQS by July 2011. It is expected that once the US EPA finalizes the revised ozone NAAQS, it will propose a second Transport Rule that may further affect electric power generating units. The US EPA is also expected to propose revised fine particulate matter NAAQS in 2011, which could result in further emission reduction requirements in future years.
The Illinois SIP for compliance with the 1997 8-hour ozone standard was submitted to the US EPA in March 2009. The SIP for fine particulates was submitted to the US EPA in June 2010. As the fine particulate and ozone standards are finalized, as described above, Illinois may be required to implement additional emission control measures to address emissions of NOx, SO2 and volatile organic compounds.
In August 2007, the US EPA accepted the PADEP's maintenance plan, which indicated that the existing (and upcoming) regulations controlling emissions of volatile organic compounds and NOx will result in continued compliance with the 1997 8-hour ozone standard. However, in March 2009, the PADEP recommended to the US EPA that Indiana County (where the Homer City plant is located) be designated non-attainment under the US EPA's 2008 revised 8-hour ozone standard. Until the US EPA completes its revision to the 8-hour ozone standard, redesignations are finalized, and additional regulations are developed to achieve attainment with the revised standard, EME will not know what specific requirements it will
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have to meet. However, EME expects that its currently installed selective catalytic reduction (SCR) equipment will be capable of meeting these new requirements.
Effective April 1, 2009, the PADEP changed its air opacity policy, eliminating many exemptions and reducing the allowable exceedance rate to 0.5% of a unit's operating time. Homer City undertook optimization of unit ramp rates and combustion parameters at the Homer City plant to reduce the deratings required to meet the opacity standards. Additional capital improvements may also be required. Homer City operated below the 0.5% exceedance rate during 2010.
With respect to fine particulates, in November 2009, the US EPA indicated that Indiana County (where the Homer City plant is located) had not attained applicable standards. The PADEP must submit an updated SIP by November 13, 2012. EME cannot predict the potential effects on the Homer City plant of changes to the SIP.
The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. The goal of the rules is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions by 2064. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install BART or implement other control strategies to meet regional haze control requirements. The US EPA issued a final rulemaking on regional haze in 2005, requiring emission controls that constitute BART for industrial facilities that emit air pollutants which reduce visibility by causing or contributing to regional haze. These amendments required states to develop implementation plans to comply with BART by December 2007, to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions, and then to set BART emissions limits for those facilities. Failure to do so would result in the imposition of a Federal Implementation Plan.
Beginning on December 31, 2009, Illinois and Pennsylvania became subject to a two-year deadline after which a Federal Implementation Plan (which has not yet been proposed) will govern related emission issues. Pennsylvania submitted its proposed SIP revisions to the US EPA in December 2010 and Illinois has prepared proposed revisions to its SIP and is expected to submit them to the US EPA in 2011. Illinois proposes that the emission reductions that the Midwest Generation plants will be required to make pursuant to the CPS, discussed above in "Nitrogen Oxide and Sulfur DioxideIllinois," satisfy the BART requirement. Pennsylvania also proposes that the existing particulate matter emission limits on the Homer City plant, as well as the plant's participation in the CAIR, will satisfy the BART requirement in that state.
New Source Review Requirements
The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at the facility. Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation's coal-fired power plants. The strategy has included both the filing of suits against a number of power plant owners, and the issuance of administrative
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Notice of Violations to a number of power plant owners alleging NSR violations. The US EPA has filed enforcement actions against Homer City and Midwest Generation alleging NSR violations. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and ContingenciesContingencies."
Regulations under the federal Clean Water Act govern critical operating parameters at generating facilities, such as the temperature of effluent discharges and the location, design and construction of cooling water intake structures at generating facilities. The US EPA is rewriting these regulations following a 2009 decision by the U.S. Supreme Court holding that it may consider, but is not required to use, a cost-benefit analysis for this purpose. The Supreme Court set a deadline of March 2011 for draft regulations, which are to be finalized by July 2011. Because there are no defined compliance targets absent a new rule, EME is reviewing a wide range of possible control technologies. A new rule could have a material impact on EME's operations, but EME cannot determine the financial impact until the final compliance criteria have been published.
Midwest Generation is a party to an administrative proceeding before the Illinois Pollution Control Board to determine whether more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River, which supply cooling water to Midwest Generation's Fisk, Crawford, Will County, and Joliet Stations, will be implemented. The rule, if implemented, is expected to affect the manner in which those stations use water for station cooling. It is not possible to predict the timing for resolution of the proceeding, the final form of the rule, or how it would impact the operation of the affected stations; however, significant capital expenditures may be required.
US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from hazardous waste requirements. This classification enables beneficial uses of coal combustion residuals, such as for cement production and fill materials. Midwest Generation currently provides a portion of its coal combustion residuals for beneficial uses. Midwest Generation is also examining the impact of current and proposed emission control technologies on ash quality for beneficial use.
In June 2010, the US EPA published proposed regulations relating to coal combustion residuals. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these residuals as special wastes subject to regulation as hazardous wastes, could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these residuals as nonhazardous wastes, would establish minimum technical standards for units that are used for the disposal of coal combustion residuals, but would allow procedural and enforcement mechanisms (such
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as permit requirements) to be exclusively a matter of state law. Many of the proposed technical standards are similar under both proposed options (for example, surface impoundments may need to be retrofitted, depending on which standard is finally adopted), but the second approach would not require the retrofitting of landfills used for the disposal of coal combustion residuals.
At December 31, 2010, EME and its subsidiaries employed 1,828 people, including:
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.
EME and its subsidiaries have significant cash requirements and limited sources of capital.
At December 31, 2010, EME had corporate cash and cash equivalents of $615 million and $484 million of available borrowing capacity under its $564 million credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $295 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012.
As of December 31, 2010, EME's consolidated debt was approximately $4.5 billion. EME's subsidiaries had $2.9 billion of long-term, power plant lease obligations that are due over a period ranging up to 24 years. Compliance with current and forthcoming environmental requirements will add to EME's near-term liquidity needs.
EME's and Midwest Generation's below-investment grade credit status may limit their ability to extend or replace credit facilities, including those maturing in 2012, should they choose to do so, and the terms and conditions of any refinancing could be substantially less favorable than those in the current credit facilities, depending on market conditions. In the case of a further downgrade, EME expects that these negative effects would become more pronounced. If EME's credit facilities are not extended or replaced, or if cash flow and other means for
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assuring liquidity are unavailable or insufficient, EME may be unable to complete environmental improvements at its coal plants (which in turn could lead to unit shutdowns) or to provide credit support for contracts for power and fuel related to merchant activities. The terms of EME's and its subsidiaries' debt instruments may restrict EME's ability to sell assets or incur secured indebtedness, and EME's subsidiaries' debt instruments may limit EME's ability to seek additional capital, or restructure or refinance debt to satisfy liquidity needs. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources."
EME is a holding company and may be limited in its ability to access funds from its subsidiaries to meet its obligations.
EME has no material assets other than the stock of its subsidiaries and depends to a large degree upon dividends and other transfers of funds from its subsidiaries to meet its obligations. EME's subsidiaries are separate and distinct legal entities and have no obligation to provide EME with funds. The ability of EME's subsidiaries to pay dividends and make other payments to EME may be restricted by, among other things, applicable corporate and other laws, potentially adverse tax consequences, and restrictions contained in agreements entered into by the subsidiaries. If EME is unable to access the cash flow of its subsidiaries, it may have difficulty meeting its own obligations. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesEME's Liquidity as a Holding Company" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesDividend Restrictions in Major Financings.
EME depends upon tax-allocation payments from Edison International to meet its obligations. EME receives these payments only if, and only to the extent that, Edison International is able to utilize tax losses and credits generated by EME.
EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income to be able to utilize EME's consolidated tax losses and credits in the consolidated income tax returns for Edison International and its subsidiaries. The timing of certain tax-allocation payments was delayed in 2010, as a result of the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act, because Edison International was not able to fully utilize EME's consolidated tax losses and credits. Tax-allocation payments to EME may be further delayed until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years as a result of these new tax laws. For further discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesAvailable LiquidityBonus Depreciation Impact on EME."
These arrangements are subject to the terms of the tax-allocation and payment agreements among Edison International, Mission Energy Holding Company, EME and other Edison International subsidiaries. The agreements under which EME receives tax-allocation payments may be terminated by the immediate parent company at any time, by notice given before the first day of the first year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year
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beginning prior to the notice. For further discussion, see "Liquidity and Capital ResourcesEME's Liquidity as a Holding CompanyIntercompany Tax-Allocation Agreement."
The interests of Edison International as EME's equity holder may conflict with the interests of holders of debt.
EME is indirectly owned and controlled by Edison International. The directors appointed by Edison International are able to make decisions affecting EME's capital structure which could include, subject to contractual obligations and applicable law, decisions to incur or repurchase debt, pay dividends, or otherwise take actions that may alter the portion of Edison International's portfolio of assets that is held and developed by EME. The interests of Edison International may not in all cases be aligned with the interests of the holders of EME's debt or the debt and lease obligations of EME's subsidiaries. If EME encounters financial difficulties or becomes unable to pay its debts as they mature, the interests of Edison International might conflict with the interests of holders of EME's and its subsidiaries' debt. In addition, Edison International may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its equity investments, even though such transactions might involve risks to EME's business or the holders of EME's and its subsidiaries' debt. Furthermore, Edison International may in the future own businesses that directly or indirectly compete with EME. Edison International also may pursue acquisition opportunities that may be complementary to EME's business, and as a result, those acquisition opportunities may not be available to EME.
Regulatory and Environmental Risks
EME is subject to extensive environmental regulation and permitting requirements that may involve significant and increasing costs.
EME's operations are subject to extensive and frequently changing environmental regulations with respect to, among other things, air quality, water quality and waste disposal, which involve significant and increasing costs and substantial uncertainty. EME is required to obtain, and comply with conditions established by, licenses, permits and other approvals in order to construct, operate or modify its facilities. Failure to comply with these requirements could subject EME to civil or criminal liability, the imposition of liens or fines, or actions by regulatory agencies seeking to curtail operations of EME's projects. EME may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to off-site waste disposal sites that have been used in its operations.
EME devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. EME believes that it is currently in substantial compliance with environmental regulatory requirements. However, the US EPA has filed enforcement actions against Midwest Generation and Homer City alleging violations of the CAA and other regulations at the Midwest Generation plants and the Homer City plant. For more detail with respect to these matters, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and Contingencies."
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The current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The adoption of laws and regulations to implement CO2 controls could adversely affect coal-fired power plants. Other environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge and cooling water systems, are also generally becoming more stringent. The continued operation of EME's facilities, particularly its coal plants, is expected to require substantial capital expenditures for environmental controls. If EME cannot comply with all applicable regulations, it could be required to retire or suspend operations at some of its facilities, or restrict or modify the operations of its facilities, and its business, results of operations and financial condition could be adversely affected.
Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. EME cannot provide assurance that it will be able to obtain and comply with all necessary licenses, permits and approvals for its plants. If there is a delay in obtaining required approvals or permits or if EME fails to obtain and comply with such permits, the operation of EME's facilities may be interrupted or become subject to additional costs.
The controls imposed on the Midwest Generation plants as a result of the CPS may require material expenditures or unit shutdowns.
All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. Capital expenditures relating to controls contemplated by the CPS are expected to be significant and could make some units uneconomic to maintain or operate. Midwest Generation may ultimately decide to comply with CPS requirements by shutting down units rather than making improvements. Unit shutdowns could have an adverse effect on EME's business, results of operation and financial condition. For more information about the CPS requirements and Midwest Generation's plans for compliance, see "Item 1. BusinessEnvironmental Matters and RegulationsAir QualityNitrogen Oxide and Sulfur DioxideIllinois."
EME is subject to extensive energy industry regulation.
EME's operations are subject to extensive regulation by governmental agencies. EME's projects are subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operation of generation facilities, and access to transmission. Generation facilities are also subject to federal, state and local laws and regulations that govern, among other things, the geographical location, zoning, land use and operation of a project. EME in the course of its business must obtain and periodically renew licenses, permits and approvals for its facilities. The FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines that potential market power might exist and that the public interest requires mitigation. RTOs and ISOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to facilitate market functions. Such actions may materially affect EME's results of operations. EME's facilities are also subject to mandatory reliability standards promulgated by NERC, compliance with which can increase the facilities' operating costs or capital expenditures.
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This extensive governmental regulation creates significant risks and uncertainties for EME's business. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to EME or its facilities or operations in a manner that may have a detrimental effect on its business or result in significant additional costs.
EME has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices because they operate without long-term power purchase agreements. Wholesale energy prices have substantially declined in recent years.
EME's merchant energy power plants do not have long-term power purchase agreements. Because the output of these power plants is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the amount and price of energy, capacity and ancillary services sold from the power plants. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced when it is to be used. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of time. Due to the volume of sales into PJM from the coal plants, EME has concentrated exposure to market conditions and fluctuations in PJM. Prices for power have declined significantly in recent years as a result of increased use of demand response technology, changes in final demand for power during the economic slowdown, and technological developments that have permitted the exploitation of natural gas shale reserves in a way that has resulted in substantial declines in market prices for natural gas which supplies power plants that compete with EME's coal plants.
Market prices of energy, capacity and ancillary services sold from these power plants are influenced by multiple factors beyond EME's control, and thus there is considerable uncertainty whether or when current depressed prices will recover or whether EME can effectively hedge the risks involved on economic terms. EME's hedging activities may not cover the entire exposure of its assets or positions to market price volatility, and the level of coverage will vary over time. The effectiveness of EME's hedging activities may depend on the amount of credit available to post collateral, either in support of performance guarantees or as cash margin, and liquidity requirements may be greater than EME anticipates or will be able to meet. EME cannot provide assurance that its hedging strategies will successfully mitigate market risks. For more detail with respect to these matters, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk ExposuresCommodity Price Risk."
EME's financial results can be affected by changes in prices, transportation cost, and supply interruptions related to fuel, sorbents, and other commodities used for power generation and emission controls.
In addition to volatile power prices, EME's business is subject to changes in the cost of fuel, sorbents, and other commodities used for power generation and emission controls, and in the cost of transportation. These costs can be volatile and are influenced by many factors outside EME's control. The price at which EME can sell its energy may not rise or fall at the same rate as a corresponding rise or fall in commodity costs. Operations at the coal plants are
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dependent upon the availability and affordability of coal which is available only from a limited number of suppliers and which, in the case of Midwest Generation, is transported by rail under a long-term transportation contract that will expire in 2011. All of these factors may have an adverse effect on EME's financial condition and results of operations.
Competition could adversely affect EME's business.
EME has numerous competitors in all aspects of its business, some of whom may have greater liquidity, greater access to credit and other financial resources, lower cost structures, greater ability to withstand losses, larger staffs or more experience than EME. Multiple participants in the wholesale markets, including many regulated utilities, have a lower cost of capital than most merchant generators and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. These factors could affect EME's ability to compete effectively in the markets in which those entities operate. Newer plants owned by EME's competitors are often more efficient than EME's facilities and may also have lower costs of operation. Over time, some of EME's merchant facilities may become obsolete in their markets, or be unable to compete with such plants.
EME's development projects may not be successful.
EME's development activities are subject to risks including, without limitation, risks related to the identification of project sites, financing, construction, permitting, governmental approvals and the negotiation of project agreements, including power purchase agreements. EME may be required to spend significant amounts for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses before it can determine whether a project is feasible, economically attractive, or capable of being built. As a result of these risks, EME may not be successful in developing new projects, or the timing of such development may be delayed beyond the date that equipment is ready for installation, in which case EME may be required to incur material equipment and/or material costs with no deployment plan at delivery. Projects under development may also be adversely affected by delays in construction or equipment deliveries, commissioning delays or performance issues, and agreements with off-takers may contain damages and termination provisions related to failures to meet specified milestones. Due to competing capital needs, EME's further development of its renewable business will depend upon the availability of third-party equity capital.
EME's projects may be affected by general operating risks and hazards customary in the power generation industry. EME may not have adequate insurance to cover all these hazards.
The operation of power generation facilities is a potentially dangerous activity that involves many operating risks, including transmission disruptions and constraints, equipment failures or shortages, and system limitations, degradation and interruption. EME's operations are also subject to risks of human performance and workforce capabilities. There can be no assurance that EME's insurance will be sufficient or effective under all circumstances or protect against all hazards to which EME may be subject or that insurance coverage will continue to be available on terms similar to those presently available, or at all. EME has a number of older
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facilities with potentially higher risks of failure or outage than an average plant, and EME has in the past experienced serial defects in certain models of wind turbines deployed at its wind projects.
Uncertainties in EME's future operations could affect its ability to attract and retain skilled people.
Uncertainties concerning EME's future operations could affect its ability to attract and retain qualified personnel with experience in the energy industry. If EME is unable to successfully attract and retain an appropriately qualified workforce, its results of operations will be negatively affected.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Inapplicable.
EME leases its principal office in Santa Ana, California. The office lease is currently for approximately 85,000 square feet and expires on December 31, 2020. EME also leases office space in Chicago, Illinois; Bolingbrook, Illinois; and Boston, Massachusetts. The Chicago lease is for approximately 41,000 square feet and expires on November 30, 2011. A portion of the Chicago office facility, representing approximately 15,000 square feet, is subleased through November 30, 2011. The Bolingbrook lease is for approximately 20,000 square feet and expires on March 31, 2014. The Boston lease is for approximately 41,000 square feet and expires on September 30, 2017.
The following table shows, as of December 31, 2010, the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of EME's income before tax or is one in which EME has an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project.
Plant |
Location |
Interest in Land |
Plant Description |
|||
---|---|---|---|---|---|---|
Homer City plant | Pittsburgh, Pennsylvania | Owned | 1 | Coal-fired generation facility | ||
Midwest Generation plants | Northeast Illinois | Owned | 2 | Coal, oil-fired generation facilities | ||
Elkhorn Ridge | Bloomfield, Nebraska | Leased | Wind-powered electric generation facility | |||
Kern River | Bakersfield, California | Leased | Natural gas-turbine cogeneration facility | |||
Midway-Sunset | Taft, California | Leased | Natural gas-turbine cogeneration facility | |||
San Juan Mesa | Elida, New Mexico | Leased | Wind-powered electric generation facility | |||
Sunrise | Fellows, California | Leased | Combined cycle generation facility | |||
Sycamore | Bakersfield, California | Leased | Natural gas-turbine cogeneration facility | |||
Watson | Carson, California | Leased | Natural gas-turbine cogeneration facility | |||
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For a discussion of the material legal proceedings specifically affecting EME, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and Contingencies."
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
All the outstanding common stock of EME is, as of the date hereof, owned by Mission Energy Holding Company, which is a wholly owned subsidiary of Edison Mission Group Inc., a wholly owned subsidiary of Edison International. There is no market for the common stock. Dividends on the common stock are paid when declared by EME's board of directors. EME did not pay or declare any dividends during 2010, 2009 and 2008. Dividends from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax considerations, and restrictions imposed by applicable law. For more information about dividend restrictions in EME's corporate credit facility, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesDividend Restrictions in Major Financings."
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ITEM 6. SELECTED FINANCIAL DATA
The selected financial data was derived from EME's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report. EME's international operations, which were sold in 2004, are accounted for as discontinued operations, except the Doga project located in the Republic of Turkey, which EME still owns.
INCOME STATEMENT DATA (in millions) |
|||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Years Ended December 31, | ||||||||||||||||
|
2010 |
2009 |
2008 |
2007 |
2006 |
||||||||||||
Operating Revenues |
$ | 2,423 | $ | 2,377 | $ | 2,811 | $ | 2,580 | $ | 2,239 | |||||||
Operating Expenses |
|||||||||||||||||
Fuel, plant operations and plant operating leases |
1,641 | 1,552 | 1,544 | 1,444 | 1,332 | ||||||||||||
Depreciation and amortization |
248 | 236 | 194 | 162 | 144 | ||||||||||||
Asset write-downs, gain on buyout of contract, loss on termination of contract, and other charges and credits, net |
45 | 4 | 14 | 6 | | ||||||||||||
Administrative and general |
182 | 196 | 207 | 204 | 140 | ||||||||||||
|
2,116 | 1,988 | 1,959 | 1,816 | 1,616 | ||||||||||||
Operating Income |
307 | 389 | 852 | 764 | 623 | ||||||||||||
Equity in income from unconsolidated affiliates |
104 | 100 | 122 | 200 | 186 | ||||||||||||
Interest and other income |
30 | 24 | 48 | 103 | 120 | ||||||||||||
Interest expense, net of capitalized interest |
(263 | ) | (296 | ) | (279 | ) | (273 | ) | (279 | ) | |||||||
Loss on early extinguishment of debt |
| | | (160 | ) | (146 | ) | ||||||||||
Income from continuing operations before income taxes |
178 | 217 | 743 | 634 | 504 | ||||||||||||
Provision for income taxes |
19 | 16 | 243 | 219 | 189 | ||||||||||||
Income from continuing operations |
159 | 201 | 500 | 415 | 315 | ||||||||||||
Income (loss) from operations of discontinued subsidiaries, net of tax |
4 | (7 | ) | 1 | (2 | ) | 98 | ||||||||||
Net Income |
163 | 194 | 501 | 413 | 413 | ||||||||||||
Net Loss Attributable to Noncontrolling Interests |
1 | 3 | | 1 | 1 | ||||||||||||
Net Income Attributable to EME Common Shareholder |
$ | 164 | $ | 197 | $ | 501 | $ | 414 | $ | 414 | |||||||
BALANCE SHEET DATA (in millions) |
||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
As of December 31, | |||||||||||||||
|
2010 |
2009 |
2008 |
2007 |
2006 |
|||||||||||
Current assets |
$ | 1,859 | $ | 1,862 | $ | 2,661 | $ | 1,734 | $ | 2,594 | ||||||
Total assets |
9,321 | 8,633 | 9,080 | 7,272 | 7,235 | |||||||||||
Current liabilities |
524 | 549 | 635 | 454 | 631 | |||||||||||
Long-term debt net of current maturities |
4,342 | 3,929 | 4,638 | 3,806 | 3,035 | |||||||||||
Total EME common shareholder's equity |
2,817 | 2,761 | 2,684 | 1,923 | 2,582 | |||||||||||
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EME's competitive power generation business primarily consists of the generation and sale into the PJM market of energy and capacity from its approximately 7,000 megawatts of coal-fired power plants. The profitability of these operations is expected to decline significantly in 2011 as a result of lower realized energy prices (largely driven by the expiration of hedge contracts) and higher fuel costs. In addition, the profitability of EME's Midwest Generation plants is expected to be adversely affected in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract). For discussion of energy and fuel price risks, see "Market Risk ExposuresCommodity Price Risk" and "Item 1A. Risk FactorsMarket Risks." As a result of the projected decrease in profitability of EME's merchant activities, EME may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.
Highlights of Operating Results
Net income attributable to EME common shareholder is comprised of the following components:
|
Years Ended December 31, |
|
|
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Year Ended December 31, 2008 |
||||||||||||
(in millions) |
2010 |
2009 |
Change |
|||||||||||
Net income attributable to EME common shareholder |
$ | 164 | $ | 197 | $ | (33 | ) | $ | 501 | |||||
Non-Core Items |
||||||||||||||
Write-off of capitalized costs |
(24 | ) | | (24 | ) | | ||||||||
Income (loss) from discontinued operations |
4 | (7 | ) | 11 | 1 | |||||||||
Settlement of tax disputes |
16 | 6 | 10 | | ||||||||||
Total non-core items |
(4 | ) | (1 | ) | (3 | ) | 1 | |||||||
Core Earnings |
$ | 168 | $ | 198 | $ | (30 | ) | $ | 500 | |||||
EME's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as net income attributable to EME's shareholder excluding income from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, sale of assets, early debt extinguishment costs, other activities that are no longer continuing, asset impairments, and certain tax, regulatory or legal proceedings.
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EME's 2010 core earnings were lower than 2009 core earnings primarily due to the following pre-tax items:
The decrease was partially offset by the following pre-tax items:
In addition to the preceding pre-tax items, core earnings in 2010 were lower due to $15 million of increased tax expenses that resulted from the recapture of Section 199 deductions realized in prior years resulting from the carryback of net operating tax losses.
Non-core items for EME included:
EME's 2009 earnings were significantly lower than 2008 primarily due to the following:
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West locations during 2009. Electrical load, calculated from data published by PJM, for these locations declined 5% and 3%, respectively, during 2009 compared to 2008. In addition, the price of natural gas, which often serves as the marginal fuel source in the region, declined significantly. The reduction in natural gas prices together with lower electrical demand resulted in significantly lower wholesale energy prices. The average 24-hour PJM real-time price for energy at the Northern Illinois Hub and the PJM West Hub declined to $28.86/MWh and $38.31/MWh, respectively, during 2009 as compared to $49.01/MWh and $68.56/MWh, respectively, during 2008.
Midwest Generation Environmental Compliance Plans and Costs
During 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois EPA to allow the installation of SNCR technology on multiple units to meet the NOx portion of the CPS. In November 2010 and February 2011, the Illinois EPA issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or its equivalent at the Waukegan generating station's Unit 7 and Units 5 and 6 at the Powerton Station. The permit for Unit 7 at the Waukegan Station also authorizes Midwest Generation to convert the existing electrostatic precipitator to a cold-side design which will improve removal efficiency of particulate matter to satisfy the particulate control requirements of the CPS.
Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO2 emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time than the use of spray dryer absorber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs.
Based on work to date, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, and the associated upgrading of existing particulate removal systems, would be approximately $1.2 billion in 2010 dollars. If these projects are undertaken, these expenditures would be incurred through 2018.
Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs
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applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project.
Homer City Environmental Issues and Capital Resource Limitations
Homer City may be required to install additional environmental equipment on Units 1 and 2 to comply with environmental regulations under the Transport Rule. Homer City projects that if SO2 reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO2 and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. The installation of environmental compliance equipment will be dependent on lessor decisions regarding the funding of these expenditures. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. EME has no legal obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made.
For information regarding recent developments in environmental regulations, see "Item 1. BusinessEnvironmental Matters and Regulations."
At December 31, 2010, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW and had four projects totaling 480 MW under construction. EME anticipates that these projects will achieve commercial operation in 2011. In addition to the projects under construction at December 31, 2010, EME expects the 55 MW Pinnacle project in West Virginia will commence construction in 2011 with anticipated commercial operation in 2011. The pace of additional growth in EME's renewable program will be subject to the availability of third-party capital.
At December 31, 2010, EME, as a holding company, had cash and cash equivalents of $427 million to meet liquidity needs as well as $484 million of capacity under its credit facility. EME's subsidiary, EMMT, also had cash and cash equivalents of $168 million at
42
December 31, 2010, which can be loaned or distributed to EME subject to applicable corporate and other laws. In addition, at December 31, 2010, Midwest Generation had cash and cash equivalents of $295 million to meet liquidity needs.
Midwest Generation has not yet committed to the completion of environmental compliance activities for all of its plants. Expenditures for NOx and SO2 controls through 2013 are estimated at $481 million based on an assumption that Midwest Generation would retrofit all units over the compliance period, which extends to 2018. Depending upon the facilities selected to be retrofitted, the cost of such retrofitting, and the timing of funding requirements beyond the near term, Midwest Generation may utilize operating cash flow, draw on its credit facilities, when available, or seek debt financing to fund capital expenditures.
Capital expenditures to complete renewable energy projects through 2011 are projected to be $279 million at December 31, 2010. EME anticipates that capital investment for renewable energy projects under or pending construction will be funded using a combination of construction and term financings, U.S. Treasury grants and third-party capital. EME has available secured project financing of $48 million. In addition, U.S. Treasury grants of $346 million are anticipated based on estimated eligible construction costs for renewable projects completed in 2010 and scheduled to be completed in 2011.
Edison International's utilization of net operating losses and production tax credits from EME in its consolidated return impacts EME's liquidity. The bonus depreciation extension enacted in the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act is expected to result in delays in EME's receipt of future tax-allocation payments. For more information, see "Liquidity and Capital ResourcesEME's Liquidity as a Holding CompanyIntercompany Tax-Allocation Agreement," "Liquidity and Capital ResourcesAvailable LiquidityBonus Depreciation Impact on EME" and "Item 1A. Risk FactorsLiquidity Risks."
43
Results of Continuing Operations
EME operates in one line of business, independent power production. The following section and table provide a summary of results of EME's operating projects and corporate expenses for the three years ended December 31, 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.
The following table shows the adjusted operating income (AOI) of EME's projects:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Midwest Generation plants |
$ | 264 | $ | 340 | $ | 688 | ||||
Homer City plant |
114 | 186 | 202 | |||||||
Renewable energy projects |
51 | 53 | 60 | |||||||
Energy trading |
110 | 49 | 164 | |||||||
Big 4 projects |
52 | 46 | 87 | |||||||
Sunrise |
33 | 37 | 24 | |||||||
Doga |
15 | 8 | 8 | |||||||
March Point1 |
17 | 11 | | |||||||
Westside projects |
1 | 4 | 9 | |||||||
Other projects |
9 | 9 | 13 | |||||||
Other operating income (expense) |
| | (31 | ) | ||||||
|
666 | 743 | 1,224 | |||||||
Corporate administrative and general |
(145 | ) | (163 | ) | (172 | ) | ||||
Corporate depreciation and amortization |
(19 | ) | (15 | ) | (12 | ) | ||||
AOI2 |
$ | 502 | $ | 565 | $ | 1,040 | ||||
44
The following table reconciles AOI to operating income as reflected on EME's consolidated statements of income:
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
AOI |
$ | 502 | $ | 565 | $ | 1,040 | |||||
Less: |
|||||||||||
Equity in income of unconsolidated affiliates |
104 | 100 | 122 | ||||||||
Dividend income from projects |
19 | 12 | 10 | ||||||||
Production tax credits |
62 | 56 | 44 | ||||||||
Other income, net |
9 | 5 | 12 | ||||||||
Net loss attributable to noncontrolling interests |
1 | 3 | | ||||||||
Operating Income |
$ | 307 | $ | 389 | $ | 852 | |||||
Adjusted Operating Income from Consolidated Operations
The following table presents additional data for the Midwest Generation plants:
|
Years Ended December 31 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||||
Operating Revenues |
$ | 1,479 | $ | 1,487 | $ | 1,778 | ||||||
Operating Expenses |
||||||||||||
Fuel1 |
519 | 547 | 482 | |||||||||
Plant operations |
448 | 396 | 431 | |||||||||
Plant operating leases |
75 | 75 | 75 | |||||||||
Depreciation and amortization |
114 | 109 | 106 | |||||||||
Asset write-downs and (gain) on buyout of contract |
42 | 2 | (16 | ) | ||||||||
Administrative and general |
22 | 21 | 22 | |||||||||
Total operating expenses |
1,220 | 1,150 | 1,100 | |||||||||
Operating Income |
259 | 337 | 678 | |||||||||
Other Income |
5 | 3 | 10 | |||||||||
AOI |
$ | 264 | $ | 340 | $ | 688 | ||||||
45
|
Years Ended December 31 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||||
Statistics2 |
||||||||||||
Generation (in GWh) |
||||||||||||
Energy contracts |
29,798 | 28,977 | 26,010 | |||||||||
Load requirements services contracts |
| 1,333 | 5,090 | |||||||||
Total |
29,798 | 30,310 | 31,100 | |||||||||
Aggregate plant performance |
||||||||||||
Equivalent availability |
82.2 | % | 85.3% | 81.0 | % | |||||||
Capacity factor |
62.3 | % | 63.3% | 64.8 | % | |||||||
Load factor |
75.8 | % | 74.2% | 80.0 | % | |||||||
Forced outage rate |
6.2 | % | 5.8% | 8.3 | % | |||||||
Average realized price/MWh |
||||||||||||
Energy contracts |
$ | 40.12 | $ | 41.17 | $ | 51.82 | ||||||
Load requirements services contracts |
$ | | $ | 62.52 | $ | 62.64 | ||||||
Capacity revenues only (in millions) |
$ | 263 | $ | 178 | $ | 111 | ||||||
Average realized fuel costs/MWh |
$ | 17.17 | $ | 18.54 | $ | 15.49 | ||||||
AOI from the Midwest Generation plants decreased $76 million in 2010 compared to 2009, and decreased $348 million in 2009 compared to 2008. Excluding the $40 million pre-tax charge related to the Powerton Station, the 2010 decrease in AOI was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009 related to hedge contracts and an increase in plant maintenance costs, partially offset by higher capacity revenues, a gain from the sale of the bankruptcy claims against Lehman Brothers, and lower average realized fuel costs. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Average realized fuel costs per megawatt-hour were lower in 2010 as compared to 2009 primarily due to lower emission allowance costs partially offset by higher costs for activated carbon, which is used to reduce mercury emissions.
The 2009 decrease in AOI as compared to 2008 was primarily attributable to lower realized energy prices and higher average realized fuel costs, partially offset by higher capacity revenues, unrealized gains in 2009 compared to unrealized losses in 2008 related to hedge contracts, and lower plant operations expense. The 2009 increase in average realized fuel costs was due to higher emission allowance costs to comply with the CAIR annual NOx emission program that began in 2009 and higher costs for activated carbon to implement new mercury emission controls. The 2009 decline in plant operations expense was due to cost containment efforts and the deferral of plant overhaul activities.
46
Included in operating revenues were unrealized gains (losses) of $(6) million, $30 million and $(6) million in 2010, 2009 and 2008, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily due to economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of income. In addition, $10 million and $14 million were reversed from accumulated other comprehensive income and recognized in 2010 and 2009, respectively, related to the power contracts with Lehman Brothers. Unrealized losses in 2008 included a $24 million write-down of power contracts with Lehman Brothers for 2009 and 2010 forecasted generation. These contracts qualified as cash flow hedges until EME dedesignated the contracts due to nonperformance risk and subsequently terminated the contracts. The change in fair value was recorded as an unrealized loss during 2008. In addition, unrealized gains (losses) included the ineffective portion of hedge contracts at the Midwest Generation plants attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system) resulting from marginal losses.
Included in fuel costs were unrealized gains (losses) of $(7) million and $15 million for the year ended December 31, 2010 and 2009, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.
47
The following table presents additional data for the Homer City plant:
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Operating Revenues |
$ | 636 | $ | 663 | $ | 717 | |||||
Operating Expenses |
|||||||||||
Fuel1 |
279 | 251 | 270 | ||||||||
Plant operations |
117 | 104 | 126 | ||||||||
Plant operating leases |
103 | 102 | 102 | ||||||||
Depreciation and amortization |
18 | 16 | 16 | ||||||||
Administrative and general |
5 | 4 | 4 | ||||||||
Total operating expenses |
522 | 477 | 518 | ||||||||
Operating Income |
114 | 186 | 199 | ||||||||
Other Income |
| | 3 | ||||||||
AOI |
$ | 114 | $ | 186 | $ | 202 | |||||
Statistics2 |
|||||||||||
Generation (in GWh) |
11,028 | 11,446 | 11,334 | ||||||||
Equivalent availability |
79.7 | % | 84.7% | 80.7 | % | ||||||
Capacity factor |
66.8 | % | 69.2% | 68.3 | % | ||||||
Load factor |
83.8 | % | 81.7% | 84.6 | % | ||||||
Forced outage rate |
10.8 | % | 9.4% | 9.8 | % | ||||||
Average realized energy price/MWh |
$ | 49.04 | $ | 48.85 | $ | 56.24 | |||||
Capacity revenues only (in millions) |
$ | 114 | $ | 89 | $ | 46 | |||||
Average fuel costs/MWh |
$ | 25.26 | $ | 21.89 | $ | 23.35 | |||||
On February 10, 2011, a steam pipe ruptured at Unit 1 of the Homer City plant, taking the unit off line. As a precautionary measure, Homer City has taken Unit 2 (which has the same design) off line in order to further evaluate the equipment and perform any necessary corrective work. Work has commenced to inspect the piping that failed and planning activities to install replacement piping on both units are underway. Homer City is in the process of modifying its scheduled maintenance plans to incorporate this outage. It is expected that both units will return to service during the second quarter of 2011.
AOI from the Homer City plant decreased $72 million in 2010 compared to 2009 and decreased $16 million in 2009 compared to 2008. The 2010 decrease in AOI was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009 related to
48
hedge contracts, higher coal costs, lower generation, and higher plant operations costs related to scheduled plant outages, partially offset by an increase in capacity revenues. The Homer City plant experienced increased forced outages in 2010 compared to 2009 due to deratings to comply with opacity restrictions and unscheduled outages. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Coal costs increased due to higher coal prices and changes in the mix of ready-to-burn coal and raw coal consumed.
The 2009 decrease in AOI as compared to 2008 was primarily attributable to lower realized energy prices, partially offset by an increase in capacity revenues, lower plant operations expense and lower coal costs. The decline in plant operations expense was attributable to cost containment efforts and the deferral of plant overhaul activities.
Included in operating revenues were unrealized gains (losses) from hedge activities of $(20) million, $15 million and $21 million in 2010, 2009 and 2008, respectively. Unrealized gains (losses) were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).
Reconciliation of Non-GAAP DisclosuresCoal Plants and Statistical Definitions
The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenues less unrealized gains (losses) and other non-energy related revenues by (ii) generation as shown in the table below. Revenues related to capacity sales are excluded from the calculation of average realized energy price.
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Midwest Generation Plants (in millions) |
|||||||||||
2010 |
2009 |
2008 |
|||||||||
Operating revenues |
$ | 1,479 | $ | 1,487 | $ | 1,778 | |||||
Less: |
|||||||||||
Load requirements services contracts |
| (83 | ) | (319 | ) | ||||||
Unrealized (gains) losses |
6 | (30 | ) | 6 | |||||||
Capacity and other1 revenues |
(290 | ) | (181 | ) | (117 | ) | |||||
Realized revenues |
$ | 1,195 | $ | 1,193 | $ | 1,348 | |||||
Generationenergy contracts (in GWh) |
29,798 | 28,977 | 26,010 | ||||||||
Average realized energy price/MWh |
$ |
40.12 |
$ |
41.17 |
$ |
51.82 |
|||||
49
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Homer City (in millions) |
|||||||||||
2010 |
2009 |
2008 |
|||||||||
Operating revenues |
$ | 636 | $ | 663 | $ | 717 | |||||
Less: |
|||||||||||
Unrealized (gains) losses |
20 | (15 | ) | (21 | ) | ||||||
Capacity and other revenues |
(115 | ) | (89 | ) | (59 | ) | |||||
Realized revenues |
$ | 541 | $ | 559 | $ | 637 | |||||
Generation (in GWh) |
11,028 | 11,446 | 11,334 | ||||||||
Average realized energy price/MWh |
$ |
49.04 |
$ |
48.85 |
$ |
56.24 |
|||||
The average realized energy price is presented as an aid in understanding the operating results of the coal plants. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the operating revenues of the coal plants and renewable energy projects to consolidated operating revenues presented in the preceding table is set forth below:
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Operating revenues |
|||||||||||
Midwest Generation plants |
$ | 1,479 | $ | 1,487 | $ | 1,778 | |||||
Homer City plant |
636 | 663 | 717 | ||||||||
Renewable energy projects |
137 | 141 | 108 | ||||||||
Other revenues |
171 | 86 | 208 | ||||||||
Consolidated operating revenues as reported |
$ | 2,423 | $ | 2,377 | $ | 2,811 | |||||
The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including emission allowance costs and the effects of hedges. It is determined by dividing (i) fuel costs adjusted for unrealized gains (losses) by (ii) generation as shown in the table below:
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Midwest Generation Plants (in millions) |
|||||||||||
2010 |
2009 |
2008 |
|||||||||
Fuel costs |
$ | 519 | $ | 547 | $ | 482 | |||||
Add back: |
|||||||||||
Unrealized gains (losses) |
(7 | ) | 15 | | |||||||
Realized fuel costs |
$ | 512 | $ | 562 | $ | 482 | |||||
Total generation (in GWh) |
29,798 | 30,310 | 31,100 | ||||||||
Average realized fuel costs/MWh |
$ |
17.17 |
$ |
18.54 |
$ |
15.49 |
|||||
50
The average realized fuel costs are presented as an aid in understanding the operating results of the Midwest Generation plants. Average realized fuel costs are a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel costs. Management believes that average realized fuel costs are meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the fuel costs of the coal plants to consolidated fuel costs presented in the preceding table is set forth below:
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Fuel costs |
|||||||||||
Midwest Generation plants |
$ | 519 | $ | 547 | $ | 482 | |||||
Homer City plant |
279 | 251 | 270 | ||||||||
Other |
11 | (2 | ) | (5 | ) | ||||||
Consolidated fuel costs as reported |
$ | 809 | $ | 796 | $ | 747 | |||||
51
The following table presents additional data for EME's renewable energy projects:
|
Years Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||||
Operating Revenues |
$ | 137 | $ | 141 | $ | 108 | ||||||
Production Tax Credits |
62 | 56 | 44 | |||||||||
|
199 | 197 | 152 | |||||||||
Operating Expenses |
||||||||||||
Plant operations |
55 | 55 | 35 | |||||||||
Depreciation and amortization |
89 | 92 | 59 | |||||||||
Asset impairment and sale of assets |
3 | | | |||||||||
Administrative and general |
3 | 3 | 2 | |||||||||
Total operating expenses |
150 | 150 | 96 | |||||||||
Other Income |
2 |
3 |
4 |
|||||||||
Net Loss Attributable to Noncontrolling Interests |
|
3 |
|
|||||||||
AOI1 |
$ | 51 | $ | 53 | $ | 60 | ||||||
Statistics2 |
||||||||||||
Generation (in GWh)3 |
3,646 | 3,081 | 2,286 | |||||||||
Aggregate plant performance3 |
||||||||||||
Equivalent availability |
91.78% | 88.7% | 80.4 | % | ||||||||
Capacity factor |
32.97% | 31.4% | 33.1 | % | ||||||||
AOI from renewable energy projects decreased $2 million in 2010 compared to 2009, and decreased $7 million in 2009 compared to 2008. The 2010 decrease was primarily due to the impairment of a Minnesota Wind project and an increase in costs related to projects under construction. The 2009 decrease in AOI was primarily attributable to mild wind conditions, which reduced the revenue increases relative to the increased operating costs associated with additional projects coming on line. Expenses incurred for projects under construction also contributed to the decrease in AOI. EME's share of installed capacity of new wind projects that commenced operations during 2010, 2009 and 2008 was 150 MW, 223 MW and 396 MW, respectively.
52
AOI in 2010, 2009 and 2008 included payments from Suzlon Wind Energy Corporation (Suzlon) for availability losses of $2 million, $17 million and $28 million, respectively. Payments under the availability guarantee are designed to compensate EME for lost earnings, including production tax credits. Accordingly, the payments under the availability guarantee are paid on a pre-tax basis which affects period-to-period comparisons that include production tax credits which are after tax.
EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities primarily in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from ISOs.
AOI from energy trading activities increased $61 million in 2010 compared to 2009, and decreased $115 million in 2009 compared to 2008. The 2010 increase in AOI energy trading activities was attributable to increased revenues in congestion and power trading. Congestion trading results increased in 2010 compared to 2009 due to unseasonable cold weather and transmission outages in the New York and PJM markets. The 2009 decrease in AOI from energy trading activities was attributable to lower transmission congestion in the eastern U.S. power grid. In addition, energy trading included favorable results for load service transactions in 2009.
Adjusted Operating Income from Unconsolidated Affiliates
Big 4 Projects. AOI from the Big 4 projects increased $6 million in 2010 compared to 2009, and decreased $41 million in 2009 compared to 2008. The changes in income are driven by changes in natural gas prices affecting steam revenues and plant maintenance.
Sunrise. AOI from the Sunrise project decreased $4 million in 2010 from 2009 and increased $13 million in 2009 from 2008. The 2010 decrease was primarily due to a lower availability bonus, partially offset by lower maintenance expenses. The 2009 increase was primarily due to higher availability incentive payments in 2009 and lower maintenance expenses.
March Point. AOI from the March Point project increased $6 million in 2010 from 2009 and $11 million in 2009 from 2008. The 2010 increase was primarily due to equity distributions received from the project. EME subsequently sold its ownership interest in the March Point project to its partner at book value in February 2010. The 2009 increase was due to EME recommencing recording its share of equity in income from the March Point project in 2009.
Doga. AOI from the Doga project increased $7 million in 2010 from 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.
53
Other Operating Income (Expense)
Other operating income (expense) in 2008 resulted from a charge of $23 million related to the termination of a turbine supply agreement in connection with the Walnut Creek project and a $7 million write-down of capitalized costs related to development projects. These amounts are reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statements of income. For additional information regarding capital expenditures for turbines and the Walnut Creek project, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and ContingenciesOther Commitments" and "Note 15. Related-Party Transactions."
Corporate Administrative and General Expenses
Corporate administrative and general expenses decreased $18 million in 2010 from 2009 and decreased $9 million in 2009 from 2008. The 2010 and 2009 decreases were primarily attributable to lower development costs related to renewable energy. In April 2009, EME reduced approximately 75 positions in its regional and corporate offices.
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Interest income |
$ | 2 | $ | 7 | $ | 26 | |||||
Interest expense, net of capitalized interest |
|||||||||||
EME debt |
(229 | ) | (267 | ) | (254 | ) | |||||
Non-recourse debt |
(34 | ) | (29 | ) | (25 | ) | |||||
|
$ | (263 | ) | $ | (296 | ) | $ | (279 | ) | ||
Interest income decreased primarily due to lower interest rates and, to a lesser extent, lower average cash balances.
EME's interest expense decreased $33 million in 2010 from 2009 and increased $17 million in 2009 from 2008. The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities, partially offset by higher wind project financing. The 2009 increase was primarily due to higher debt balances under EME's credit facility in 2009, compared to 2008, and EME's wind financing in June 2009. Capitalized interest was $54 million, $19 million and $32 million in 2010, 2009 and 2008, respectively. The 2010 increase was the result of increased interest capitalization for renewable energy projects under construction.
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
54
years 1986 through 2002. In addition, income taxes in 2010, 2009 and 2008 included tax benefits of production tax credits of $62 million, $56 million and $44 million, respectively.
EME's effective tax rates were 11%, 7% and 33%, respectively, for the years ended December 31, 2010, 2009 and 2008. The effective tax rate for 2010 was impacted by the recapture of qualified production deductions realized in prior years resulting from a carryback of net operating losses to 2008. The effective tax rate for 2009 was impacted by lower pretax income in relation to the level of production tax credits and estimated state income tax benefits allocated from Edison International. Estimated state income tax benefits allocated from Edison International of $7 million, $15 million and $5 million were recognized for the years ended December 31, 2010, 2009 and 2008, respectively.
For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 7. Income Taxes."
Results of Discontinued Operations
The 2010 results of discontinued operations included foreign exchange gains and interest expense on contract indemnities denominated in euros, adjustments to unrecognized tax benefits, and expiration in 2010 of another contract indemnity. The contract indemnities relate to the sale of EME's international projects in December 2004. Results in 2009 and 2008 included foreign exchange gains (losses), change in estimates, and interest expense also associated with these contract indemnities.
EME owns interests in partnerships that sell electricity generated by their project facilities to SCE and others under the terms of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $367 million, $366 million and $686 million in 2010, 2009 and 2008, respectively. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 15. Related-Party Transactions."
For a discussion of new accounting guidance affecting EME, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 1. Summary of Significant Accounting PoliciesNew Accounting Guidance."
55
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes available liquidity at December 31, 2010:
(in millions) |
Cash and Cash Equivalents |
Available Under Credit Facilities |
Total Available Liquidity |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
EME as a holding company |
$ | 427 | $ | 484 | $ | 911 | |||||
EME subsidiaries without contractual dividend restrictions |
188 | | 188 | ||||||||
EME corporate cash and cash equivalents |
615 | 484 | 1,099 | ||||||||
EME subsidiaries with contractual dividend restrictions |
|||||||||||
Midwest Generation1 |
295 | 497 | 792 | ||||||||
Homer City |
132 | | 132 | ||||||||
Other EME subsidiaries |
33 | | 33 | ||||||||
Total |
$ | 1,075 | $ | 981 | $ | 2,056 | |||||
Because EME, as a holding company, does not directly own any revenue-producing generation facilities, EME relies on cash distributions and tax payments from its projects to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, see "Dividend Restrictions in Major Financings."
The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2010, which mature in June 2012:
(in millions) |
EME |
Midwest Generation |
|||||
---|---|---|---|---|---|---|---|
Commitments |
$ | 564 | $ | 500 | |||
Outstanding borrowings |
| | |||||
Outstanding letters of credit |
(80 | ) | (3 | ) | |||
Amount available |
$ | 484 | $ | 497 | |||
EME and Midwest Generation may seek to extend or replace credit facilities or retire them by other means. The terms and conditions of any refinancing could be substantially different than those in the current credit facilities. Senior notes in the principal amount of $500 million, which were issued in 2006 and which bear interest at 7.50% per annum, are due in June 2013. EME may also from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.
For additional discussion of liquidity, see "Management's OverviewEME's Liquidity."
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Bonus Depreciation Impact on EME
The Small Business Jobs Act of 2010 and the 2010 Tax Relief Act extended 50% bonus depreciation for qualifying property through 2012 and created a new 100% bonus depreciation for qualifying property placed in service between September 9, 2010 and December 31, 2011. These provisions are expected to result in a consolidated Edison International net operating loss for federal income tax purposes for 2011, and delay tax-allocation payments to EME until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years, In addition, EME expects to make tax-allocation payments in 2012 as a result of reallocation of tax obligations from the expected Edison International consolidated net operating loss during 2011.
The negative impact on 2010 net income was $15 million from recapture of 2008 Section 199 deductions realized in prior years resulting from the carryback of net operating losses.
At December 31, 2010, forecasted capital expenditures through 2013 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:
(in millions) |
2011 |
2012 |
2013 |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Midwest Generation Plants |
|||||||||||
Plant capital expenditures |
$ | 34 | $ | 23 | $ | 29 | |||||
Environmental expenditures |
151 | 132 | 198 | ||||||||
Homer City Plant |
|||||||||||
Plant capital expenditures |
18 | 25 | 16 | ||||||||
Environmental expenditures |
| | | ||||||||
Renewable Energy Projects |
|||||||||||
Capital and construction expenditures |
189 | | | ||||||||
Turbine commitments |
90 | | | ||||||||
Other capital expenditures |
21 | 19 | 17 | ||||||||
Total |
$ | 503 | $ | 199 | $ | 260 | |||||
Environmental Capital Expenditures
Midwest Generation plants' environmental expenditures include $109 million for expenditures in 2011 related to SNCR equipment and $372 million for expenditures in 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to
57
continue or complete the project. For additional discussion, see "Management's OverviewEnvironmental DevelopmentsMidwest Generation Compliance Plans and Costs."
The capital investment plan set forth in the previous table does not include environmental capital expenditures for Homer City. However, depending on upcoming and future regulatory developments, Homer City may be required to undertake capital projects to install additional pollution control equipment, which will be dependent on lessor decisions regarding the funding of these expenditures. For a discussion of environmental regulations, see "Management's OverviewEnvironmental DevelopmentsHomer City Environmental Issues and Capital Resource Limitations."
Non-Environmental Capital Expenditures
Plant capital expenditures in the preceding table relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, condenser re-tubing, development of a coal-cleaning plant refuse site and a new ash disposal site, and main power transformer replacement.
Renewable energy projects' capital and construction expenditures include a project of an unconsolidated entity in which construction expenditures will be substantially funded by EME. Construction project financing of $48 million was available as of December 31, 2010. In addition, U.S. Treasury grants of $346 million are anticipated based on estimated eligible construction costs for renewable projects completed in 2010 and scheduled to be completed in 2011.
At December 31, 2010, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Future development of the wind portfolio is dependent on the availability of third-party capital. To the extent that third-party capital is available, the success of development efforts will depend upon, among other things, obtaining permits and agreements necessary to support an investment. This process may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.
For additional information regarding capital expenditures for turbines and the Walnut Creek project, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and ContingenciesOther Commitments" and "Note 15. Related-Party Transactions."
EME's Historical Consolidated Cash Flow
This section discusses EME's consolidated cash flows from operating, financing and investing activities.
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Condensed Consolidated Statement of Cash Flows
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Operating cash flow from continuing operations |
$ | 602 | $ | 258 | $ | 728 | ||||
Operating cash flow from discontinued operations |
4 | (7 | ) | 1 | ||||||
Net cash provided by operating activities |
606 | 251 | 729 | |||||||
Net cash provided by (used in) financing activities |
425 | (714 | ) | 844 | ||||||
Net cash used in investing activities |
(752 | ) | (548 | ) | (760 | ) | ||||
Net increase (decrease) in cash and cash equivalents |
$ | 279 | $ | (1,011 | ) | $ | 813 | |||
Consolidated Cash Flows from Operating Activities
The 2010 increase as compared to 2009 in cash provided by operating activities from continuing operations was primarily attributable to higher realized revenues from derivative contracts and payments on U.S. Treasury grants.
The 2009 decrease as compared to 2008 in cash provided by operating activities from continuing operations was primarily attributable to lower realized revenues due to lower market prices in 2009, compared to 2008 and a decrease in margin deposits received from counterparties at December 31, 2009.
Consolidated Cash Flows from Financing Activities
The 2010 increase as compared to 2009 in cash used in financing activities from continuing operations was attributable to project-level financing of renewable energy projects and repayment of credit facilities in 2009.
The 2009 increase as compared to 2008 in cash used in financing activities from continuing operations was attributable to repayments of $376 million and $475 million under EME's corporate credit facility and Midwest Generation's working capital facility, respectively. These repayments were partially offset by proceeds received from the issuance of a $189 million term loan as part of a $202 million project financing completed in June 2009.
Consolidated Cash Flows from Investing Activities
The 2010 increase as compared to 2009 in cash used in investing activities was primarily attributable to the construction of wind projects. Cash flows related to short-term investments decreased in 2009 compared to 2008 as EME curtailed its purchase of short-term investments.
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Credit ratings for EME, Midwest Generation and EMMT as of December 31, 2010 were as follows:
|
Moody's Rating |
S&P Rating |
Fitch Rating |
||||
---|---|---|---|---|---|---|---|
EME1 |
B3 | B- | B- | ||||
Midwest Generation2 |
Ba2 | B+ | BB | ||||
EMMT |
Not Rated | B- | Not Rated | ||||
All the above ratings are on negative outlook. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
EME does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party.
The Homer City sale-leaseback documents restrict Homer City's ability to enter into derivative activities with EMMT to sell forward the output of the Homer City plant if EMMT does not have an investment grade credit rating from S&P or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents also include a requirement that Homer City's counterparty to such transactions, whether it is EMMT or another party, and Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City plant through EMMT, which has a below investment grade credit rating, and Homer City is not rated. In order to continue to sell forward the output of the Homer City plant through EMMT, EME has obtained a consent from the sale-leaseback owner participants that allows Homer City to enter into such sales, under specified conditions, through March 1, 2014. Homer City continues to be in compliance with the terms of the consent; however, because EMMT's credit rating has dropped below BB-, the consent is revocable by the sale-leaseback owner participants at any time. The sale-leaseback owner participants have not indicated that they intend to revoke the consent; however, there can be no assurance that they will not do so in the future. An additional consequence of EMMT's
60
lowered credit rating is a requirement for EMMT to prepay for Homer City's output to satisfy a requirement under the terms of the consent that outstanding accounts receivable between EMMT and Homer City be reduced to zero. Revocation of the consent would not affect trades between EMMT and Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City plant into the spot market on the terms set forth in the Homer City sale-leaseback documents.
Margin, Collateral Deposits and Other Credit Support for Energy Contracts
To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. At December 31, 2010, EMMT had deposited $43 million in cash with clearing brokers in support of futures contracts and had deposited $16 million in cash with counterparties in support of forward energy and congestion contracts. Cash collateral provided to others offset against derivative liabilities totaled $4 million at December 31, 2010. In addition, EME had received cash collateral of $52 million at December 31, 2010 to support credit risk of counterparties under margin agreements. The liability for margin deposits received from counterparties has been offset against net derivative assets.
Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of December 31, 2010 could increase by approximately $89 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "EME's Liquidity as a Holding Company" and "Dividend Restrictions in Major Financings."
EME's Liquidity as a Holding Company
Intercompany Tax-Allocation Agreement
EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures
61
regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME received net tax-allocation payments of $116 million and $166 million in 2010 and 2009, respectively, and made net tax-allocation payments to Edison International of $95 million in 2008. EME expects to receive tax-allocation payments in 2011 as a result of the carryback of Edison International consolidated net operating losses for 2010 and subsequently make tax-allocation payments in 2012 as a result of the reallocation of tax obligations from an expected Edison International consolidated net operating loss during 2011. For further information, see "Available LiquidityBonus Depreciation Impact on EME."
EME's Credit Facility Financial Ratios
EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility. The following details of EME's interest coverage ratio and a maximum corporate-debt-to-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements. As of December 31, 2010, EME and its subsidiaries are in compliance with the terms of their debt covenants.
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The following table sets forth the major components of the interest coverage ratio:
|
Years Ended December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||||
Funds Flow Available for Interest |
|||||||||
Distributions |
|||||||||
Midwest Generation |
$ | 125 | $ | 200 | |||||
Homer City |
74 | 75 | |||||||
Big 4 Projects |
77 | 62 | |||||||
U.S. Treasury grants |
92 | | |||||||
Renewable energy projects1 |
223 | 208 | |||||||
Other projects |
63 | 47 | |||||||
Tax payments received from subsidiaries |
136 | 68 | |||||||
Realized trading income |
120 | 36 | |||||||
Tax allocation receipts (payments)2 |
90 | 139 | |||||||
Operating expenses |
(139 | ) | (151 | ) | |||||
Other items, net |
(56 | ) | (14 | ) | |||||
|
$ | 805 | $ | 670 | |||||
Net Interest Expense |
|||||||||
EME corporate debt |
$ | 223 | $ | 261 | |||||
Addback: Capitalized interest |
54 | 19 | |||||||
Powerton-Joliet intercompany notes |
112 | 112 | |||||||
EME interest income |
| (2 | ) | ||||||
|
$ | 389 | $ | 390 | |||||
Ratio |
2.07 | 1.72 | |||||||
Covenant threshold (not less than) |
1.20 | 1.20 | |||||||
The Small Business Jobs Act of 2010 and the 2010 Tax Relief Act provisions are expected to result in a consolidated net operating loss for federal income tax purposes for 2011 and delay tax-allocation payments to EME until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years.
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The following table sets forth the major components of the corporate-debt-to-capital ratio:
|
December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||||
Corporate Debt |
|||||||||
Indebtedness for money borrowed |
$ | 3,700 | $ | 3,700 | |||||
Powerton-Joliet termination value |
933 | 1,046 | |||||||
Letters of credit |
83 | 104 | |||||||
|
$ | 4,716 | $ | 4,850 | |||||
Corporate Capital |
|||||||||
Common shareholder's equity |
$ | 2,842 | $ | 2,761 | |||||
Less: |
|||||||||
Non-cash cumulative changes in accounting |
(9 | ) | 1 | ||||||
Accumulated other comprehensive income |
31 | (78 | ) | ||||||
Adjustments: |
|||||||||
After-tax losses incurred on termination of Collins lease |
587 | 587 | |||||||
Dividend to Mission Energy Holding Company for repayment of 13.5% notes |
899 | 899 | |||||||
|
4,350 | 4,170 | |||||||
Corporate debt |
4,716 | 4,850 | |||||||
|
$ | 9,066 | $ | 9,020 | |||||
Corporate-debt-to-capital ratio |
0.52 | 0.54 | |||||||
Covenant threshold (not more than) |
0.75 | 0.75 | |||||||
Dividend Restrictions in Major Financings
Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.
Key Ratios of EME's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at December 31, 2010 or for the 12 months ended December 31, 2010:
Subsidiary |
Financial Ratio |
Covenant |
Actual |
|||||
---|---|---|---|---|---|---|---|---|
Midwest Generation (Midwest Generation plants) |
Debt to Capitalization Ratio | Less than or equal to 0.60 to 1 | 0.15 to 1 | |||||
Homer City (Homer City plant) |
Senior Rent Service Coverage Ratio | Greater than 1.7 to 1 | 2.51 to 1 | |||||
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Midwest Generation Financing Restrictions on Distributions
Midwest Generation is bound by the covenants in its credit agreement and certain covenants under the Powerton-Joliet lease documents with respect to Midwest Generation making payments under the leases. These covenants include restrictions on the ability to, among other things, incur debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines of business, enter into swap agreements, or engage in transactions for any speculative purpose. In order for Midwest Generation to make a distribution, it must be in compliance with the covenants specified under its credit agreement, including maintaining a debt to capitalization ratio of no greater than 0.60 to 1.
Homer City Sale-Leaseback Restrictions on Distributions
Homer City completed a sale-leaseback of the Homer City plant in December 2001. In order to make a distribution, Homer City must be in compliance with the covenants specified in the lease agreements, including the following financial performance requirements measured on the date of distribution.
At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid and the senior rent service coverage ratio for the prior 12-month period (taken as a whole and projected for each of the prospective two 12-month periods) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of Homer City less amounts paid for operating expenses, capital expenditures funded by Homer City, taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service reserve letter of credit. No more than two rent default events may have occurred, whether or not cured. A rent default event is defined as the failure to pay the equity portion of the rent within five business days of when it is due. EME has not guaranteed Homer City's obligations under the leases.
EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries
EME's corporate credit agreement contains covenants that restrict its ability and the ability of several of its subsidiaries to make distributions. This restriction impacts the EME subsidiaries that own interests in the Westside projects, the Sunrise project, the coal plants, and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME's shareholder if an event of default were to occur and be continuing under EME's secured credit agreement after giving effect to the distribution.
EME's Senior Notes and Guaranty of Powerton-Joliet Leases
EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter
65
preceding the sale or disposition in question. At December 31, 2010, the maximum permissible sale or disposition of EME assets is calculated as follows:
(in millions) |
|
|||||
---|---|---|---|---|---|---|
Consolidated Net Tangible Assets |
||||||
Total consolidated assets |
$ | 9,321 | ||||
Less: |
||||||
Consolidated current liabilities |
524 | |||||
Intangible assets |
78 | |||||
|
$ | 8,719 | ||||
10% Threshold |
$ | 872 | ||||
This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.
As a wholly owned indirect subsidiary of Edison International, EME is subject to determinations made by its directors, each of whom is appointed by Edison International, to act in the interests of Edison International and its shareholders, which may result in EME making distributions of cash or assets, subject to the limitations described above and applicable law, at any time or from time to time, which may affect EME's assets held or under development.
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Contractual Obligations, Commercial Commitments and Contingencies
EME has contractual obligations and other commercial commitments that represent prospective cash requirements. The following table summarizes EME's significant consolidated contractual obligations as of December 31, 2010.
|
|
Payments Due by Period | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Total |
Less than 1 year |
1 to 3 years |
3 to 5 years |
More than 5 years |
||||||||||||
Long-term debt1 |
$ | 6,711 | $ | 340 | $ | 1,180 | $ | 842 | $ | 4,349 | |||||||
Power plant and other operating lease obligations2 |
3,166 | 339 | 664 | 496 | 1,667 | ||||||||||||
Purchase obligations3: |
|||||||||||||||||
Fuel supply contracts |
765 | 482 | 283 | | | ||||||||||||
Coal transportation agreements |
231 | 231 | | | | ||||||||||||
Gas transportation agreements |
60 | 8 | 16 | 17 | 19 | ||||||||||||
Capital expenditures |
182 | 182 | | | | ||||||||||||
Turbine commitments |
90 | 90 | | | | ||||||||||||
Other contractual obligations |
198 | 85 | 103 | 8 | 2 | ||||||||||||
Employee benefit plan contribution4 |
22 | 22 | | | | ||||||||||||
Total Contractual Obligations5,6 |
$ | 11,425 | $ | 1,779 | $ | 2,246 | $ | 1,363 | $ | 6,037 | |||||||
As of December 31, 2010, standby letters of credit under EME and its subsidiaries' credit facilities aggregated $116 million and were scheduled to expire as follows: $95 million in 2011,
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$11 million in 2012, and $10 million in 2017. Certain letters of credit are subject to automatic annual renewal provisions.
EME's significant contingencies related to the Midwest Generation NSR lawsuit and Homer City NSR Lawsuit are discussed in "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and Contingencies."
Off-Balance Sheet Transactions
EME has off-balance sheet transactions in two principal areas: investments in projects accounted for under the equity method and operating leases resulting from sale-leaseback transactions.
Investments Accounted for under the Equity Method
EME has a number of investments in power projects that are accounted for under the equity method. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 3. Variable Interest Entities."
EME has entered into sale-leaseback transactions related to the Powerton Station and Units 7 and 8 of the Joliet Station in Illinois and the Homer City plant in Pennsylvania. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and ContingenciesPower Plant and Other Lease Commitments."
EME's subsidiaries record depreciation expense from the power plants and interest expense from the lease financing in lieu of an operating lease expense which EME uses in preparing its consolidated financial statements. The treatment of these leases as operating leases on its consolidated financial statements in lieu of lease financings, which are recorded by EME's subsidiaries, resulted in an increase in consolidated net income of $36 million, $35 million and $46 million in 2010, 2009 and 2008, respectively.
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The lessor equity and lessor debt associated with the sale-leaseback transactions for the Powerton, Joliet and Homer City assets are summarized in the following table:
Power Station(s) |
Acquisition Price (in millions) |
Equity Investor |
Original Equity Investment in Owner-Lessor (in millions) |
Amount of Lessor Debt at December 31, 2010 (in millions) |
Maturity Date of Lessor Debt |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Powerton/Joliet |
$ | 1,367 | PSEG/Citigroup, Inc. | $ | 238 | $ | 565 Series B | 2016 | ||||||||
Homer City |
$ |
1,591 |
GECC/Metropolitan Life |
$ |
798 |
$ |
201 Series A |
2019 |
||||||||
|
Insurance Company | $ | 495 Series B | 2026 | ||||||||||||
The operating lease payments to be made by each of EME's subsidiary lessees are structured to service the lessor debt and provide a return to the owner-lessor's equity investors. Neither the value of the leased assets nor the lessor debt is reflected on EME's consolidated balance sheet. In accordance with GAAP, EME records rent expense on a levelized basis over the terms of the respective leases. The following table summarizes the lease payments and rent expense.
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Cash payments under plant operating leases |
|||||||||||
Powerton and Joliet facilities |
$ | 170 | $ | 185 | $ | 185 | |||||
Homer City plant |
155 | 151 | 152 | ||||||||
Total cash payments under plant operating leases |
$ | 325 | $ | 336 | $ | 337 | |||||
Rent expense |
|||||||||||
Powerton and Joliet facilities |
$ | 75 | $ | 75 | $ | 75 | |||||
Homer City plant |
103 | 102 | 102 | ||||||||
Total rent expense |
$ | 178 | $ | 177 | $ | 177 | |||||
To the extent that EME's cash rent payments exceed the amount levelized over the term of each lease, EME records prepaid rent. At December 31, 2010 and 2009, aggregate prepaid rent on these leases was $1,187 million and $1,038 million, respectively. To the extent that EME's cash rent payments are less than the amount levelized, EME reduces the amount of prepaid rent.
In the event of a default under the leases, each lessor can exercise all its rights under the applicable lease, including repossessing the power plant and seeking monetary damages. Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which generally declines over time and in the case of default may be reduced by the proceeds arising from the sale of the repossessed power plant. A default under the terms of the Powerton and Joliet or Homer City leases could result in a loss of EME's ability to use such power plant. In addition, a default under the terms of the Powerton and Joliet
69
leases would trigger obligations under EME's guarantee of such leases. These events could have a material adverse effect on EME's results of operations and financial position.
EME's Obligations to Midwest Generation
Proceeds, in the aggregate amount of approximately $1.4 billion, were received by Midwest Generation from the sale of the Powerton and Joliet plants, described above under "Sale-Leaseback Transactions." These proceeds were loaned to EME and used by EME to repay corporate indebtedness. Although interest and principal payments made by EME to Midwest Generation under the intercompany loan assist in the payment of the lease rental payments owed by Midwest Generation, the intercompany obligation does not appear on EME's consolidated balance sheet. The following table summarizes principal payments due under this intercompany loan:
Years Ending December 31, (in millions) |
Principal Amount |
Interest Amount |
Total |
|||||||
---|---|---|---|---|---|---|---|---|---|---|
2011 |
$ | 9 | $ | 111 | $ | 120 | ||||
2012 |
11 | 110 | 121 | |||||||
2013 |
12 | 109 | 121 | |||||||
2014 |
544 | 86 | 630 | |||||||
2015 |
284 | 40 | 324 | |||||||
Thereafter |
483 | | 483 | |||||||
Total |
$ | 1,343 | $ | 456 | $ | 1,799 | ||||
EME funds the interest and principal payments due under the intercompany loan from distributions from EME's subsidiaries, including Midwest Generation, and cash on hand. A default by EME in the payment of this intercompany loan could result in a shortfall of cash available for Midwest Generation to meet its lease and debt obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME.
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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.
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.
EME classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Midwest Generation plants |
|||||||||||
Non-qualifying hedges |
$ | (11 | ) | $ | 40 | $ | (16 | ) | |||
Ineffective portion of cash flow hedges |
(2 | ) | 5 | 10 | |||||||
Homer City plant |
|||||||||||
Non-qualifying hedges |
(1 | ) | 1 | 1 | |||||||
Ineffective portion of cash flow hedges |
(19 | ) | 14 | 20 | |||||||
Total unrealized gains (losses) |
$ | (33 | ) | $ | 60 | $ | 15 | ||||
At December 31, 2010, cumulative unrealized gains of $4 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to 2011.
In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of
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EME's derivative instruments, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 4. Fair Value Measurements" and "Note 6. Derivative Instruments and Hedging Activities," respectively.
The fair value of derivatives used for non-trading purposes at December 31, 2010 was $46 million. A 10% change in the market price of the underlying commodity at December 31, 2010 would increase or decrease the fair value of outstanding non-trading commodity derivative instruments by approximately $58 million.
The fair value of derivatives used for trading purposes at December 31, 2010 was $110 million. A 10% change in the market price of the underlying commodity at December 31, 2010 would increase or decrease the fair value of trading contracts by approximately $26 million. The impact of changes to the various inputs used to determine the fair value of Level 3 derivatives would not be anticipated to be material to EME's results of operations as such changes would be offset by similar changes in derivatives classified within Level 3 as well as other levels. Level 3 assets and liabilities are 58% and 34%, respectively, of assets and liabilities measured at fair value before the impact of offsetting collateral and netting as of December 31, 2010.
EME's merchant operations create exposure to commodity price risk, which reflects the potential impact of a change in the market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided by a risk management committee, to ensure compliance with EME's risk management policies. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.
Energy Price Risk Affecting Sales from the Coal Plants
Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub, and to a lesser extent, the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant.
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The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated:
|
24-Hour Average Historical Market Prices1 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
||||||||
Midwest Generation plants |
|||||||||||
Northern Illinois Hub |
$ | 33.08 | $ | 28.86 | $ | 49.01 | |||||
Homer City plant |
|||||||||||
PJM West Hub |
$ | 45.88 | $ | 38.31 | $ | 68.56 | |||||
Homer City Busbar |
39.35 | 34.91 | 57.72 | ||||||||
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at December 31, 2010:
|
24-Hour Forward Energy Prices1 | ||||||
---|---|---|---|---|---|---|---|
|
Northern Illinois Hub |
PJM West Hub |
|||||
2011 calendar "strip"2 |
$ | 30.68 | $ | 45.45 | |||
2012 calendar "strip"2 |
$ | 32.37 | $ | 46.41 | |||
Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the coal plants into these markets may vary materially from the forward market prices set forth in the preceding table.
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EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) as of December 31, 2010 for electricity expected to be generated in 2011 and 2012:
|
2011 | 2012 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
MWh (in thousands) |
Average price/ MWh1 |
MWh (in thousands) |
Average price/ MWh1 |
||||||||||
Midwest Generation plants |
||||||||||||||
Northern Illinois and AEP/Dayton Hubs |
10,870 | $ | 37.75 | 3,358 | $ | 38.11 | ||||||||
Homer City plant2,3 |
||||||||||||||
PJM West Hub |
2,540 | 55.36 | 1,370 | 51.68 | ||||||||||
Total |
13,410 | 4,728 | ||||||||||||
Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for capacity resources. The RPM is intended to provide a mechanism for PJM to meet the region's need for generation capacity, while allocating the cost to load-serving entities through a locational reliability charge.
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The following table summarizes the status of capacity sales for Midwest Generation and Homer City at December 31, 2010:
|
|
|
|
RPM Capacity Sold in Base Residual Auction |
Other Capacity Sales, Net of Purchases3 |
|
||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Installed Capacity MW |
Unsold Capacity1 MW |
Capacity Sold2 MW |
MW |
Price per MW-day |
MW |
Average Price per MW-day |
Aggregate Average Price per MW-day |
||||||||||||||||||
January 1, 2011 to May 31, 2011 |
||||||||||||||||||||||||||
Midwest Generation |
5,477 | (548 | ) | 4,929 | 4,929 | $ | 174.29 | | | $ | 174.29 | |||||||||||||||
Homer City |
1,884 | (261 | ) | 1,623 | 1,813 | 174.29 | (190 | ) | $ | 53.95 | 188.38 | |||||||||||||||
June 1, 2011 to May 31, 2012 |
||||||||||||||||||||||||||
Midwest Generation |
5,477 | (495 | ) | 4,982 | 4,582 | 110.00 | 400 | 85.00 | 107.99 | |||||||||||||||||
Homer City |
1,884 | (113 | ) | 1,771 | 1,771 | 110.00 | | | 110.00 | |||||||||||||||||
June 1, 2012 to May 31, 2013 |
||||||||||||||||||||||||||
Midwest Generation |
5,477 | (773 | ) | 4,704 | 4,704 | 16.46 | | | 16.46 | |||||||||||||||||
Homer City |
1,884 | (232 | ) | 1,652 | 1,736 | 133.37 | (84 | ) | 16.46 | 139.31 | ||||||||||||||||
June 1, 2013 to May 31, 2014 |
||||||||||||||||||||||||||
Midwest Generation |
5,477 | (827 | ) | 4,650 | 4,650 | 27.73 | | | 27.73 | |||||||||||||||||
Homer City |
1,884 | (104 | ) | 1,780 | 1,780 | 226.15 | | | 221.03 | 4 | ||||||||||||||||
The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.
Revenues from the sale of capacity from Midwest Generation and Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM's RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, demand side management activities and the cost of new entry.
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Sales made from the coal plants in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City plant and for settlement points at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Midwest Generation plants. EME's hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as "basis risk." During 2010, transmission congestion in PJM resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 14%, compared to 9% during 2009 and 16% during 2008. During 2010, transmission congestion in PJM resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 13% and 1%, respectively, compared to 14% and 1%, respectively, during 2009.
By entering into cash settled futures contracts and forward contracts using the PJM West Hub, the Northern Illinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for Homer City and Midwest Generation. A financial transmission right is a financial instrument that entitles the holder to receive the difference between actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME's hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.
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Coal and Transportation Price Risk
The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at December 31, 2010 for the following three years:
|
Amount of Coal Under Contract in Millions of Equivalent Tons1 |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
2011 |
2012 |
2013 |
|||||||
Midwest Generation plants2 |
15.9 | 9.8 | | |||||||
Homer City plant |
4.6 | 1.8 | 0.5 | |||||||
EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City plant, increased during 2010 from 2009 and decreased during 2009 from 2008. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to a price of $70 per ton at December 31, 2010, compared to a price of $52.50 per ton at December 31, 2009, as reported by the EIA. In 2010, the price of NAPP coal ranged from $54 per ton to $71 per ton, as reported by the EIA. The 2010 increase in NAPP coal prices was primarily driven by the export market demand and global coal pricing.
Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Midwest Generation plants increased during 2010 from 2009 year-end prices and declined during 2009 from 2008 year-end prices. The price of PRB coal fluctuated between $9.80 per ton and $15.35 per ton during 2010, with a price of $13.60 per ton at December 31, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the EIA. The 2010 increase in PRB coal prices was due to the draw down of inventory levels and flat to slight declines of PRB coal production.
EME has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through 2011. EME is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.
Based on EME's anticipated coal requirements in 2011 in excess of the amount under contract, EME expects that a 10% change in the price of coal at December 31, 2010 would increase or decrease pre-tax income in 2011 by approximately $6 million.
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Emission Allowances Price Risk
The federal Acid Rain Program requires electric generating stations to hold SO2 allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, the coal plants are required to hold seasonal and annual NOx allowances.
In the event that actual emissions required are greater than allowances held, EME is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO2 allowances was $50 per ton in 2010, $65 per ton in 2009 and $315 per ton in 2008. The average purchase price of annual NOx allowances was $936 per ton in 2010 and $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO2 allowances and annual NOx allowances was $9 per ton and $320 per ton, respectively, at December 31, 2010.
Based on EME's anticipated SO2 requirements and annual and seasonal NOx requirements for 2011 beyond those allowances already purchased, EME expects that a 10% change in the price of SO2 emission allowances and annual and seasonal NOx emission allowances at December 31, 2010 would increase or decrease pre-tax income in 2011 by approximately $0.5 million.
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 StatementsNote 6. Derivative Instruments and Hedging Activities."
The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At December 31,
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2010, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:
|
December 31, 2010 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Exposure2 |
Collateral |
Net Exposure |
||||||||
Credit Rating1 |
|||||||||||
A or higher |
$ | 141 | $ | (14 | ) | $ | 127 | ||||
A- |
2 | | 2 | ||||||||
BBB+ |
4 | | 4 | ||||||||
BBB |
31 | | 31 | ||||||||
BBB- |
34 | | 34 | ||||||||
Below investment grade |
39 | (38 | ) | 1 | |||||||
Total |
$ | 251 | $ | (52 | ) | $ | 199 | ||||
The credit risk exposure set forth in the above table is comprised of $149 million of net accounts receivable and payables and $102 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $59 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.
The terms of EME's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines, and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EME's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EME's turbine suppliers may have a material impact on EME's wind projects and development efforts.
Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. A 10% change in market interest rates at December 31, 2010 would increase or decrease the fair value of the interest rate swap agreements by approximately $7 million. The fair market values of fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated long-term debt (including current portion) was $3.8 billion at
79
December 31, 2010, compared to the carrying value of $4.5 billion. A 10% increase in market interest rates at December 31, 2010 would result in a decrease in the fair value of total long-term debt by approximately $167 million. A 10% decrease in market interest rates at December 31, 2010 would result in an increase in the fair value of total long-term debt by approximately $182 million.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
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 StatementsNote 1. Summary of Significant Accounting Policies."
EME uses derivative instruments to manage exposure to changes in electricity, fuel oil and interest rates. Derivative instruments that do not meet the normal purchases and sales exception at fair value are recorded with changes in the derivative's fair value recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for cash flow hedge accounting treatment, the effective portion of the changes in the derivative's fair value is recognized in other comprehensive income until the hedged item is recognized in earnings. EME records derivative instruments used for trading at fair value with changes in fair value recognized in income.
Management's judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management's judgment is also required to determine the fair value of derivative transactions.
Key Assumptions and Approach Used. EME determines the fair value of derivative instruments based on forward market prices in active markets adjusted for nonperformance risk. If quoted market prices are not available, internally developed models are used to determine the fair value. When actual market prices, or relevant observable inputs are not available, it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid and non-liquid trading hubs. In assessing nonperformance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit
80
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 StatementsNote 4. Fair Value Measurements."
Effect if Different Assumptions Used. As described above, fair value is determined using a combination of market information or observable data and unobservable inputs which reflect management's assumptions. Changes in observable data would impact results. In addition, unobservable inputs could have an impact on results. Fair value for Level 3 derivatives is derived using observable and unobservable inputs. As of December 31, 2010, Level 3 derivatives had a net fair value of $91 million. While it is difficult to determine the impact of a change in any one input, if the fair value of Level 3 derivatives were increased or decreased by 10%, the impact would be a $10 million increase or decrease to operating revenues.
For EME's derivative instruments that are measured at fair value using quantitative pricing models, a significant change in estimate could affect EME's results of operations. For further sensitivities in EME's assumptions used to calculate fair value, see "Market Risk ExposuresDerivative InstrumentsFair Value Disclosures." For further information on derivative instruments, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 6. Derivative Instruments and Hedging Activities."
Impairment of Long-Lived Assets
Nature of Estimates Required. Long-lived assets, including intangible assets, are evaluated for impairment in accordance with applicable authoritative guidance. Authoritative guidance requires that if the undiscounted expected future cash flow from a company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be recognized on the financial statements. The impairment charges, if applicable, are calculated as the excess of the asset's carrying value over its fair value, which represents the discounted expected future cash flows attributable to the asset or, in the case of assets expected to be sold, at fair value less costs to sell. Long-lived assets for impairment are evaluated whenever indicators of impairment exist or when there is a commitment to sell or dispose of the asset. These evaluations may result from significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as economic or operational analyses.
Key Assumptions and Approach Used. The assessment of impairment requires significant management judgment to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. Factors that are considered important, which could trigger an impairment, include operating losses from a project, projected future operating losses, the financial condition of counterparties, or significant negative industry or economic trends. The determination of fair value requires management to apply judgment
81
in: (1) estimating future prices of energy and capacity in wholesale energy markets and fuel prices that are susceptible to significant change, (2) environmental and maintenance expenditures, and (3) the time period due to the length of the estimated remaining useful lives.
Effect if Different Assumptions Used. The estimates and assumptions used to determine whether an impairment exists are subject to a high degree of uncertainty. The estimated fair value of an asset would change materially if different estimates and assumptions were used to determine the amounts or timing of future revenues, environmental compliance costs or operating expenditures.
Application to Merchant Coal-Fired Power Plants
Weak commodity prices combined with continuing, heightened public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants, which may require significant capital and increased operating costs to meet environmental requirements. For a discussion of environmental requirements, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Environmental Developments" Management has reviewed long-term cash flow forecasts that include assumptions about future electricity and fuel prices, future capacity payments under the PJM RPM, and future capital expenditure requirements under different scenarios. Assumptions included in the long-term cash flow forecasts include:
If electricity and capacity prices do not increase consistent with the fundamental forecast or if EME decides not to install additional environmental control equipment and, instead, shuts down one or more coal-fired power plants, the forecasted cash flow would be less than expected and impairment may result.
EME includes allocated acquired emission allowances as part of each power plant asset group. In the case of the Powerton and Joliet Stations, EME also includes prepaid rent in the respective asset group. EME's unit of account is at the plant level and, accordingly, the closure of a unit at a multi-unit site would not result in an impairment of property, plant and equipment unless such condition were to affect an impairment assessment on the entire plant.
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The following table summarizes the net book value of the merchant coal-fired asset groups at December 31, 2010:
(in millions) |
|
||||
---|---|---|---|---|---|
Midwest Generation plants |
|||||
Crawford Station |
$ | 178 | |||
Fisk Station |
124 | ||||
Joliet Station |
683 | ||||
Powerton Station |
721 | ||||
Waukegan Station |
365 | ||||
Will County Station |
537 | ||||
Homer City plant |
$ |
978 |
|||
Accounting for Contingencies, Guarantees and Indemnities
Nature of Estimates Required. EME records loss contingencies when it determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. When a guarantee or indemnification subject to authoritative guidance is entered into, EME records a liability for the estimated fair value of the underlying guarantee or indemnification. Gain contingencies are recognized in the financial statements when they are realized.
Key Assumptions and Approach Used. The determination of a reserve for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, EME may consider the following factors, among others: the nature of the litigation, claim or assessment, available information, opinions or views of legal counsel and other advisors, and the experience gained from similar cases. EME provides disclosures for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred. Some guarantees and indemnifications could have a significant financial impact under certain circumstances, and management also considers the probability of such circumstances occurring when estimating the fair value.
During 2004, EME sold a majority of its international operations. The asset sale agreements contain indemnities from EME to the purchasers, including indemnification for pre-closing environmental liabilities and for pre-closing foreign taxes imposed with respect to operations of the assets prior to the sale. At December 31, 2010, EME had recorded an estimated liability of $42 million (of which $3 million is classified as a current liability) related to these matters.
In addition, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation Company LLC for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in a supplemental agreement. The estimated liability is based on studies that estimate future losses
83
based on claims experience and other available information. In calculating future losses, various assumptions were made, including, but not limited to, the settlement of future claims under the supplemental agreement, the distribution of exposure sites and that the filing date of asbestos claims will not be after 2044. At December 31, 2010, Midwest Generation had recorded a liability of $56 million related to this contract indemnity.
Effect if Different Assumptions Used. Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenues and expenses recorded on the consolidated financial statements. In addition, for guarantees and indemnities actual results may differ from the amounts recorded and disclosed and could have a significant impact on EME's consolidated financial statements. For a discussion of contingencies, guarantees and indemnities, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 9. Commitments and ContingenciesGuarantees and Indemnities," "Contingencies" and "Item 1. BusinessEnvironmental Matters and Regulations."
Nature of Estimates Required. As part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes for each jurisdiction in which it operates. This process involves estimating actual current period tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within EME's consolidated balance sheet.
EME takes certain tax positions it believes are applied in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the Internal Revenue Service, state tax authorities and the courts. EME determines its uncertain tax positions in accordance with the authoritative guidance.
Key Assumptions and Approach Used. Accounting for tax obligations requires management judgment. Management uses judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing its uncertain tax positions, EME considers, among others, the following factors: the facts and circumstances of the position, regulations, rulings, and case law, opinions or views of legal counsel and other advisers, and the experience gained from similar tax positions. Management evaluates uncertain tax positions at the end of each reporting period and makes adjustments when warranted based on changes in fact or law.
Effect if Different Assumptions Used. Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenues and expenses recorded in the financial statements. EME continues to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. A tax liability has been recorded with respect to tax positions in which the outcome is uncertain and
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the effect is estimable. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated. For further discussion, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 7. Income Taxes."
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A is filed with this report under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, EME's management concluded that EME's internal control over financial reporting was effective as of December 31, 2010.
Internal Control Over Financial Reporting
There were no changes in EME's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.
None.
86
EDISON MISSION ENERGY AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Edison Mission Energy:
In our opinion, the consolidated financial statements listed in the index appearing under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Edison Mission Energy and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) of the Form 10-K present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 1 and 3 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities and fair value disclosure principles as of January 1, 2010.
/s/
PricewaterhouseCoopers LLP
Los Angeles, California
February 28, 2011
87
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions)
|
Years Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||||
Operating Revenues |
$ | 2,423 | $ | 2,377 | $ | 2,811 | ||||||
Operating Expenses |
||||||||||||
Fuel |
809 | 796 | 747 | |||||||||
Plant operations |
654 | 579 | 621 | |||||||||
Plant operating leases |
178 | 177 | 176 | |||||||||
Depreciation and amortization |
248 | 236 | 194 | |||||||||
Asset write-downs, gain on buyout of contract and loss on termination of contract, net (Notes 1, 2, 9 and 15) |
45 | 4 | 14 | |||||||||
Administrative and general |
182 | 196 | 207 | |||||||||
Total operating expenses |
2,116 | 1,988 | 1,959 | |||||||||
Operating income |
307 | 389 | 852 | |||||||||
Other Income (Expense) |
||||||||||||
Equity in income from unconsolidated affiliates |
104 | 100 | 122 | |||||||||
Dividend income |
19 | 12 | 10 | |||||||||
Interest income |
2 | 7 | 26 | |||||||||
Interest expense, net of capitalized interest |
(263 | ) | (296 | ) | (279 | ) | ||||||
Other income (expense), net |
9 | 5 | 12 | |||||||||
Total other income (expense) |
(129 | ) | (172 | ) | (109 | ) | ||||||
Income from continuing operations before income taxes |
178 | 217 | 743 | |||||||||
Provision for income taxes |
19 | 16 | 243 | |||||||||
Income From Continuing Operations |
159 | 201 | 500 | |||||||||
Income (loss) from Operations of Discontinued Subsidiaries, net of tax (Note 14) |
4 | (7 | ) | 1 | ||||||||
Net Income |
163 | 194 | 501 | |||||||||
Net Loss Attributable to Noncontrolling Interests |
1 | 3 | | |||||||||
Net Income Attributable to Edison Mission Energy Common Shareholder |
$ | 164 | $ | 197 | $ | 501 | ||||||
Amounts Attributable to Edison Mission Energy Common Shareholder |
||||||||||||
Income from continuing operations, net of tax |
$ | 160 | $ | 204 | $ | 500 | ||||||
Income (loss) from discontinued operations, net of tax |
4 | (7 | ) | 1 | ||||||||
Net Income Attributable to Edison Mission Energy Common Shareholder |
$ | 164 | $ | 197 | $ | 501 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
88
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions)
|
December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
|||||||
Assets |
|||||||||
Current Assets |
|||||||||
Cash and cash equivalents |
$ | 1,075 | $ | 796 | |||||
Accounts receivabletrade |
170 | 201 | |||||||
Receivables from affiliates |
192 | 93 | |||||||
Inventory |
236 | 196 | |||||||
Derivative assets |
46 | 197 | |||||||
Restricted cash |
2 | 69 | |||||||
Margin and collateral deposits |
59 | 120 | |||||||
Prepaid expenses and other |
79 | 190 | |||||||
Total current assets |
1,859 | 1,862 | |||||||
Investments in Unconsolidated Affiliates |
557 | 361 | |||||||
Property, Plant and Equipment, net |
5,332 | 4,805 | |||||||
Other Assets |
|||||||||
Deferred financing costs |
54 | 43 | |||||||
Long-term derivative assets |
70 | 81 | |||||||
Restricted deposits |
44 | 40 | |||||||
Rent payments in excess of levelized rent expense under plant operating leases |
1,187 | 1,038 | |||||||
Other long-term assets |
218 | 403 | |||||||
Total other assets |
1,573 | 1,605 | |||||||
Total Assets |
$ | 9,321 | $ | 8,633 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
89
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share amounts)
|
December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
|||||||
Liabilities and Shareholder's Equity |
|||||||||
Current Liabilities |
|||||||||
Accounts payable |
$ | 90 | $ | 97 | |||||
Payables to affiliates |
18 | 14 | |||||||
Accrued liabilities |
201 | 247 | |||||||
Derivative liabilities |
6 | 5 | |||||||
Interest payable |
31 | 30 | |||||||
Deferred taxes |
34 | 119 | |||||||
Current maturities of long-term debt |
48 | 37 | |||||||
Short-term debt |
96 | | |||||||
Total current liabilities |
524 | 549 | |||||||
Long-term debt net of current maturities |
4,342 | 3,929 | |||||||
Deferred taxes and tax credits |
836 | 672 | |||||||
Deferred revenues |
160 | 153 | |||||||
Long-term derivative liabilities |
19 | 15 | |||||||
Other long-term liabilities |
619 | 478 | |||||||
Total Liabilities |
6,500 | 5,796 | |||||||
Commitments and Contingencies (Notes 5, 6, 9 and 10) |
|||||||||
Equity |
|||||||||
Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of December 31, 2010 and 2009 |
64 | 64 | |||||||
Additional paid-in capital |
1,336 | 1,339 | |||||||
Retained earnings |
1,448 | 1,280 | |||||||
Accumulated other comprehensive income (loss) |
(31 | ) | 78 | ||||||
Total Edison Mission Energy common shareholder's equity |
2,817 | 2,761 | |||||||
Noncontrolling Interests |
4 | 76 | |||||||
Total Equity |
2,821 | 2,837 | |||||||
Total Liabilities and Equity |
$ | 9,321 | $ | 8,633 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
90
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF TOTAL EQUITY
(in millions)
|
|
Edison Mission Energy Shareholder's Equity | |
|||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Total Equity |
Common Stock |
Additional Paid-in Capital |
Retained Earnings (Accumulated Deficit) |
Accumulated Other Comprehensive Income (Loss) |
Non- controlling Interests |
||||||||||||||
Balance at December 31, 2007 |
$ | 1,965 | $ | 64 | $ | 1,326 | $ | 596 | $ | (63 | ) | $ | 42 | |||||||
Net income |
501 | | | 501 | | | ||||||||||||||
Other comprehensive income, net of tax |
263 | | | | 263 | | ||||||||||||||
Payments to Edison International for stock purchases related to stock-based compensation |
(12 | ) | | | (12 | ) | | | ||||||||||||
Excess tax benefits related to stock-option exercises |
3 | | 3 | | | | ||||||||||||||
Other stock transactions, net |
6 | | 6 | | | | ||||||||||||||
Sale of membership interest in noncontrolling interests |
28 | | | | | 28 | ||||||||||||||
Cash contributions from noncontrolling interests |
12 | | | | | 12 | ||||||||||||||
Cash distributions to noncontrolling interests |
(2 | ) | | | | | (2 | ) | ||||||||||||
Balance at December 31, 2008 |
2,764 | 64 | 1,335 | 1,085 | 200 | 80 | ||||||||||||||
Net income (loss) |
194 | | | 197 | | (3 | ) | |||||||||||||
Other comprehensive loss, net of tax |
(122 | ) | | | | (122 | ) | | ||||||||||||
Payments to Edison International for stock purchases related to stock-based compensation |
(2 | ) | | | (2 | ) | | | ||||||||||||
Other stock transactions, net |
4 | | 4 | | | | ||||||||||||||
Cash contributions from noncontrolling interests |
2 | | | | | 2 | ||||||||||||||
Cash distributions to noncontrolling interests |
(3 | ) | | | | | (3 | ) | ||||||||||||
Balance at December 31, 2009 |
2,837 | 64 | 1,339 | 1,280 | 78 | 76 | ||||||||||||||
Impact of consolidation and deconsolidation of variable interest entities (Note 1) |
(61 | ) | | | 10 | | (71 | ) | ||||||||||||
Net income (loss) |
163 | | | 164 | | (1 | ) | |||||||||||||
Other comprehensive loss, net of tax |
(109 | ) | | | | (109 | ) | | ||||||||||||
Payments to Edison International for stock purchases related to stock-based compensation |
(6 | ) | | | (6 | ) | | | ||||||||||||
Other stock transactions, net |
7 | | 7 | | | | ||||||||||||||
Purchase of noncontrolling interests |
(10 | ) | | (10 | ) | | | | ||||||||||||
Balance at December 31, 2010 |
$ | 2,821 | $ | 64 | $ | 1,336 | $ | 1,448 | $ | (31 | ) | $ | 4 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
91
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
|
Years Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||||
Net Income |
$ | 163 | $ | 194 | $ | 501 | ||||||
Other comprehensive income (loss), net of tax |
||||||||||||
Pension and postretirement benefits other than pensions: |
||||||||||||
Prior service adjustment, net of tax |
(7 | ) | 1 | 3 | ||||||||
Net gain (loss) adjustment, net of tax expense (benefit) of $(10), $6 and $(26) for 2010, 2009 and 2008, respectively |
(14 | ) | 10 | (41 | ) | |||||||
Amortization of net loss and prior service adjustment included in expense, net of tax |
1 | 2 | 1 | |||||||||
Unrealized gains (losses) on derivatives qualified as cash flow hedges: |
||||||||||||
Unrealized holding gains arising during period, net of income tax expense of $37, $36 and $138 for 2010, 2009 and 2008, respectively |
55 | 43 | 211 | |||||||||
Reclassification adjustments included in net income, net of income tax expense (benefit) of $(96), $(124) and $58 for 2010, 2009 and 2008, respectively |
(144 | ) | (178 | ) | 89 | |||||||
Other comprehensive income (loss), net of tax |
(109 | ) | (122 | ) | 263 | |||||||
Comprehensive Income |
54 | 72 | 764 | |||||||||
Comprehensive Loss Attributable to Noncontrolling Interests |
1 | 3 | | |||||||||
Comprehensive Income Attributable to Edison Mission Energy Common Shareholder |
$ | 55 | $ | 75 | $ | 764 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
92
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
|
Years Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||||
Cash Flows From Operating Activities |
||||||||||||
Net income |
$ | 163 | $ | 194 | $ | 501 | ||||||
(Income) loss from discontinued operations |
(4 | ) | 7 | (1 | ) | |||||||
Income from continuing operations, net |
159 | 201 | 500 | |||||||||
Adjustments to reconcile income to net cash provided by (used in) operating activities: |
||||||||||||
Equity in income from unconsolidated affiliates |
(104 | ) | (100 | ) | (121 | ) | ||||||
Distributions from unconsolidated affiliates |
91 | 76 | 108 | |||||||||
Depreciation and amortization |
260 | 246 | 202 | |||||||||
Deferred taxes and tax credits |
162 | 275 | 104 | |||||||||
Asset write-downs, gain on buyout of contract and loss on termination of contract, net |
45 | 4 | 14 | |||||||||
Changes in operating assets and liabilities: |
||||||||||||
(Increase) decrease in margin and collateral deposits |
61 | (32 | ) | (3 | ) | |||||||
Increase in receivables |
(65 | ) | (35 | ) | (1 | ) | ||||||
Increase in inventory |
(37 | ) | (8 | ) | (40 | ) | ||||||
(Increase) decrease in prepaid expenses and other |
6 | 53 | (9 | ) | ||||||||
(Increase) decrease in restricted cash |
68 | (69 | ) | | ||||||||
Increase in rent payments in excess of levelized rent expense |
(149 | ) | (160 | ) | (162 | ) | ||||||
Decrease in accounts payable and other current liabilities |
(93 | ) | (109 | ) | (7 | ) | ||||||
(Increase) decrease in derivative assets and liabilities |
18 | (168 | ) | 215 | ||||||||
Proceeds from U.S. Treasury grants |
92 | | | |||||||||
(Increase) decrease in other operatingassets |
(9 | ) | 16 | (53 | ) | |||||||
Increase (decrease) in other operatingliabilities |
97 | 68 | (19 | ) | ||||||||
Operating cash flow from continuing operations |
602 | 258 | 728 | |||||||||
Operating cash flow from discontinued operations |
4 | (7 | ) | 1 | ||||||||
Net cash provided by operating activities |
606 | 251 | 729 | |||||||||
Cash Flows From Financing Activities |
||||||||||||
Borrowings on long-term debt |
401 | 189 | 1,130 | |||||||||
Payments on long-term debt agreements |
(48 | ) | (886 | ) | (292 | ) | ||||||
Borrowings on short-term debt |
96 | | | |||||||||
Cash contributions from noncontrolling interests |
| 2 | 12 | |||||||||
Cash dividends to noncontrolling interests |
| (3 | ) | | ||||||||
Payments to affiliates related to stock-based awards |
(6 | ) | (2 | ) | (8 | ) | ||||||
Excess tax benefits related to stock-based awards |
1 | | 3 | |||||||||
Financing costs |
(19 | ) | (14 | ) | (1 | ) | ||||||
Net cash provided by (used in) financing activities from continuing operations |
425 | (714 | ) | 844 | ||||||||
Cash Flows From Investing Activities |
||||||||||||
Capital expenditures |
(764 | ) | (283 | ) | (552 | ) | ||||||
Proceeds from return of capital and loan repayments and sale of assets |
34 | 30 | 39 | |||||||||
Proceeds from sale of membership interest |
| | 28 | |||||||||
Purchase of interest of acquired companies |
(4 | ) | (22 | ) | (19 | ) | ||||||
Investments in and loans to unconsolidated affiliates |
(7 | ) | | | ||||||||
Purchase of short-term investments |
| | (19 | ) | ||||||||
Maturities of short-term investments |
1 | 3 | 96 | |||||||||
(Increase) decrease in restricted deposits |
(5 | ) | 3 | 4 | ||||||||
Investments in other assets |
(7 | ) | (279 | ) | (337 | ) | ||||||
Net cash used in investing activities from continuing operations |
(752 | ) | (548 | ) | (760 | ) | ||||||
Net increase (decrease) in cash and cash equivalents |
279 | (1,011 | ) | 813 | ||||||||
Cash and cash equivalents at beginning of period |
796 | 1,807 | 994 | |||||||||
Cash and cash equivalents at end of period |
$ | 1,075 | $ | 796 | $ | 1,807 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
93
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.
The consolidated financial statements include the accounts of EME and all subsidiaries and partnerships in which EME has a controlling interest and variable interest entities in which EME is deemed the primary beneficiary. EME's investments in unconsolidated affiliates and variable interest entities in which EME is not deemed to be the primary beneficiary, are accounted for by the equity method. For a discussion of EME's variable interest entities, see Note 3Variable Interest Entities. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.
The preparation of financial statements in conformity with United States generally accepted accounting principles requires EME to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates.
Cash equivalents included money market funds totaling $813 million and $690 million at December 31, 2010 and 2009, respectively. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months.
Cash balances that are restricted under margining agreements are classified as restricted cash and included in current assets, as such amounts change frequently based on forward market prices. Restricted deposits consisted of cash balances that are restricted to pay amounts required for lease payments, debt service or to provide collateral. Included in restricted deposits was $20 million at each December 31, 2010 and 2009 related to lease payments and $24 million and $20 million at December 31, 2010 and 2009, respectively, related to debt service and collateral reserves, or other.
94
Inventory is stated at the lower of weighted average cost or market. Inventory is recorded at actual cost when purchased and then expensed at weighted-average cost as used. Generally, cost is reduced to market value if the market value of inventory has declined and it is probable that revenues earned from the generation of power will not cover the cost of the inventory in the ordinary course of business. Inventory consisted of the following:
|
December 31, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Coal, fuel oil and other raw materials |
$ | 163 | $ | 132 | |||
Spare parts, materials and supplies |
73 | 64 | |||||
Total inventory |
$ | 236 | $ | 196 | |||
Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are principally comprised of EME's majority-owned subsidiaries' plants and related facilities. Depreciation and amortization are computed using the straight-line method over the estimated useful life of the property, plant and equipment and over the shorter of the lease term or estimated useful life for leasehold improvements. Gains and losses from sale of assets are recognized at the time of the transaction.
As part of the acquisition of the Midwest Generation plants and Homer City plant, EME acquired emission allowances under the United States Environmental Protection Agency's (US EPA's) Acid Rain Program. EME uses these emission allowances in the normal course of its business to generate electricity and has classified them as part of property, plant and equipment. Acquired emission allowances will be amortized on a straight-line basis.
Estimated useful lives for property, plant and equipment are as follows:
Power plant facilities | 3 to 35 years | |
Leasehold improvements | Shorter of life of lease or estimated useful life |
|
Emission allowances | 25 to 33.75 years | |
Equipment, furniture and fixtures | 3 to 10 years | |
Capitalized leased equipment | 5 years | |
95
The remaining estimated useful life or lease term at December 31, 2010 for the Midwest Generation coal plants is as follows:
Crawford Station | 14 years | |
Fisk Station | 14 years | |
Joliet Unit 6 | 19 years | |
Joliet Units 7 and 81 | 20 years | |
Powerton Station1 | 23 years | |
Waukegan Station | 14 years | |
Will County Station | 19 years | |
Estimated useful lives of individual facilities could be impacted by decisions related to the installation of environmental remediation equipment. If environmental compliance equipment is not installed, the useful life may be shortened.
Certain of EME's power plant facilities and equipment require periodic major maintenance. These costs are expensed as incurred.
Interest incurred on funds borrowed by EME is capitalized during the construction period. Such capitalized interest is included in property, plant and equipment. Capitalized interest is amortized over the depreciation period of the major plant and facilities for the respective project. Capitalized interest was $54 million, $19 million and $32 million in 2010, 2009 and 2008, respectively.
Impairment of Long-Lived Assets
EME evaluates the impairment of its investments in projects and other long-lived assets based on a review of estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying amount of such investments or assets may not be recoverable. If the carrying amount for an investment in a project exceeds fair value, an impairment loss is recorded if the decline is other than temporary. If the carrying amount of a long-lived asset exceeds the expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized.
EME capitalizes project development costs incurred in the assessment, design and construction of generating projects once it is probable that the project will be completed. EME determines it is probable that the project will be completed based upon management's determination that the project is economically and operationally feasible and appropriate management and regulatory approvals have been obtained or are probable. Project development costs consist of professional fees, permits and other directly related development costs incurred by EME. The capitalized costs are recorded in other long-term assets on EME's consolidated balance sheets until the start of construction, at which time the costs are transferred to construction in progress, a component of property, plant and equipment. The
96
capitalized costs are amortized over the life of the projects once operational or charged to expense if management determines the costs to be unrecoverable.
Acquired intangible assets with indefinite lives are not amortized; rather they are tested at least annually for impairment or when events or changes in circumstances indicate that the asset might be impaired. Intangible assets are periodically reviewed when impairment indicators are present to assess recoverability from future operations using undiscounted future cash flows. Project development rights are subject to ongoing impairment analysis, such that if a project is no longer expected to be developed, the capitalized costs are written off.
Current unamortized intangible assets reflected in prepaid expenses and other on EME's consolidated balance sheet, consist of purchased emission allowances and were $29 million and $51 million at December 31, 2010 and 2009, respectively.
Noncurrent intangible assets reflected in other long-term assets on EME's consolidated balance sheets consist of the following unamortized intangible assets:
|
December 31, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Project development rights |
$ | 4 | $ | 10 | |||
Option rights |
14 | 17 | |||||
Purchased emission allowances1 |
31 | 21 | |||||
Total unamortized intangible assets |
$ | 49 | $ | 48 | |||
Project development rights relate to the consolidation of a development stage enterprise. As project development is completed, the project development rights will be considered part of the property, plant and equipment and depreciated over the estimated useful lives of the respective projects. During 2008, EME recorded a $7 million write-down of capitalized costs, which was reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statement of income.
Option rights relate to EME's joint development agreement entered into to develop jointly a portfolio of projects located in Arizona, Nevada and New Mexico and an option to purchase specific projects. As of December 31, 2010, option rights were $14 million, net of a $3 million write-down in 2009, which was reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statement of income for options unused. The remaining projects are in development with target completion dates of 2012 and beyond. EME is required to fund ongoing development expenses for each project.
Emission allowances at EME's coal plants are classified as current or long-term assets based on the time the allowances are expected to be used. Total emission allowances at these facilities decreased in 2010 due to usage of existing allowances. EME also holds purchased emission allowances related to thermal projects under development.
97
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 9Commitments and ContingenciesPower Plant and Other Lease Commitments.
Power purchase agreements entered into by EME may contain leases as described under Power Purchase Agreements, below.
Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis that approximates the effective interest rate method over the term of the related debt. EME had unamortized debt issuance costs of $54 million and $43 million at December 31, 2010 and 2009, respectively. Amortization of deferred financing costs charged to interest expense was $5 million, $3 million and $1 million in 2010, 2009 and 2008, respectively.
Generally, revenues and related costs are recognized when electricity is generated or services are provided unless the transaction is accounted for as a derivative and does not qualify for the normal purchases and sales exception. EME's subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts, all subject to market conditions. One of EME's subsidiaries executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EME's subsidiaries generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. EME's subsidiaries record the settlement of non-trading physical forward contracts on a gross basis. EME nets the cost of purchased power against related third-party sales in markets that use locational marginal pricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EME's subsidiaries do not take title to the underlying commodity. Therefore, gains and losses from settlement of financial swaps and options are recorded net in operating revenues in the accompanying consolidated income statements.
Revenues under certain long-term power sales contracts are recognized based on the output delivered at the lower of the amount billable or the average rate over the contract term. The excess of the amounts billed over the portion recorded as revenues is reflected in deferred revenues on the consolidated balance sheets.
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EME accounts for grant income on the deferred method and, accordingly, will recognize operating revenues related to such income over the estimated useful life of the projects. In 2010, EME received $92 million in U.S. Treasury grants (cash grants, under the American Recovery and Reinvestment Act of 2009) related to wind projects that was included in prepaid expenses and other on its consolidated balance sheet at December 31, 2009.
EME, generally as the seller, enters into long-term power purchase agreements in the normal course of business. Accounting for long-term power purchase agreements is complex and varies based on the terms and conditions of each agreement. A power purchase agreement may be considered a variable interest in a variable interest entity. Under this classification, the power purchase agreement is evaluated to determine if EME is the primary beneficiary in the variable interest entity, in which case, such entity would be consolidated. EME does not have any power purchase agreements in which it is the primary beneficiary.
A power purchase agreement may also contain a lease for accounting purposes. This generally occurs when a power purchase agreement (signed or modified after June 30, 2003) designates a specific power plant in which the buyer purchases substantially all of the output and does not otherwise meet a fixed price per unit of output exception. EME has a number of power purchase agreements that contain leases. These agreements are classified as operating leases. EME records rental income from wind projects that are accounted for as operating leases as electricity is delivered at rates defined in power sales agreements. Revenues from these power sales agreements were $81 million, $83 million and $46 million in 2010, 2009 and 2008, respectively.
A power purchase agreement that does not contain a lease may be classified as a derivative subject to a normal purchases and sales exception, in which case the power purchase agreement is classified as an executory contract. The contracts that are not eligible for the normal purchases and sales exception are defined as a derivative and are recorded on the consolidated balance sheets at fair value. For further information on derivatives and hedging activities, see Note 6Derivative Instruments and Hedging Activities.
Power purchase agreements that do not meet the above classification are accounted for on the accrual basis.
Derivative Instruments and Hedging Activities
Authoritative guidance on derivatives and hedging establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). EME is required to record derivatives on its balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as normal purchases and sales. All changes in the fair value of derivative instruments are recognized currently in earnings, unless specific hedge criteria are met, which requires that EME formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
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The accounting guidance for cash flow hedges provides that the effective portion of gains or losses on derivative instruments designated and qualifying as cash flow hedges be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gains or losses on the derivative instruments, if any, must be recognized currently in earnings.
Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows. Derivative and hedging accounting policies are discussed further in Note 6Derivative Instruments and Hedging Activities.
Edison International's stock options, performance shares, deferred stock units and restricted stock units have been granted to EME employees under Edison International's long-term incentive compensation programs. Edison International usually does not issue new common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of option exercises, performance shares, and restricted stock units. Edison International has discretion to settle certain performance shares awards in common stock; however, generally settles half in cash and half in common stock. Deferred stock units granted to management are settled in cash and represent a liability. Restricted stock units are settled in common stock; however, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.
EME recognizes stock-based compensation expense on a straight-line basis over the requisite service period. EME recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, EME recognized stock-based compensation expense over the explicit requisite service period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal requisite service period for the award, stock-based compensation is recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement.
EME is included in the consolidated federal and state income tax returns of Edison International and participates in tax-allocation and payment agreements with other subsidiaries of Edison International. EME calculates its tax provision in accordance with these tax agreements. EME's current tax liability or benefit is determined on a "with and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding EME's taxable income or loss and state apportionment factors. This method is similar to a separate company return, except that EME recognizes, without regard
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to separate company limitations, additional tax liabilities or benefits based on the impact to the combined group including EME's taxable income or losses and state apportionment factors. At December 31, 2010 and 2009, amounts included in receivables from affiliates and other long-term assets associated with the tax-allocation agreements totaled $199 million and $80 million, respectively.
EME accounts for deferred income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted income tax rates. Investment and energy tax credits are deferred and amortized over the term of the power purchase agreement of the respective project while production tax credits are recognized when earned. EME's investments in wind-powered electric generation projects qualify for federal production tax credits under Section 45 of the Internal Revenue Code, unless a U.S. Treasury cash grant has been elected. Such credits are allowable for production during the 10-year period after a qualifying wind energy facility is placed into service. Certain of these investments may also be eligible for an option to claim investment tax credits (30% of eligible property) or to obtain cash grants for specified renewable energy projects in lieu of credits (30% of eligible property). Cash grants in lieu of tax credits are obtained separate from the tax return. EME applied for and received U.S. Treasury grants in 2010 for Phase II of the Goat Wind and High Lonesome wind projects, which were placed in service in 2009. Certain of EME's wind projects also qualify for state tax credits, which are accounted for similarly to federal production tax credits. For further information regarding income taxes, see Note 7Income Taxes.
Accounting Guidance Adopted in 2010
ConsolidationImprovements to Financial Reporting by Enterprises Involved with Variable Interest Entities
The Financial Accounting Standards Board (FASB) issued an accounting standards update that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, its ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has the obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. EME adopted this guidance effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of certain wind assets totaling $253 million and the consolidation of coal assets totaling $99 million at January 1, 2010. Deconsolidation did not result in a gain or loss. The consolidation of EME's 50% partnership interest in American Bituminous Power Partners, L.P., referred to as the Ambit project, a coal-fired electrical plant project with a capacity of 80 MW, resulted in a cumulative effect adjustment that increased retained earnings by $10 million. For further discussion, see Note 3Variable Interest Entities.
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Fair Value Measurements and Disclosures
The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. The requirements, which EME adopted effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. Since this guidance impacts disclosures only, the adoption did not have an impact on EME's consolidated results of operations, financial position or cash flows. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 4Fair Value Measurements.
Accounting Guidance Not Yet Adopted
In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The adoption of this accounting standards update will not have a material impact on EME's consolidated results of operations, financial position or cash flows.
Note 2. Property, Plant and Equipment
Property, plant and equipment consisted of the following:
|
December 31, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Power plant facilities |
$ | 4,478 | $ | 4,133 | |||
Leasehold improvements |
177 | 156 | |||||
Emission allowances |
1,305 | 1,305 | |||||
Construction in progress1 |
1,036 | 616 | |||||
Equipment, furniture and fixtures |
95 | 69 | |||||
|
7,091 |
6,279 |
|||||
Less accumulated depreciation and amortization |
1,759 |
1,474 |
|||||
Net property, plant and equipment |
$ | 5,332 | $ | 4,805 | |||
In the fourth quarter of 2010, Midwest Generation recorded a $40 million write-off reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" of
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capitalized construction in progress costs for air emissions control technology that is not currently being pursued for use at the Powerton Station.
The power sales agreements of certain wind projects qualify as operating leases pursuant to authoritative guidance on leases. The carrying amount and related accumulated depreciation of the property of these wind projects totaled $1.4 billion and $137 million, respectively, at December 31, 2010.
Authoritative guidance on asset retirement obligations (AROs) requires entities to record the fair value of a liability for an ARO in the period in which it is incurred, including a liability for the fair value of a conditional ARO, if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. When an ARO liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased for accretion expense to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Settlement of an ARO liability for an amount other than its recorded amount results in an increase or decrease in expense.
Midwest Generation has conditional AROs related to asbestos removal and disposal costs for owned buildings and power plant facilities. EME has not recorded a liability related to these structures because it cannot reasonably estimate the obligation's fair value at this time. The range of time over which EME may settle these obligations in the future (demolition or other method) is sufficiently large to not allow for the use of expected present value techniques.
EME has recorded AROs related to its wind facilities due to site lease obligations to return the land to grade at the end of the respective leases. Wind-related AROs cover site reclamation and turbine and related facility dismantlement. The earliest settlement of any of these obligations is anticipated to be in 2019. However, the operation of an individual facility may impact the timing of the ARO for that facility. Decisions made in conjunction with each facility's operation could extend or shorten the anticipated life depending on improvements and other factors.
EME recorded a liability representing expected future costs associated with site reclamations, facilities dismantlement and removal of environmental hazards, which is included in other
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long-term liabilities on EME's consolidated balance sheets. A reconciliation of the changes in the ARO liability is as follows:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Beginning balance |
$ | 43 | $ | 34 | $ | 16 | ||||
Accretion expense |
3 | 3 | 1 | |||||||
Revisions |
| | (4 | ) | ||||||
Liabilities added |
9 | 6 | 21 | |||||||
Transfers out1 |
(1 | ) | | | ||||||
Ending balance |
$ | 54 | $ | 43 | $ | 34 | ||||
Note 3. Variable Interest Entities
Authoritative guidance regarding consolidation of variable interest entities defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk, or as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. Effective January 1, 2010, EME adopted the FASB's new guidance. Under this new qualitative model, the primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of variable interest entities in which EME has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements. EME uses variable interest entities to conduct its business as described below.
Description of Use of Variable Interest Entities
EME is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power generation facilities and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project.
EME's subsidiaries and affiliates have financed the development and construction or acquisition of its projects by capital contributions from EME and the incurrence of debt or lease obligations by its subsidiaries and affiliates owning the operating facilities. These project
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level debt or lease obligations are generally secured by project specific assets and structured as non-recourse to EME, with several exceptions, including EME's guarantee of the Powerton and Joliet leases as part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Midwest Generation plants.
Categories of Variable Interest Entities
Projects or Entities that are Consolidated
EME has purchased a majority interest in a number of wind projects under joint development agreements with third-party developers. At December 31, 2010 and 2009, EME had majority interests in 15 wind projects with a total generating capacity of 700 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. Upon the application of the new guidance effective January 1, 2010, EME deconsolidated two of these projects. See further discussion in "Projects that are not Consolidated." In determining that EME was the primary beneficiary of the 13 projects consolidated at December 31, 2010, the key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities.
The following table presents summarized financial information of the wind projects that were consolidated by EME:
|
December 31, | |||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
||||||
Current assets |
$ | 16 | $ | 73 | ||||
Net property, plant and equipment1 |
660 | 944 | ||||||
Other long-term assets |
2 | 2 | ||||||
Total assets1 |
$ | 678 | $ | 1,019 | ||||
Current liabilities |
$ | 11 | $ | 17 | ||||
Long-term debt net of current maturities |
16 | 20 | ||||||
Deferred revenues |
57 | 58 | ||||||
Other long-term liabilities |
19 | 21 | ||||||
Total liabilities |
$ | 103 | $ | 116 | ||||
Noncontrolling interests |
$ | 4 | $ | 76 | ||||
Assets serving as collateral for the debt obligations had a carrying value of $71 million and $81 million at December 31, 2010 and 2009, respectively, and primarily consist of property, plant and equipment. The consolidated statements of income and cash flows for the years ended December 31, 2010 and 2009 includes $13 million and $12 million of pre-tax losses, respectively, and $7 million and $37 million of operating cash flows, respectively, related to variable interest entities that are consolidated.
EME has a 50% partnership interest in the Ambit project. EME has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has
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the obligation to absorb losses and right to receive benefits from the project. Effective January 1, 2010, under new accounting guidance, EME is the primary beneficiary. As the primary beneficiary, EME consolidated Ambit project assets totaling $99 million on January 1, 2010.
The following table presents the summarized financial information of the Ambit project consolidated by EME:
(in millions) |
December 31, 2010 |
||||
---|---|---|---|---|---|
Current assets |
$ | 10 | |||
Net property, plant and equipment |
79 | ||||
Other long-term assets |
4 | ||||
Total assets |
$ | 93 | |||
Current liabilities |
$ | 14 | |||
Long-term obligations net of current maturities |
55 | ||||
Deferred revenues |
14 | ||||
Other long-term liabilities |
2 | ||||
Total liabilities |
$ | 85 | |||
Substantially all of the assets above are pledged as collateral for the partnership's debt obligations.
The consolidated statements of income and cash flows for the year ended 2010 were not significantly impacted by the consolidation of the Ambit project.
Projects that are not Consolidated
EME accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. As of December 31, 2010 and 2009, EME had five significant variable interests in projects that are not consolidated, consisting of the Big 4 projects and the Sunrise project. A subsidiary of EME operates the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects) and EME's partner provides the fuel management services. In addition, the executive director of these projects is provided by EME's partner. Commercial and operating activities are jointly controlled by a management committee of each variable interest entity. Accordingly, EME continues to account for its variable interests under the equity method.
EME deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EME is not the primary beneficiary of these projects. Accordingly, effective January 1, 2010, EME accounts for its interests in these projects under the equity method.
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The following table presents the carrying amount of EME's investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment:
|
As of December 31, 2010 | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
Investment |
Maximum Exposure |
|||||
Natural gas-fired projects |
$ | 333 | $ | 333 | |||
Wind projects |
224 | 224 | |||||
EME's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EME's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's investment, but would not require EME to contribute additional capital. At December 31, 2010, entities which EME has accounted for under the equity method had indebtedness of $116 million, of which $41 million is proportionate to EME's ownership interest in these two projects. At December 31, 2009, entities which EME has accounted for under the equity method had indebtedness of $245 million, of which $104 million was proportionate to EME's ownership interest in these two projects.
The following table presents summarized financial information of the investments in unconsolidated affiliates accounted for by the equity method:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Revenues |
$ | 828 | $ | 936 | $ | 1,434 | ||||
Expenses |
653 | 734 | 1,193 | |||||||
Net income |
$ | 175 | $ | 202 | $ | 241 | ||||
|
December 31, | |||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
||||||
Current assets |
$ | 296 | $ | 387 | ||||
Noncurrent assets |
850 | 715 | ||||||
Total assets |
$ | 1,146 | $ | 1,102 | ||||
Current liabilities |
$ | 157 | $ | 198 | ||||
Noncurrent liabilities |
74 | 198 | ||||||
Equity |
915 | 706 | ||||||
Total liabilities and equity |
$ | 1,146 | $ | 1,102 | ||||
The difference between the carrying value of these equity investments and the underlying equity in the net assets was $11 million at December 31, 2010. The difference is being amortized over the life of the projects. The majority of noncurrent liabilities are comprised of project financing arrangements that are non-recourse to EME. The undistributed earnings of
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equity method investments were $28 million and $30 million at December 31, 2010 and 2009, respectively.
In February 2010, EME sold its 50% ownership interest in the March Point project to its partner after receiving an $18 million equity distribution reflected in "Equity in income from unconsolidated affiliates" on EME's consolidated statement of income. The purchaser of EME's interest in March Point has agreed to indemnify EME for claims under a guarantee.
The following table presents, as of December 31, 2010, the investments in unconsolidated affiliates accounted for by the equity method that represent at least five percent (5%) of EME's income before tax or in which EME has an investment balance greater than $50 million:
Unconsolidated Affiliates |
Location |
Investment at December 31, 2010 (in millions) |
Ownership Interest at December 31, 2010 |
Operating Status |
||||||
---|---|---|---|---|---|---|---|---|---|---|
San Juan Mesa |
Elida, NM | $ | 92 | 75 | % | Operating wind-powered facility | ||||
Elkhorn Ridge |
Bloomfield, NE | 81 | 67 | % | Operating wind-powered facility | |||||
Sunrise |
Fellows, CA | 174 | 50 | % | Operating gas-fired facility | |||||
Midway-Sunset |
Taft, CA | 40 | 50 | % | Operating cogeneration facility | |||||
Sycamore |
Bakersfield, CA | 36 | 50 | % | Operating cogeneration facility | |||||
Kern River |
Bakersfield, CA | 26 | 50 | % | Operating cogeneration facility | |||||
Watson |
Carson, CA | 48 | 49 | % | Operating cogeneration facility | |||||
The following table presents summarized financial information of the investments in unconsolidated affiliates:
(in millions) |
2010 |
2009 |
||||||
---|---|---|---|---|---|---|---|---|
Investments in Unconsolidated Affiliates |
||||||||
Equity investment |
$ | 548 | $ | 351 | ||||
Cost investment |
9 | 10 | ||||||
Total |
$ | 557 | $ | 361 | ||||
At December 31, 2010 and 2009, EME has a 38% ownership interest in a small biomass project that it accounts for under the cost method of accounting as it does not have a significant influence over the project's operating and financial activities. EME believes that the carrying amount at December 31, 2010 and 2009 was not impaired.
At December 31, 2010 and 2009, EME accounted for its ownership in the Doga project on the cost method as accumulated distributions exceeded accumulated earnings. EME has not estimated the fair value of cost method investments as quoted market prices are not available and the determination of fair value is highly subjective and cannot be readily ascertained.
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Note 4. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or a liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. The fair value of derivative assets' nonperformance risk was not material as of December 31, 2010 and 2009.
EME categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The following table sets forth EME's assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
|
As of December 31, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Netting and Collateral1 |
Total |
|||||||||||||
Assets at Fair Value |
||||||||||||||||||
Money market funds2 |
$ | 813 | $ | | $ | | $ | | $ | 813 | ||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | 70 | $ | 107 | $ | (61 | ) | $ | 116 | |||||||
Natural gas |
1 | | | (1 | ) | | ||||||||||||
Fuel oil |
8 | | | (8 | ) | | ||||||||||||
Total commodity contracts |
9 | 70 | 107 | (70 | ) | 116 | ||||||||||||
Total assets |
$ | 9 | $ | 70 | $ | 107 | $ | (70 | ) | $ | 116 | |||||||
Liabilities at Fair Value |
||||||||||||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | 12 | $ | 16 | $ | (21 | ) | $ | 7 | |||||||
Natural gas |
| 2 | | | 2 | |||||||||||||
Coal |
| 1 | | (1 | ) | | ||||||||||||
Total commodity contracts |
| 15 | 16 | (22 | ) | 9 | ||||||||||||
Interest rate contracts |
| 16 | | | 16 | |||||||||||||
Total liabilities |
$ | | $ | 31 | $ | 16 | $ | (22 | ) | $ | 25 | |||||||
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|
As of December 31, 2009 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Netting and Collateral1 |
Total |
|||||||||||||
Assets at Fair Value |
||||||||||||||||||
Money market funds2 |
$ | 758 | $ | | $ | | $ | | $ | 758 | ||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | 235 | $ | 179 | $ | (136 | ) | $ | 278 | |||||||
Natural gas |
2 | | | (2 | ) | | ||||||||||||
Fuel oil |
15 | | | (15 | ) | | ||||||||||||
Total commodity contracts |
17 | 235 | 179 | (153 | ) | 278 | ||||||||||||
Total assets |
$ | 17 | $ | 235 | $ | 179 | $ | (153 | ) | $ | 278 | |||||||
Liabilities at Fair Value |
||||||||||||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | 85 | $ | 6 | $ | (73 | ) | $ | 18 | |||||||
Natural gas |
3 | 1 | | (4 | ) | | ||||||||||||
Total commodity contracts |
3 | 86 | 6 | (77 | ) | 18 | ||||||||||||
Interest rate contracts |
| 2 | | | 2 | |||||||||||||
Total liabilities |
$ | 3 | $ | 88 | $ | 6 | $ | (77 | ) | $ | 20 | |||||||
The following table sets forth a summary of changes in the fair value of assets and liabilities, net categorized as Level 3:
|
|
2009 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 Derivatives |
Derivatives |
Money Market Funds |
||||||||
Fair value, net asset at beginning of periods |
$ | 173 | $ | 213 | $ | 3 | |||||
Total realized/unrealized gains (losses): |
|||||||||||
Included in earnings1 |
64 | 7 | | ||||||||
Included in accumulated other comprehensive income (loss) |
2 | 3 | | ||||||||
Purchases and settlements, net2 |
(143 | ) | (40 | ) | (3 | ) | |||||
Transfers in or out of Level 3 |
(5 | ) | (10 | ) | | ||||||
Fair value, net asset at end of periods |
$ | 91 | $ | 173 | $ | | |||||
Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at end of periods1 |
$ | 13 | $ | 64 | $ | | |||||
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EME determines the fair value of transfers in and out of each level at the end of each reporting period. There were no significant transfers between levels during 2010, 2009 and 2008.
Valuation Techniques used to Determine Fair Value
Level 1 includes assets and liabilities where unadjusted quoted prices in active markets are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded derivatives and money market funds.
Level 2 pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and liabilities utilizing Level 2 inputs include over-the-counter derivatives.
Derivative contracts that are over-the-counter traded are valued using pricing models and are generally classified as Level 2. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. Forward market prices are developed based on the source that best represents trade activity in each market. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.
Level 3 includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, qualifying facilities contracts, derivative contracts that trade infrequently (such as congestion revenue rights in the California market, financial transmission rights traded in markets outside California and over-the-counter derivatives at illiquid locations), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3. In circumstances where EME cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.
For derivative contracts that trade infrequently (illiquid financial transmission rights and congestion revenue rights), changes in fair value are based on the hypothetical sale of illiquid positions. Objective criteria are reviewed, including system congestion and other underlying drivers and fair value is adjusted when it is concluded that a change in objective criteria
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would result in a new valuation that better reflects fair value. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of EME's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models that may require EME to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.
The carrying amounts and fair values of EME's long-term debt were as follows:
|
December 31, 2010 | December 31, 2009 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||||||||
Long-term debt, including current portion |
$ | 4,390 | $ | 3,670 | $ | 3,966 | $ | 3,150 | |||||
In assessing the fair value of EME's long-term debt, EME primarily uses quoted market prices, except for floating-rate debt for which the carrying amounts were considered a reasonable estimate of fair value.
The carrying amount of trade receivables, payables and short-term debt approximates fair value and, therefore, is not included in the table above.
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Note 5. Debt and Credit Agreements
Long-term debt includes both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay such obligations. At December 31, 2010, recourse debt to EME totaled $3.7 billion and non-recourse project debt totaled $690 million. The following table summarizes long-term debt (rates and terms as of December 31, 2010):
|
December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||||
Recourse |
|||||||||
EME (parent only) |
|||||||||
Senior Notes, net |
|||||||||
due 2013 (7.50%) |
$ | 500 | $ | 500 | |||||
due 2016 (7.75%) |
500 | 500 | |||||||
due 2017 (7.00%) |
1,200 | 1,200 | |||||||
due 2019 (7.20%) |
800 | 800 | |||||||
due 2027 (7.625%) |
700 | 700 | |||||||
Non-recourse |
|||||||||
EME CP Holdings Co. |
54 |
61 |
|||||||
Viento Funding II, Inc. |
150 | 178 | |||||||
American Bituminous Power Partners, L.P. |
63 | | |||||||
Big Sky Wind, LLC |
190 | | |||||||
Cedro Hill Wind, LLC |
135 | | |||||||
High Lonesome Mesa, LLC |
75 | | |||||||
Other |
23 | 27 | |||||||
Subtotal |
$ | 4,390 | $ | 3,966 | |||||
Less current maturities of long-term debt |
48 | 37 | |||||||
Total |
$ | 4,342 | $ | 3,929 | |||||
Long-term debt maturities at December 31, 2010, for the next five years are summarized as follows: $48 million in 2011, $58 million in 2012, $566 million in 2013, $260 million in 2014, and $70 million in 2015.
In connection with Midwest Generation's financing activities, a first priority security interest was provided in substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants, the receivables of EMMT directly related
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to Midwest Generation's hedging activities and the pledge of the intercompany notes from EME (approximately $1.3 billion at December 31, 2010). The net book value of assets pledged or mortgaged was $2.8 billion at December 31, 2010. In addition to these assets, Midwest Generation's membership interests and the capital stock of Edison Mission Midwest Holdings were pledged.
In connection with the Viento Funding II wind financing, Viento Funding II's payment obligations are secured by pledges of its direct and indirect ownership interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. In connection with the Big Sky turbine financing, the loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if any, of the Big Sky wind project is to be deposited on a monthly basis. In connection with each of the High Lonesome, Laredo Ridge and Cedro Hill wind financings, the payment obligations are secured by a mortgage on the respective project's real property assets and a pledge of the respective project's material contracts. In connection with the High Lonesome financing, a security interest was also provided in an operations and maintenance reserve account and a debt service reserve account that the project is required to fund over a period of time.
For further details regarding consolidated assets pledged as security for debt obligations, see Note 3Variable Interest Entities.
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.
Total borrowings available under EME's secured credit facility maturing in June 2012 were $564 million, and subject to the satisfaction of conditions as set forth in the secured credit facility, EME is permitted to increase the amount available under the secured credit facility to an amount that, when taken together with all other secured indebtedness of EME, does not exceed 15% of EME's consolidated net tangible assets, as defined in the secured credit facility. Loans made under this credit facility bear interest, at EME's election, at either London Interbank Offered Rate, or LIBOR, (which is based on the interbank Eurodollar market) or the base rate (which is calculated as the higher of Citibank, N.A.'s publicly announced base rate and the federal funds rate in effect from time to time plus 0.50%) plus, in both cases, an applicable margin. The applicable margin depends on EME's debt ratings. The credit facility contains financial covenants which require EME to maintain an interest
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coverage ratio not less than 1.20 and a corporate debt to corporate capital ratio not more than 0.75. A failure to meet a ratio threshold could trigger other provisions and require a prepayment of the outstanding borrowings. At December 31, 2010, the interest coverage ratio was 2.07 for the year ended December 31, 2010 and the corporate debt to corporate capital ratio was 0.52.
EME's corporate credit agreement contains covenants that restrict its ability and the ability of several of its subsidiaries to make distributions. This restriction impacts the subsidiaries that own interests in the Westside projects, the Sunrise project, the coal plants, and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME's shareholder if an event of default were to occur and be continuing under EME's secured credit agreement after giving effect to the distribution.
Borrowings made under Midwest Generation's credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%. The working capital facility matures in June 2012. The working capital facility contains financial covenants which require Midwest Generation to maintain a debt to capitalization ratio of no greater than 0.60 to 1. At December 31, 2010, the debt to capitalization ratio was 0.15 to 1. Midwest Generation uses its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation can also support its hedging activities by granting liens to eligible hedge counterparties.
The following table summarizes the status of the EME and Midwest Generation credit facilities at December 31, 2010:
(in millions) |
EME |
Midwest Generation |
|||||
---|---|---|---|---|---|---|---|
Commitments |
$ | 564 | $ | 500 | |||
Outstanding borrowings |
| | |||||
Outstanding letters of credit |
(80 | ) | (3 | ) | |||
Amount available |
$ | 484 | $ | 497 | |||
Viento Funding II Wind Financing
In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The financing included a $189 million seven-year term loan and a $13 million letter of credit facility which replaced project letters of credit previously issued under the EME corporate credit facility. Interest under the term loan accrues at LIBOR plus 3.875% initially, with the rate increasing 0.25% on the third and sixth anniversaries of the closing date. Viento Funding II entered into interest rate swap agreements at 3.175% to hedge the majority of the variable interest rate under the term loan. For further details regarding the interest rate swap agreements, see Note 6Derivative Instruments and Hedging Activities.
Distributions from Viento Funding II are subject to compliance with the terms and conditions of its credit facilities, including a 12-month historic debt service coverage ratio test as
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specified in the agreements of 1.20 to 1.0. The debt service coverage ratio was 2.08 at December 31, 2010. At December 31, 2010, $150 million was outstanding under this loan. The amount of outstanding letters of credit was $13 million.
EME consolidated the Ambit project on January 1, 2010. At December 31, 2010, this project had $63 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The Ambit project is required to maintain funded reserve accounts primarily for debt servicing and maintenance costs. The required reserve account balance at December 31, 2010 was $18 million and was under funded by $14 million. The underfunded reserve does not create an event of default under the loan, but does restrict distributions from the Ambit project.
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:
At December 31, 2010, $190 million was outstanding under this loan.
In November 2010, EME completed through its subsidiary, High Lonesome Mesa, LLC, a non-recourse financing of its interests in the High Lonesome wind project. The $81 million financing included: $50 million Series 2010A bonds issued by the New Mexico Renewable Energy Transmission Authority, as a conduit issuer for High Lonesome Mesa, LLC, with proceeds loaned to the High Lonesome wind project, $25 million Series 2010B bonds issued directly by the project, and a $6 million debt service reserve letter of credit facility.
Both series of bonds mature on November 1, 2017, and accrue interest at 6.85%. The Series 2010A bonds are scheduled to partially amortize over the term, while no principal payments of the Series 2010B bonds are due until maturity. As of December 31, 2010, there were $50 million and $25 million outstanding under the Series 2010A bonds and Series 2010B bonds, respectively, and $5 million of outstanding letters of credit.
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In July 2010, EME completed through its subsidiary, Laredo Ridge Wind, LLC, a non-recourse financing of its interests in the Laredo Ridge wind project. The financing included: a $75 million construction loan required to be converted to a 15-year amortizing term loan by August 31, 2011, subject to meeting specified conditions; a $53 million bridge loan, secured by the expected U.S. Treasury grant, immediately due to be fully repaid upon receipt of the U.S. Treasury grant and no later than December 31, 2011; a $9 million letter of credit facility; and a $3 million working capital facility.
Interest under the construction loan and the term loan will accrue at LIBOR plus 2.75% initially, with the rate increasing 0.125% after the third, sixth, ninth and twelfth years. Pursuant to the financing agreement, Laredo Ridge entered into a forward starting interest rate swap agreement at 3.46% to hedge the majority of the variable interest rate debt effective March 31, 2011, the same date EME estimates that the construction loan will convert to the term loan. Interest under the bridge loan will accrue at LIBOR plus 2.50%. For further details regarding the interest rate swap agreements, see Note 6Derivative Instruments and Hedging Activities. As of December 31, 2010, there was $43 million outstanding under the construction loan at a weighted average interest rate of 3.01% and $53 million outstanding under the bridge loan at a weighted average interest rate of 2.76%, both classified as short-term debt on EME's consolidated balance sheet, and $3 million of outstanding letters of credit.
In March 2010, EME completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that was converted to a 15-year amortizing term loan on December 22, 2010, a $10 million letter of credit facility and a $4 million working capital facility.
Interest under the term loan will accrue at LIBOR plus 3% initially, with the rate increasing 0.125% after the third, sixth, ninth and eleventh years and 0.25% after the thirteenth year. Pursuant to the financing agreement, Cedro Hill Wind entered into a forward starting interest rate swap agreement at 4.29% to hedge the majority of the variable interest rate debt. For further details regarding the interest rate swap agreements, see Note 6Derivative Instruments and Hedging Activities. As of December 31, 2010, there was $135 million outstanding under the term loan at a weighted average interest rate of 3.31% classified as long-term debt on EME's consolidated balance sheet and $10 million of outstanding letters of credit.
Other Letters of Credit Facilities
As of December 31, 2010, a subsidiary of EME had a $10 million letter of credit facility with $2 million outstanding letters of credit.
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As of December 31, 2010, standby letters of credit under EME's credit facility aggregated $80 million and were scheduled to expire as follows: $72 million in 2011 and $8 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $36 million, $3 million of which was under the Midwest Generation credit facility, and were scheduled to expire as follows: $23 million in 2011, $3 million in 2012 and $10 million in 2017. Certain letters of credit are subject to automatic annual renewal provisions.
Note 6. Derivative Instruments and Hedging Activities
EME uses derivative instruments to reduce EME's exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. To the extent that EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.
Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EME's consolidated balance sheets with offsetting changes recorded on the consolidated statements of income. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on EME's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted transaction occurs.
Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues on the consolidated statements of income.
Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.
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Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
December 31, 2010 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity |
Forwards/Futures | Sales | GWh1 | 16,799 | 2 | 22,456 | 4 | 34,630 | ||||||||
Electricity |
Forwards/Futures | Purchases | GWh | 408 | 2 | 22,931 | 4 | 37,669 | ||||||||
Electricity |
Capacity | Sales | MW-Day (in thousands) |
190 | 3 | | 136 | 3 | ||||||||
Electricity |
Capacity | Purchases | MW-Day (in thousands) |
8 | 3 | | 419 | 3 | ||||||||
Electricity |
Congestion | Sales | GWh | | 136 | 5 | 12,020 | 5 | ||||||||
Electricity |
Congestion | Purchases | GWh | | 1,143 | 5 | 187,689 | 5 | ||||||||
Natural gas |
Forwards/Futures | Sales | bcf1 | | | 30.6 | ||||||||||
Natural gas |
Forwards/Futures | Purchases | bcf | | | 34.3 | ||||||||||
Fuel oil |
Forwards/Futures | Sales | barrels | | 250,000 | 10,000 | ||||||||||
Fuel oil |
Forwards/Futures | Purchases | barrels | | 490,000 | 10,000 | ||||||||||
Coal |
Forwards/Futures | Sales | tons | | | 2,630,500 | ||||||||||
Coal |
Forwards/Futures | Purchases | tons | | | 2,645,500 | ||||||||||
(in millions) | |||||||||
---|---|---|---|---|---|---|---|---|---|
Instrument |
Purpose |
Type of Hedge |
Notional Amount |
Expiration Date |
|||||
Amortizing interest rate swap |
Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt |
Cash flow | $ | 138 | June 2016 | ||||
Amortizing forward starting |
Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt |
Cash flow | 122 | December 2025 | |||||
Amortizing forward starting |
Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt |
Cash flow | 68 | March 2026 | |||||
December 31, 2009 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity |
Forwards/Futures | Sales | GWh1 | 24,355 | 2 | 26,838 | 4 | 23,306 | ||||||||
Electricity |
Forwards/Futures | Purchases | GWh | 106 | 2 | 25,971 | 4 | 23,404 | ||||||||
Electricity |
Capacity | Sales | MW-Day (in thousands) |
254 | 3 | 1 | 3 | 597 | 3 | |||||||
Electricity |
Capacity | Purchases | MW-Day (in thousands) |
11 | 3 | 2 | 3 | 736 | 3 | |||||||
Electricity |
Congestion | Sales | GWh | | 136 | 5 | 10,212 | 5 | ||||||||
Electricity |
Congestion | Purchases | GWh | | 1,576 | 5 | 181,930 | 5 | ||||||||
Natural gas |
Forwards/Futures | Sales | bcf1 | | 3.3 | 30.8 | ||||||||||
Natural gas |
Forwards/Futures | Purchases | bcf | | | 30.6 | ||||||||||
Fuel oil |
Forwards/Futures | Sales | barrels | | 250,000 | 120,000 | ||||||||||
Fuel oil |
Forwards/Futures | Purchases | barrels | | 625,000 | 120,000 | ||||||||||
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(in millions) | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Instrument |
Purpose |
Type of Hedge |
Notional Amount |
Expiration Date |
|||||||
Amortizing interest rate swap |
Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt |
Cash flow | $ | 160 | June 2016 | ||||||
Included in trading activities in the preceding table, EME shows net the volume of energy trading activities that are physically settled. Gross purchases and sales totaled 3,944 GWh, 3,791 GWh and 4,080 GWh during 2010, 2009 and 2008, respectively.
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Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EME's consolidated balance sheets:
December 31, 2010 | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Derivative Assets | Derivative Liabilities | |
||||||||||||||||||||
(in millions) |
Short-term |
Long-term |
Subtotal |
Short-term |
Long-term |
Subtotal |
Net Assets |
||||||||||||||||
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 54 | $ | 2 | $ | 56 | $ | 10 | $ | 25 | $ | 35 | $ | 21 | |||||||||
Economic hedges |
77 | 2 | 79 | 71 | | 71 | 8 | ||||||||||||||||
Trading activities |
184 | 103 | 287 | 148 | 29 | 177 | 110 | ||||||||||||||||
|
315 | 107 | 422 | 229 | 54 | 283 | 139 | ||||||||||||||||
Netting and collateral received1 |
(269 | ) | (37 | ) | (306 | ) | (223 | ) | (35 | ) | (258 | ) | (48 | ) | |||||||||
Total |
$ | 46 | $ | 70 | $ | 116 | $ | 6 | $ | 19 | $ | 25 | $ | 91 | |||||||||
December 31, 2009 | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Derivative Assets | Derivative Liabilities | |
||||||||||||||||||||
(in millions) |
Short-term |
Long-term |
Subtotal |
Short-term |
Long-term |
Subtotal |
Net Assets |
||||||||||||||||
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 240 | $ | 17 | $ | 257 | $ | 69 | $ | 6 | $ | 75 | $ | 182 | |||||||||
Economic hedges |
202 | 8 | 210 | 180 | | 180 | 30 | ||||||||||||||||
Trading activities |
234 | 111 | 345 | 182 | 41 | 223 | 122 | ||||||||||||||||
|
676 | 136 | 812 | 431 | 47 | 478 | 334 | ||||||||||||||||
Netting and collateral received1 |
(479 | ) | (55 | ) | (534 | ) | (426 | ) | (32 | ) | (458 | ) | (76 | ) | |||||||||
Total |
$ | 197 | $ | 81 | $ | 278 | $ | 5 | $ | 15 | $ | 20 | $ | 258 | |||||||||
Income Statement Impact of Derivative Instruments
The following table provides the activity of accumulated other comprehensive income, containing information about the changes in the fair value of cash flow hedges, to the extent
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effective, and reclassification from accumulated other comprehensive income into results of operations:
|
Cash Flow Hedge Activity1 | |
||||||
---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
|||||||
(in millions) |
2010 |
2009 |
||||||
Accumulated other comprehensive income derivative gain at January 1 |
$ | 175 | $ | 398 | ||||
Effective portion of changes in fair value |
92 | 79 | ||||||
Reclassification from accumulated other comprehensive income to net income |
(240 | ) | (302 | ) | Operating revenues | |||
Accumulated other comprehensive income derivative gain at December 31 |
$ | 27 | $ | 175 | ||||
The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.
EME recorded net gains (losses) of $(4) million, $24 million and $7 million in 2010, 2009 and 2008, respectively, in operating revenues on the consolidated statements of income representing the amount of cash flow hedge ineffectiveness.
The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of income is presented below:
|
|
December 31, | |||||||
---|---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
||||||||
(in millions) |
2010 |
2009 |
|||||||
Economic hedges |
Operating revenues | $ | 8 | $ | 34 | ||||
|
Fuel costs | 2 | 18 | ||||||
Trading activities |
Operating revenues | 114 | 47 | ||||||
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Energy Trading Derivative Instruments
The fair value of outstanding energy trading derivative instruments at December 31, 2010 and 2009 was $110 million and $122 million, respectively. The change in the fair value of trading contracts was as follows:
|
Years Ended December 31, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Fair value of trading contracts at beginning of periods |
$ | 122 | $ | 112 | |||
Net gains from energy trading activities |
114 | 47 | |||||
Amount realized from energy trading activities |
(131 | ) | (44 | ) | |||
Other changes in fair value |
5 | 7 | |||||
Fair value of trading contracts at end of periods |
$ | 110 | $ | 122 | |||
Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at December 31, 2010 and, accordingly, the contingent features described above do not currently have liquidity exposure. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.
Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. EME nets counterparty receivables and payables where balances exist under master netting arrangements. EME presents the portion of its margin and collateral deposits netted with its derivative positions
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on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:
|
December 31, | |||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
||||||
Collateral provided to counterparties |
||||||||
Offset against derivative liabilities |
$ | 4 | $ | 49 | ||||
Reflected in margin and collateral deposits |
59 | 120 | ||||||
Collateral received from counterparties |
||||||||
Offset against derivative assets |
52 | 124 | ||||||
Commodity Price Risk Management
EME's merchant operations create exposure to commodity price risk, which reflects the potential impact of a change in the market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided by a risk management committee, to ensure compliance with EME's risk management policies. EME uses estimates of the variability in gross margin to help identify, measure, monitor and control its overall market risk exposure and earnings volatility with respect to hedge positions at the coal plants and the merchant wind projects, and uses "value at risk" metrics to help identify, measure, monitor and control its overall risk exposure in respect to its trading positions. These measures allow management to aggregate overall commodity risk, compare risk on a consistent basis and identify changes in risk factors. Value at risk measures the possible loss, and variability in gross margin measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers volumetric exposure limits. When appropriate, EME manages the spread between the electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives.
Interest rate 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.
In conducting EME's hedging and trading activities, EME enters into transactions with utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with market price changes occurring since the original contract was executed if the nonperforming counterparty were unable to pay the resulting damages owed to EME. Further, EME would be exposed to the risk of
124
non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.
To manage credit risk, EME evaluates the risk of potential defaults by counterparties. Credit risk is measured as the loss that EME would expect to incur if a counterparty failed to perform pursuant to the terms of its contractual obligations. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.
The majority of EME's consolidated wind projects and unconsolidated affiliates that own power plants sell power under power purchase agreements. Generally, each project or plant sells its output to one counterparty. A default by the counterparty, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of the project or plant.
The majority of the coal for the coal plants is purchased from suppliers under contracts which may be for multiple years. None of the coal suppliers to the coal plants have investment grade credit ratings and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier.
The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 66%, 48% and 50% of EME's consolidated operating revenues for the years ended December 31, 2010, 2009 and 2008, respectively. Moody's Investors Service, Inc. (Moody's) rates PJM's debt Aa3. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At December 31, 2010 and 2009, EME's account receivable due from PJM was $64 million and $50 million, respectively.
For the years ended December 31, 2010, 2009 and 2008, a second customer, Constellation Energy Commodities Group, Inc. accounted for less than 10%, 16% and 10%, respectively, of EME's consolidated operating revenues. Sales to Constellation are primarily generated from the coal plants and consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB- by Standard & Poor's Ratings Services (S&P) and Baa3 by Moody's. At December 31, 2010 and 2009, EME's account receivable due from Constellation was $32 million and $36 million, respectively.
For the year ended December 31, 2008, EME also derived 12% of its consolidated operating revenues from the sale of energy, capacity and ancillary services generated at the Midwest Generation plants to Commonwealth Edison Company under load requirements services contracts.
125
The provision (benefit) for income taxes is comprised of the following:
|
Years Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||||
Continuing Operations |
||||||||||||
Current |
||||||||||||
Federal |
$ | (288 | ) | $ | (176 | ) | $ | 95 | ||||
State |
18 | (35 | ) | 33 | ||||||||
Total current |
(270 | ) | (211 | ) | 128 | |||||||
Deferred |
||||||||||||
Federal |
$ | 278 | $ | 187 | $ | 96 | ||||||
State |
11 | 40 | 19 | |||||||||
Total deferred |
289 | 227 | 115 | |||||||||
Provision for income taxes from continuing operations |
19 | 16 | 243 | |||||||||
Discontinued operations |
9 | (2 | ) | 5 | ||||||||
Total |
$ | 28 | $ | 14 | $ | 248 | ||||||
EME recorded a tax benefit of $16 million in 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for the tax years 1986 through 2002.
The components of income (loss) before income taxes applicable to continuing operations and discontinued operations are as follows:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Continuing operations |
$ | 178 | $ | 217 | $ | 743 | ||||
Discontinued operations |
13 | (9 | ) | 6 | ||||||
Total |
$ | 191 | $ | 208 | $ | 749 | ||||
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The components of net accumulated deferred income tax liability are:
|
December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||||
Deferred tax assets |
|||||||||
Accrued charges and liabilities |
$ | 201 | $ | 156 | |||||
Net operating loss and tax credit carryforwards |
60 | | |||||||
Deferred income |
| 5 | |||||||
Other |
2 | | |||||||
Total |
263 | 161 | |||||||
Deferred tax liabilities |
|||||||||
Basis differences in property |
$ | 1,117 | $ | 821 | |||||
Derivative instruments |
| 93 | |||||||
Deferred investment tax credit |
4 | 5 | |||||||
State taxes |
9 | 27 | |||||||
Other |
3 | 6 | |||||||
Total |
1,133 | 952 | |||||||
Deferred tax liabilities and tax credits, net |
$ | 870 | $ | 791 | |||||
Classification of net accumulated deferred income taxes |
|||||||||
Included in current liabilities |
$ | 34 | $ | 119 | |||||
Included in non-current liabilities |
$ | 836 | $ | 672 | |||||
The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholder:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Provision for income taxes at federal statutory rate of 35% |
$ | 62 | $ | 76 | $ | 260 | ||||
State tax-net of federal benefit (excludes state tax settlement) |
9 | 7 | 33 | |||||||
Production tax credits, net |
(61 | ) | (55 | ) | (43 | ) | ||||
Qualified production deduction |
15 | (2 | ) | (13 | ) | |||||
Deferred tax adjustments1 |
6 | | | |||||||
Resolution of 1986-2002 state tax issues |
(16 | ) | | | ||||||
Other |
4 | (10 | ) | 6 | ||||||
Income tax expense from continuing operations |
$ | 19 | $ | 16 | $ | 243 | ||||
Effective tax rate |
11% | 7% | 33% | |||||||
127
Accounting for Uncertainty in Income Taxes
The following table provides a reconciliation of unrecognized tax benefits:
(in millions) |
2010 |
2009 |
2008 |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Balance at January 1 |
$ | 115 | $ | 144 | $ | 136 | |||||
Tax positions taken during the current year |
|||||||||||
Increases |
| | 8 | ||||||||
Decreases |
| | | ||||||||
Tax positions taken during a prior year |
|||||||||||
Increases |
126 | 11 | | ||||||||
Decreases |
(80 | ) | | | |||||||
Increases (decreases) for settlements during the period |
(8 |
) |
(40 |
) |
|
||||||
Decreases resulting from a lapse in statute of limitations |
| | | ||||||||
Balance at December 31 |
$ |
153 |
$ |
115 |
$ |
144 |
|||||
The total amount of unrecognized tax benefits as of December 31, 2010 that, if recognized, would affect the effective tax rate was $148 million. EME believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $9 million within the next 12 months.
Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 remain subject to audit.
Accrued Interest and Penalties
The total amount of accrued interest expense (income) and penalties was $32 million and $12 million as of December 31, 2010 and 2009, respectively. The total amount of interest expense (income) and penalties recognized in income tax expense was $13 million, $(45) million and $8 million for 2010, 2009 and 2008, respectively.
The Internal Revenue Service examination phase of Edison International's federal income tax returns for tax years 2003 through 2006 was completed in the fourth quarter of 2010, and a revenue agent report was issued. The revenue agent report includes the following EME item:
Edison International disagrees with the proposed adjustments and filed a protest with the Internal Revenue Service in 2011.
128
Note 8. Compensation and Benefit Plans
A 401(k) plan is maintained to supplement eligible employees' retirement income. The plan received contributions from EME of $14 million in 2010, $13 million in 2009 and $15 million in 2008.
Pension Plans and Postretirement Benefits Other than Pensions
Noncontributory defined benefit pension plans (the non-union plan has a cash balance feature) cover most employees meeting minimum service requirements. The expected contributions (all by the employer) are approximately $20 million for the year ended December 31, 2011.
Volatile market conditions have affected the value of the trusts established to fund its future long-term pension benefits. The market value of the investments (reflecting investment returns, contributions and benefit payments) within the plan trusts declined 35% during 2008. This reduction in the value of plan assets resulted in a change in the pension plan funding status from overfunded to underfunded and will also result in increased future expense and increased future contributions. Improved market conditions in 2010 and 2009 partially offset the impacts of the 2008 market conditions.
129
Information on plan assets and benefit obligations is shown below:
|
Years Ended December 31, | |||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
||||||
Change in projected benefit obligation |
||||||||
Projected benefit obligation at beginning of year |
$ | 243 | $ | 211 | ||||
Service cost |
16 | 15 | ||||||
Interest cost |
14 | 13 | ||||||
Actuarial loss |
22 | 10 | ||||||
Benefits paid |
(8 | ) | (6 | ) | ||||
Projected benefit obligation at end of year |
$ |
287 |
$ |
243 |
||||
Change in plan assets |
||||||||
Fair value of plan assets at beginning of year |
$ | 128 | $ | 99 | ||||
Actual return on plan assets |
20 | 25 | ||||||
Employer contributions |
24 | 10 | ||||||
Benefits paid |
(8 | ) | (6 | ) | ||||
Fair value of plan assets at end of year |
$ |
164 |
$ |
128 |
||||
Funded status at end of year |
$ |
(123 |
) |
$ |
(115 |
) |
||
Amounts recognized on consolidated balance sheets: |
||||||||
Long-term liabilities |
$ | (123 | ) | $ | (115 | ) | ||
Amounts recognized in accumulated other comprehensive income: |
||||||||
Prior service cost |
$ | 1 | $ | 1 | ||||
Net loss |
47 | 37 | ||||||
Accumulated benefit obligation at end of year |
$ |
245 |
$ |
204 |
||||
Pension plans with an accumulated benefit obligation in excess of plan assets: |
||||||||
Projected benefit obligation |
$ | 287 | $ | 243 | ||||
Accumulated benefit obligation |
245 | 204 | ||||||
Fair value of plan assets |
164 | 128 | ||||||
Weighted-average assumptions used to determine obligations at end of year: |
||||||||
Discount rate |
5.25% | 6.0% to 6.25% | ||||||
Rate of compensation increase |
4.5% to 6.0% | 5.0% to 6.0% | ||||||
130
Expense components and other amounts recognized in other comprehensive (income) loss
Expense components:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Service cost |
$ | 16 | $ | 15 | $ | 13 | ||||
Interest cost |
14 | 13 | 12 | |||||||
Expected return on plan assets |
(10 | ) | (8 | ) | (10 | ) | ||||
Net amortization |
2 | 4 | 1 | |||||||
Total expense |
$ |
22 |
$ |
24 |
$ |
16 |
||||
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Net loss (gain) |
$ | 12 | $ | (7 | ) | $ | 49 | |||
Prior service cost |
| | 1 | |||||||
Amortization of net loss |
(2 | ) | (4 | ) | (1 | ) | ||||
Total in other comprehensive (income) loss |
$ |
10 |
$ |
(11 |
) |
$ |
49 |
|||
Total in expense and other comprehensive (income) loss |
$ |
32 |
$ |
13 |
$ |
65 |
||||
The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2011 are $0.1 million for prior service costs and $3.5 million for net loss.
The following are weighted-average assumptions used to determine expenses:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||
Discount rate |
6.0% | 6.25% | 6.25% | |||||||
Rate of compensation increase |
4.5% to 6.0% | 5.0% to 6.0% | 5.0% | |||||||
Expected long-term return on plan assets |
7.5% | 7.5% | 7.5% | |||||||
The following are benefit payments, which reflect expected future service, expected to be paid:
Years Ending December 31, (in millions) |
|
|||
---|---|---|---|---|
2011 |
$ | 11 | ||
2012 |
13 | |||
2013 |
15 | |||
2014 |
17 | |||
2015 |
19 | |||
2016-2020 |
123 | |||
131
Postretirement Benefits Other Than Pensions
Non-union employees retiring at or after age 55 with at least 10 years of service may be eligible for postretirement medical, dental, vision, and life insurance coverage. Eligibility for a company contribution toward the cost of these benefits in retirement depends on a number of factors, including the employee's hire date. The expected contributions (all by the employer) for the postretirement benefits other than pensions are $2 million for the year ended December 31, 2011.
Information on plan assets and benefit obligations is shown below:
|
Years Ended December 31, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Change in benefit obligation |
|||||||
Benefit obligation at beginning of year |
$ | 94 | $ | 99 | |||
Service cost |
2 | 2 | |||||
Interest cost |
5 | 5 | |||||
Amendments |
11 | (2 | ) | ||||
Actuarial (gain) loss |
12 | (8 | ) | ||||
Benefits paid |
(2 | ) | (2 | ) | |||
Benefit obligation at end of year |
$ |
122 |
$ |
94 |
|||
Change in plan assets |
|||||||
Fair value of plan assets at beginning of year |
$ | | $ | | |||
Employer contributions |
2 | 2 | |||||
Benefits paid |
(2 | ) | (2 | ) | |||
Fair value of plan assets at end of year |
$ |
|
$ |
|
|||
Funded status at end of year |
$ |
(122 |
) |
$ |
(94 |
) |
|
Amounts recognized on consolidated balance sheets: |
|||||||
Long-term liabilities |
$ | (122 | ) | $ | (94 | ) | |
Amounts recognized in accumulated other comprehensive income: |
|||||||
Prior service cost (credit) |
$ | 8 | $ | (4 | ) | ||
Net loss |
23 | 11 | |||||
Weighted-average assumptions used to determine obligations at end of year: |
|||||||
Discount rate |
5.5% | 6.0% | |||||
Assumed health care cost trend rates: |
|||||||
Rate assumed for following year |
9.75% | 8.25% | |||||
Ultimate rate |
5.5% | 5.5% | |||||
Year ultimate rate reached |
2019 | 2016 | |||||
132
Expense components and other amounts recognized in other comprehensive (income) loss
Expense components:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Service cost |
$ | 2 | $ | 2 | $ | 3 | ||||
Interest cost |
6 | 5 | 6 | |||||||
Amortization of prior service credit |
(2 | ) | (1 | ) | (2 | ) | ||||
Amortization of net loss |
1 | 1 | 1 | |||||||
Total expense |
$ | 7 | $ | 7 | $ | 8 | ||||
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Net loss (gain) |
$ | 12 | $ | (8 | ) | $ | 18 | |||
Prior service cost (credit) |
11 | (2 | ) | (6 | ) | |||||
Amortization of prior service credit |
1 | 1 | 3 | |||||||
Amortization of net loss |
(1 | ) | (1 | ) | (3 | ) | ||||
Total in other comprehensive (income) loss |
$ | 23 | $ | (10 | ) | $ | 12 | |||
Total in expense and other comprehensive (income) loss |
$ | 30 | $ | (3 | ) | $ | 20 | |||
The estimated amortization amounts expected to be reclassified from other comprehensive (income) loss for 2011 are $0.7 million for prior service credit and $1.2 million for net loss.
The following are weighted-average assumptions used to determine expense:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||
Discount rate |
6.0% | 6.25% | 6.25% | |||||||
Assumed health care cost trend rates: |
||||||||||
Current year |
8.25% | 8.75% | 9.25% | |||||||
Ultimate rate |
5.5% | 5.5% | 5.0% | |||||||
Year ultimate rate reached |
2016 | 2016 | 2015 | |||||||
Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of December 31, 2010, by $21 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated benefit obligation as of December 31, 2010, by $18 million and annual aggregate service and interest costs by $1 million.
133
The following benefit payments are expected to be paid:
Years Ending December 31, (in millions) |
Before Subsidy1 |
Net |
|||||
---|---|---|---|---|---|---|---|
2011 |
$ | 2 | $ | 2 | |||
2012 |
3 | 3 | |||||
2013 |
4 | 4 | |||||
2014 |
4 | 4 | |||||
2015 |
5 | 5 | |||||
2016-2020 |
39 | 37 | |||||
The discount rate enables EME to state expected future cash flows at a present value on the measurement date. EME selects its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. Two corporate yield curves were considered, Citigroup and AON.
Description of Pension and Postretirement Benefits Other Than Pensions Investment Strategies
The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active and passive investment strategies within asset classes. Target allocations for pension plan assets are 30% for United States equities, 16% for non-United States equities, 35% for fixed income, 15% for opportunistic and/or alternative investments and 4% for other investments. Edison International employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches. Risk is managed through diversification among multiple asset classes, managers, styles and securities. Plan, asset class and individual manager performance are measured against targets. Edison International also monitors the stability of its investments managers' organizations.
Allowable investment types include:
134
Asset class portfolio weights are permitted to range within plus or minus 3%. Where approved by the fiduciary investment committee, futures contracts are used for portfolio rebalancing and to reallocate portfolio cash positions. Where authorized, a few of the plans' investment managers employ limited use of derivatives, including futures contracts, options, options on futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.
Determination of the Expected Long-Term Rate of Return on Assets
The overall expected long-term rate of return on assets assumption is based on the long-term target asset allocation for plan assets and capital markets return forecasts for asset classes employed.
Capital Markets Return Forecasts
Capital markets return forecasts are based on long-term strategic planning assumptions from an independent firm which uses its research, modeling and judgment to forecast rates of return for global asset classes. In addition, a separate analysis of expected returns is conducted. The estimated total return for fixed income securities is based on historic long-term United States government bonds data. The estimated total return for intermediate United States government bonds is based on historic and projected data. The estimated rate of return for United States equities, non-United States equities and hedge funds includes a 3% premium over the estimated total return for intermediate United States government bonds. The rate of return for private equity is estimated to be a 3% premium over public equity, reflecting a premium for higher volatility and illiquidity.
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
135
that are less active and transparent. The fair value of the underlying investments in equity mutual funds and equity common/collective funds are based upon stock-exchange prices. The fair value of the underlying investments in fixed-income common/collective funds, fixed-income mutual funds and other fixed income securities including municipal bonds are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. Foreign exchange and interest rate contracts are classified as Level 2 because the values are based on observable prices but are not traded on an exchange. Future contracts trade on an exchange and therefore classified as Level 1. One of the partnerships is classified as Level 2 since this investment can be readily redeemed at NAV and the underlying investments are liquid publicly traded fixed-income securities which have observable prices. The remaining partnerships/joint ventures are classified as Level 3 because fair value is determined primarily based upon management estimates of future cash flows. Other investment entities are valued similarly to common collective funds and are, therefore, classified as Level 2. The Level 1 registered investment companies are either mutual or money market funds. The remaining funds in this category are readily redeemable at NAV and classified as Level 2 and are discussed further in footnote 6 to the pension plan master trust investments table below.
The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2010 by asset class and level within the fair value hierarchy:
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Total |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Corporate stocks1 |
$ | 786 | $ | | $ | | $ | 786 | |||||
Common/collective funds2 |
| 600 | | 600 | |||||||||
Corporate bonds3 |
| 555 | | 555 | |||||||||
Partnerships/joint ventures4 |
| 155 | 345 | 500 | |||||||||
U.S. government and agency securities5 |
84 | 316 | | 400 | |||||||||
Registered investment companies6 |
84 | 169 | | 253 | |||||||||
Other investment entities7 |
| 159 | | 159 | |||||||||
Interest-bearing cash |
5 | | | 5 | |||||||||
Other |
2 | 30 | | 32 | |||||||||
Total |
$ | 961 | $ | 1,984 | $ | 345 | $ | 3,290 | |||||
Receivables and payables, net |
(55 | ) | |||||||||||
Net plan assets available for benefits |
3,235 | ||||||||||||
EME's share of net plan assets |
$ | 164 | |||||||||||
136
The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2009 by asset class and level within the fair value hierarchy:
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Total |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Corporate stocks1 |
$ | 678 | $ | | $ | | $ | 678 | |||||
Common/collective funds2 |
| 612 | | 612 | |||||||||
Corporate bonds3 |
| 469 | | 469 | |||||||||
Partnerships/joint ventures4 |
| 101 | 240 | 341 | |||||||||
U.S. government and agency |
104 | 352 | | 456 | |||||||||
Registered investment companies6 |
73 | 58 | | 131 | |||||||||
Other investment entities7 |
| 135 | | 135 | |||||||||
Interest-bearing cash |
5 | | | 5 | |||||||||
Foreign exchange contracts |
| 6 | | 6 | |||||||||
Other |
| 7 | | 7 | |||||||||
Total |
$ | 860 | $ | 1,740 | $ | 240 | $ | 2,840 | |||||
Receivables and payables, net |
17 | ||||||||||||
Net plan assets available for benefits |
2,857 | ||||||||||||
EME's share of net plan assets |
$ | 128 | |||||||||||
137
At December 31, 2010 and 2009, approximately 69% and 67%, respectively, of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.
The following table sets forth a summary of changes in the fair value of Level 3 investments for 2010 and 2009:
(in millions) |
2010 |
2009 |
||||||
---|---|---|---|---|---|---|---|---|
Fair value, net at beginning of period |
$ | 240 | $ | 111 | ||||
Actual return on plan assets: |
||||||||
Relating to assets still held at end of period |
42 | 34 | ||||||
Relating to assets sold during the period |
24 | 6 | ||||||
Purchases and dispositions, net |
39 | 89 | ||||||
Transfers in and/or out of Level 3 |
| | ||||||
Fair value, net at end of period |
$ | 345 | $ | 240 | ||||
Edison International maintains a shareholder-approved incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. The maximum number of shares of Edison International's common stock authorized to be issued or transferred pursuant to awards under the 2007 Performance Incentive Plan, as amended in 2009, is 21.5 million shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued (carry-over shares). As of December 31, 2010, Edison International had approximately 9 million shares remaining for future issuance under its stock-based compensation plans.
Under various plans, Edison International has granted stock options at exercise prices equal to the average of the high and low price, and beginning in 2007, at the closing price at the grant date, Edison International may grant stock options and other awards related to or with a value derived from its common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the requisite service period, except for awards granted to retirement-eligible participants, as discussed in Note 1Stock-Based Compensation.
Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the option term. Stock options granted in 2007 and later have no dividend equivalent rights except for options granted to Edison International's Board of Directors in 2007. Unless transferred to nonqualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.
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The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||
Expected terms (in years) |
7.3 | 7.4 | 7.4 | |||||||
Risk-free interest rate |
2.0% to 3.2% | 2.8% to 3.5% | 2.6% to 3.8% | |||||||
Expected dividend yield |
3.3% to 4.0% | 3.6% to 5.0% | 2.3% to 3.9% | |||||||
Weighted-average expected dividend yield |
3.8% | 5.0% | 2.5% | |||||||
Expected volatility |
19% to 20% | 20% to 21% | 17% to 19% | |||||||
Weighted-average volatility |
19.8% | 20.6% | 17.4% | |||||||
The expected term represents the period of time for which the options are expected to be outstanding and is primarily based on historical exercise and post-vesting cancellation experience and stock price history. The risk-free interest rate for periods within the contractual life of the option is based on a zero coupon U.S. Treasury issued STRIPS (separate trading of registered interest and principal of securities) whose maturity equals the option's expected term on the measurement date. Expected volatility is based on the historical volatility of Edison International's common stock for the lesser of 1) the period from January 1, 2003 through the last month-end prior to the grant date, or 2) the length of the options expected term. The volatility period used was 87 months, 84 months and 72 months at December 31, 2010, 2009 and 2008, respectively.
A summary of the status of Edison International's stock options granted to EME employees is as follows:
|
|
Weighted-Average | |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Stock Options |
Exercise Price |
Remaining Contractual Term (Years) |
Aggregate Intrinsic Value |
|||||||||
Outstanding, December 31, 2009 |
3,144,531 | $ | 31.49 | ||||||||||
Granted |
724,657 | 33.30 | |||||||||||
Expired |
(19,840 | ) | 45.66 | ||||||||||
Transferred from affiliates |
36,593 | 34.28 | |||||||||||
Forfeited |
(127,080 | ) | 30.48 | ||||||||||
Exercised |
(266,424 | ) | 22.11 | ||||||||||
Outstanding, December 31, 2010 |
3,492,437 | 32.57 | 6.04 | ||||||||||
Vested and expected to vest at December 31, 2010 |
3,401,045 | 32.58 | 5.98 | $ | 28,797,824 | ||||||||
Exercisable at December 31, 2010 |
1,923,233 | 32.98 | 4.24 | 16,833,610 | |||||||||
At December 31, 2010, there was $4 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately two-and-a-half years.
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A target number of contingent performance shares were awarded to executives in March 2008, March 2009 and March 2010, and vest at the end of December 2010, 2011 and 2012, respectively. Performance shares awarded contain dividend equivalent reinvestment rights. An additional number of target contingent performance shares will be credited based on dividends on Edison International common stock for which the ex-dividend date falls within the performance period. The vesting of Edison International's performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International's total shareholder return relative to the total shareholder return of a specified group of peer companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International's ranking among these companies. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Edison International also has discretion to pay certain dividend equivalents in Edison International common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares that can be settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the requisite service period based on the fair values determined, except for awards granted to retirement-eligible participants.
The fair value of performance shares is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires various assumptions noted in the following table:
|
Years Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||||
Equity awards |
||||||||||||
Grant date risk-free interest rate |
1.3 | % | 1.3 | % | 3.9 | % | ||||||
Grant date expected volatility |
21.6 | % | 21.4 | % | 17.4 | % | ||||||
Liability awards1 |
||||||||||||
Expected volatility |
20.6 | % | 21.9 | % | 19.2 | % | ||||||
Risk-free interest rate |
||||||||||||
2010 awards |
0.6 | % | | | ||||||||
2009 awards |
0.3 | % | 1.1 | % | | |||||||
2008 awards |
| 0.5 | % | 0.8 | % | |||||||
The risk-free interest rate is based on the daily spot rate on the grant or valuation date on U.S. Treasury zero coupon issue or STRIPS (separate trading of registered interest and principal of securities) with terms nearest to the remaining term of the performance shares
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and is used as proxy for the expected return for the specified group of peer companies. Expected volatility is based on the historical volatility of Edison International's (and the specified group of peer companies') common stock for the most recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data services provider.
At December 31, 2010, there was $0.7 million (based on the December 31, 2010 fair value of performance shares classified as equity awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.
A summary of the status of Edison International nonvested performance shares granted to EME employees is as follows:
|
Equity Awards | Liability Awards | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Shares |
Weighted- Average Grant- Date Fair Value |
Shares |
Weighted- Average Fair Value |
|||||||||
Nonvested at December 31, 2009 |
70,408 | $ | 33.04 | 70,408 | |||||||||
Granted |
27,437 | 32.50 | 27,437 | ||||||||||
Forfeited |
(14,449 | ) | 50.87 | (14,449 | ) | ||||||||
Transferred from affiliates |
354 | 45.17 | 354 | ||||||||||
Nonvested at December 31, 2010 |
83,750 | 29.84 | 83,750 | $ | 34.18 | ||||||||
Restricted stock units were awarded to executives in March 2008, March 2009 and March 2010 and vest and become payable in January 2011, 2012 and 2013, respectively. Each restricted stock unit awarded is a contractual right to receive one share of Edison International common stock, if vesting requirements are satisfied. Restricted stock units awarded contain dividend equivalent reinvestment rights. An additional number of restricted stock units will be credited based on dividends on Edison International common stock for which the ex-dividend date falls within the performance period. The vesting of Edison International's restricted stock units is dependent upon continuous service through the end of the three-calendar-year-plus-two-days vesting period. Vesting is subject to a pro-rated adjustment for employees who are terminated under certain circumstances or retire. Cash awards are substituted to the extent necessary to pay tax withholding or any government levies.
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The following is a summary of the status of Edison International nonvested restricted stock units granted to EME employees:
|
Restricted Stock Units |
Weighted-Average Grant-Date Fair Value |
|||||
---|---|---|---|---|---|---|---|
Nonvested at December 31, 2009 |
101,073 | $ | 34.00 | ||||
Granted |
53,558 | 33.30 | |||||
Forfeited |
(6,762 | ) | 31.73 | ||||
Paid Out |
(21,898 | ) | 47.29 | ||||
Affiliate transfersnet |
1,421 | 38.91 | |||||
Nonvested at December 31, 2010 |
127,392 | 32.23 | |||||
The fair value for each restricted stock unit awarded is determined as the closing price of Edison International common stock on the grant date.
Compensation expense related to these shares, which is based on the grant-date fair value, is recognized ratably over the requisite service period, except for awards whose holders become eligible for retirement vesting during the service period, in which case recognition is accelerated into the year the holders become eligible for retirement vesting. At December 31, 2010, there was $2 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $1 million in 2011 and $1 million in 2012.
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Supplemental Data on Stock-Based Compensation
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions, except per award amounts) |
2010 |
2009 |
2008 |
||||||||
Stock-based compensation expense (benefit)1 |
|||||||||||
Stock options |
$ | 4 | $ | 3 | $ | 6 | |||||
Performance shares |
2 | 1 | (3 | ) | |||||||
Restricted stock units |
1 | 1 | 1 | ||||||||
Other |
2 | 3 | 3 | ||||||||
Total stock-based compensation expense (benefit) |
$ | 9 | $ | 8 | $ | 7 | |||||
Income tax benefits related to stock compensation expense |
$ | 4 | $ | 3 | $ | 3 | |||||
Excess tax benefits2 |
1 | | 3 | ||||||||
Stock options |
|||||||||||
Weighted average grant date fair value per option granted |
$ | 4.92 | $ | 3.00 | $ | 9.88 | |||||
Fair value of options vested |
3 | 3 | 4 | ||||||||
Cash used to purchase shares to settle options |
11 | 1 | 11 | ||||||||
Cash from participants to exercise stock options |
6 | 1 | 5 | ||||||||
Value of options exercised |
4 | 0.4 | 6 | ||||||||
Tax benefits from options exercised |
2 | 0.2 | 2 | ||||||||
Performance shares classified as equity awards |
|||||||||||
Weighted average grant date fair value per share granted |
$ | 32.50 | $ | 21.06 | $ | 41.25 | |||||
Fair value of shares vested |
0.9 | 0.2 | 0.7 | ||||||||
Value of shares settled |
| | 3 | ||||||||
Tax benefits realized from settlement of awards |
| | 1 | ||||||||
Performance shares classified as liability awards |
|||||||||||
Value of shares settled |
$ | | $ | | $ | 2 | |||||
Tax benefits realized from settlement of awards |
| | 1 | ||||||||
Restricted stock units3 |
|||||||||||
Weighted average grant date fair value per unit granted |
$ | 33.30 | $ | 24.99 | $ | 48.66 | |||||
Note 9. Commitments and Contingencies
Power Plant and Other Lease Commitments
EME leases office space, property and equipment under noncancelable lease agreements that expire in various years through 2037.
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Future minimum payments for operating leases at December 31, 2010 are:
Years Ending December 31, (in millions) |
Homer City Plant |
Powerton and Joliet Power Facilities |
Other Operating Leases |
|||||||
---|---|---|---|---|---|---|---|---|---|---|
2011 |
$ | 161 | $ | 151 | $ | 27 | ||||
2012 |
160 | 151 | 24 | |||||||
2013 |
149 | 151 | 29 | |||||||
2014 |
138 | 151 | 17 | |||||||
2015 |
107 | 67 | 16 | |||||||
Thereafter |
1,260 | 267 | 140 | |||||||
Total future commitments |
$ | 1,975 | $ | 938 | $ | 253 | ||||
The minimum commitments do not include contingent rentals with respect to the wind projects which may be paid under certain leases on the basis of a percentage of sales calculation if this is in excess of the stipulated minimum amount.
Operating lease expense amounted to $217 million, $209 million and $208 million in 2010, 2009 and 2008, respectively.
On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City plant to third-party lessors. Under the terms of the 33.67-year leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City plant, EME has a right of first refusal to acquire the interest at fair market value. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.
On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power facilities located in Illinois to third-party lessors. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EME's subsidiary makes semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, EME has a right of first refusal to acquire the interest at fair market value. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases.
Under the terms of the foregoing sale-leaseback transactions, distributions are restricted by EME's subsidiaries unless specified financial covenants are met. At December 31, 2010, EME's subsidiaries met these covenants. In addition, the lease agreements and the Midwest Generation credit agreement contain covenants that include, among other things, restrictions on the ability of these subsidiaries to incur debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines of business, or engage in transactions for any speculative purpose.
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Certain other minimum commitments are estimated as follows:
(in millions) |
2011 |
2012 |
2013 |
2014 |
2015 |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Fuel supply contracts |
$ | 482 | $ | 250 | $ | 33 | $ | | $ | | ||||||
Coal transportation agreements |
231 | | | | | |||||||||||
Gas transportation agreements |
8 | 8 | 8 | 9 | 8 | |||||||||||
Capital expenditures |
182 | | | | | |||||||||||
Turbine commitments |
90 | | | | | |||||||||||
Other contractual obligations |
85 | 72 | 31 | 5 | 3 | |||||||||||
|
$ | 1,078 | $ | 330 | $ | 72 | $ | 14 | $ | 11 | ||||||
At December 31, 2010, Midwest Generation and Homer City had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. In January 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments, together with estimated transportation costs under existing agreements, total $34 million for 2011.
In connection with the acquisition of the Midwest Generation plants, Midwest Generation assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during 2008 reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statements of income.
Coal Transportation Agreements
At December 31, 2010, Midwest Generation and Homer City had contractual agreements for the transportation of coal. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts.
At December 31, 2010, EME had a contractual commitment to transport natural gas. EME's share of the commitment to pay minimum fees under its gas transportation agreement, which has a remaining contract length of seven years, is estimated to aggregate $41 million in the next five years. EME has entered into agreements to re-sell the transportation under this agreement which aggregates $50 million over the same period.
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At December 31, 2010, EME's subsidiaries had firm commitments for capital and construction expenditures primarily related to selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants and the construction of wind projects. EME intends to fund these expenditures through project-level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations. EME has secured $394 million in wind project financing and anticipated U.S. Treasury grants. For further discussion, see Note 5Debt and Credit Agreements.
To support its renewable program, EME has entered into several agreements for the purchase of turbines. Under one of these agreements, EME's failure to schedule turbine delivery by June 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $21 million charge against earnings. EME has identified a project in which to place these turbines. However, development is not complete, and EME cannot be assured that this project will be constructed.
On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EME against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EME committed to purchase on amended terms 23 wind turbines (aggregating 55 MW), agreed to certain price adjustments on the turbines purchased under the original contract, may elect to deploy up to 60 additional wind turbines (aggregating 144 MW) that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. EME made payments of $20 million and further agreed to payments up to $20 million for settlement of remaining disputes related to turbines purchased.
At December 31, 2010, EME and its subsidiaries were party to turbine operations and maintenance agreements, agreements for the purchase of materials used in the operation of environmental controls equipment and a coal cleaning agreement.
EME and certain of its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, guarantees of debt and indemnifications.
Environmental Indemnities Related to the Midwest Generation Plants
In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company (Commonwealth Edison) with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The
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indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "ContingenciesMidwest Generation New Source Review Lawsuit." Except as discussed below, EME has not recorded a liability related to these environmental indemnities.
Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 223 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2010. While the range of this liability is between $46 million and $67 million , Midwest Generation had recorded a $56 million and $50 million liability at December 31, 2010 and 2009, respectively, for previous, pending and future claims.
The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.
Environmental Indemnity Related to the Homer City Plant
In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity
147
provisions, they are not subject to a maximum potential liability and do not have expiration dates. For discussion of the New Source Review lawsuit filed against Homer City, see "ContingenciesHomer City New Source Review Lawsuit." EME has not recorded a liability related to this indemnity.
Indemnities Provided under Asset Sale and Sale-Leaseback Agreements
The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At December 31, 2010 and 2009, EME had recorded a liability of $42 million (of which $3 million is classified as a current liability) and $96 million, respectively, related to these matters.
In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the assets prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined.
Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. No significant amounts are recorded as a liability for these matters.
In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. No significant amounts are recorded as a liability for these matters.
With respect to potential liabilities arising under CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $3 million at December 31, 2010 for estimated environmental investigation and
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remediation costs for the Midwest Generation plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that require remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future remediation costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.
Midwest Generation New Source Review Lawsuit
In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration (PSD) requirements and of the New Source Performance Standards of the Clean Air Act (CAA), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology (BACT) emissions rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review (NSR) permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard (CPS). Several Chicago-based environmental action groups have intervened in the case.
Nine of the ten counts related to PSD requirements in the complaint were dismissed in March 2010, and the tenth count was also dismissed to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The court did not address (i) other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA, or (ii) the complaint in intervention filed by the Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.
In June 2010, the US EPA, the State of Illinois, and several environmental action groups filed amended complaints similar to the prior complaints, but also seeking to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. Midwest Generation, EME and Commonwealth Edison have filed a motion to dismiss the amended complaints.
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An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.
Homer City New Source Review Lawsuit
In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleges violations of the PSD and Title V provisions of the CAA and its implementing regulations, including requirements contained in the Pennsylvania State Implementation Plan. The PSD counts allege that the prior owners of the Homer City plant performed projects in the 1990s that triggered state and federal PSD permitting requirements by increasing emissions of sulfur dioxide and/or particulate matter. All defendants are alleged to have failed to comply with the PSD permitting requirements for those projects. The complaint also alleges that, as a result of triggering PSD permitting requirements, including the requirement to install controls sufficient to meet BACT emissions rates for sulfur dioxide and/or particulate matter, the owners and operators have been required, but have failed, to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint calls for an injunction ordering Homer City to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or NSR permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. Pennsylvania Department of Environmental Protection (PADEP), the State of New York and the State of New Jersey have intervened in the lawsuit.
Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, Mission Energy Holding Company, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs seek to have their suit certified as a class action and request injunctive relief, the funding of a health assessment study and medical monitoring, compensatory and punitive damages.
An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.
At December 31, 2010 and 2009, EME's subsidiaries had a $10 million receivable each year recorded primarily related to insurance claims from unplanned outages. During 2009 and 2008, $2 million and $6 million, respectively, related to business interruption insurance
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coverage were recorded and have been reflected in other income (expense), net on EME's consolidated statements of income. EME's subsidiaries received $17 million and $9 million in cash payments related to insurance claims during 2010 and 2009, respectively.
Note 10. Environmental Developments
Midwest Generation Environmental Compliance Plans and Costs
During 2010, Midwest Generation continued its permitting and planning activities for nitrogen oxide (NOx) and sulfur dioxide (SO2) controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois Environmental Protection Agency (Illinois EPA) to allow the installation of SNCR technology on multiple units to meet the NOx portion of the CPS. In November 2010 and February 2011, the Illinois EPA issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or its equivalent at the Waukegan generating station's Unit 7 and Units 5 and 6 at the Powerton Station. The permit for Unit 7 at the Waukegan Station also authorizes Midwest Generation to convert the existing electrostatic precipitator to a cold-side design which will improve removal efficiency of particulate matter to satisfy the particulate control requirements of the CPS.
Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO2 emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time than the use of spray dryer absorber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs.
Based on work to date, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, and the associated upgrading of existing particulate removal systems, would be approximately $1.2 billion in 2010 dollars. If these projects are undertaken, these expenditures would be incurred through 2018.
Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project.
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Homer City Environmental Issues and Capital Resource Limitations
Homer City may be required to install additional environmental equipment on Units 1 and 2 to comply with environmental regulations under the Clean Air Transport Rule (Transport Rule) described below. Homer City projects that if SO2 reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO2 and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. The installation of environmental compliance equipment will be dependent on lessor decisions regarding the funding of these expenditures. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. EME has no legal obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made.
There have been a number of federal and state legislative and regulatory initiatives to reduce greenhouse gas (GHG) emissions. Any climate change regulation or other legal obligation that would require substantial reductions in GHG emissions or that would impose additional costs or charges for the GHG emissions could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, as well as the cost of purchased power, which could adversely affect EME's business.
Significant developments include the following:
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program itself are being challenged by various citizens' groups under the California Environmental Quality Act.
In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to reduce power plant emissions of NOx and SO2 substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule.
The Transport Rule is scheduled to be finalized in 2011. Depending on the approach to emissions allowance trading and allocation adopted by the US EPA, the Transport Rule may provide allowance allocations which are adequate for the plants' needs or may require the Midwest Generation plants to procure additional allowances, based on projected emissions using the Illinois CPS allowable emission rates. The Transport Rule may require the installation of additional environmental equipment to reduce SO2 emissions at Units 1 and 2 of the Homer City facilities and, depending on the approach adopted, may also require Homer City to procure a significant amount of additional allowances or curtail operations if it is unable to do so on acceptable terms.
Hazardous Air Pollutant Regulations
In accordance with a consent decree entered in April 2010, the US EPA committed to proposing regulations by March 2011 limiting emissions of Hazardous Air Pollutants (HAPs) from coal- and oil-fired electrical generating units that are major sources of HAPs, and to finalizing such regulations by November 2011. The emissions standards must be designed to achieve the maximum degree of emission reduction that the US EPA determines is achievable for the affected units, taking into account costs and non-air quality environmental and health benefits (also referred to as maximum available control technology, or MACT standard). Unlike the Clean Air Mercury Rule, the US EPA must regulate all of the HAPs emitted by these generating units. Compliance with the MACT standards will be required three years after the effective date of the final regulations. Until the US EPA's regulations are finalized, EME cannot determine whether the actions it is taking to comply with other legal requirements (including the CPS) will be sufficient to address its obligations under the new regulations.
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Regulations under the federal Clean Water Act govern critical parameters at generating facilities, such as the temperature of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. The US EPA is rewriting these regulations following a 2009 U.S. Supreme Court decision that held that the US EPA may consider, but is not required to use, a cost-benefit analysis for this purpose. The Supreme Court set a deadline of March 2011 for draft regulations, which are to be finalized by July 2011. The new regulations will not allow the use of restoration to achieve compliance, but it is unknown whether they will use a cost-benefit analysis for determining the best technology available for compliance.
A new rule could have a material impact on EME's operations but EME cannot determine the financial impact until the final compliance criteria have been published. Significant capital expenditures may be required.
US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from hazardous waste requirements. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals. Two different proposed approaches are under consideration. If the US EPA lists these residuals as special wastes subject to regulation as hazardous wastes, as proposed under one alternative, could require EME to incur additional capital and operating costs without assurance that the additional costs could be recovered.
Note 11. Accumulated Other Comprehensive Income
Accumulated other comprehensive income consisted of the following:
(in millions) |
Unrealized Gains on Cash Flow Hedges |
Unrecognized Losses and Prior Service Adjustments, Net1 |
Accumulated Other Comprehensive Income |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2008 |
$ | 240 | $ | (40 | ) | $ | 200 | ||||
Change for 2009 |
(135 | ) | 13 | (122 | ) | ||||||
Balance at December 31, 2009 |
105 | (27 | ) | 78 | |||||||
Change for 2010 |
(89 | ) | (20 | ) | (109 | ) | |||||
Balance at December 31, 2010 |
$ | 16 | $ | (47 | ) | $ | (31 | ) | |||
Included in accumulated other comprehensive income at December 31, 2010 was $26 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $10 million, net of
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tax, of unrealized losses related to interest rate hedges. The maximum period over which an interest rate hedge is designated is through March 31, 2026. The maximum period over which a commodity cash flow hedge is designated is through May 31, 2014.
Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $26 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.
Note 12. Supplemental Cash Flows Information
|
Years Ended December 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
||||||||
Cash paid (received) |
|||||||||||
Interest (net of amount capitalized) |
$ | 239 | $ | 301 | $ | 295 | |||||
Income taxes |
(96 | ) | (131 | ) | 120 | ||||||
Cash payments under plant operating leases |
325 | 336 | 337 | ||||||||
Details of assets acquired |
|||||||||||
Fair value of assets acquired |
$ | 1 | $ | 14 | $ | | |||||
Liabilities assumed |
| 3 | | ||||||||
Net assets acquired |
$ | 1 | $ | 11 | $ | | |||||
Non-cash activities from consolidation of variable |
|||||||||||
Assets |
$ | 94 | $ | 3 | $ | 3 | |||||
Liabilities |
99 | 4 | 4 | ||||||||
Non-cash activities from deconsolidation of variable |
|||||||||||
Assets |
$ | 249 | $ | | $ | | |||||
Liabilities |
253 | | | ||||||||
In connection with certain wind projects acquired during the past four years, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments or made payments that were due upon commencement of construction and/or completion of construction scheduled during 2007 through 2011.
EME reduced approximately 75 positions in its regional and corporate offices in April 2009 and recorded charges of approximately $5 million (pre-tax) in 2009 included in administrative and general expense on EME's consolidated statements of income.
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Summarized financial information for discontinued operations is as follows:
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2008 |
|||||||
Income (loss) before income taxes |
$ | 13 | $ | (9 | ) | $ | 6 | |||
Provision (benefit) for income taxes |
9 | (2 | ) | 5 | ||||||
Income (loss) from operations of discontinued foreign |
$ | 4 | $ | (7 | ) | $ | 1 | |||
Tax indemnity payments of $41 million were made in 2010 related to EME's previous sale of an international project. EME recorded discontinued operations income before taxes of $13 million due primarily to expiration of a contract indemnity during 2010 and changes in foreign exchange rates.
In 2009, EME increased its estimated liability for a tax indemnity related to EME's previous sale of an international project by $6 million and recognized foreign exchange losses and interest related to such tax indemnity.
Note 15. Related-Party Transactions
Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or SCE employees, are shared among all affiliates of Edison International, and the costs of these corporate support services are allocated to all affiliates, including EME. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). In addition, services of Edison International or SCE employees are sometimes directly requested by EME and these services are performed for EME's benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. EME believes the allocation methodologies utilized are reasonable. EME made reimbursements for the cost of these programs and other services, which amounted to $52 million, $55 million and $66 million in 2010, 2009 and 2008, respectively. At December 31, 2010 and 2009, the amount due to Edison International was $13 million and $14 million, respectively.
EME participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. EME's insurance premiums are generally based on EME's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International.
Edison Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission
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Operation & Maintenance is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities and may also earn incentive compensation as set forth in the agreements. EME has investments in wind projects that are accounted for under the equity method for which Edison Mission Operation & Maintenance has entered into operation and maintenance agreements to provide operation and maintenance services for the wind facilities. EME recorded revenues under the operation and maintenance agreements of $23 million for 2010, $26 million for 2009 and $28 million for 2008, reflected in operating revenues on EME's consolidated statements of income. Receivables from affiliates for Edison Mission Operation & Maintenance totaled $5 million and $6 million at December 31, 2010 and 2009, respectively.
EME owns interests in partnerships that sell electricity generated by their project facilities to SCE and others under the terms of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $367 million, $366 million and $686 million in 2010, 2009 and 2008, respectively.
Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a 10-year power sales contract starting in 2013 for the output of a 479 MW gas-fired peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. Construction of the Walnut Creek project cannot begin until offsets for particulate matter (of 10 micrometers or less) and SO2 emissions required by its permits have been obtained. The capital costs to construct this project, if built, excluding interest, are estimated in the range of $500 million to $600 million over a period of 28 months. During 2008, EME recorded a $23 million charge related to the termination of a turbine supply agreement in connection with the Walnut Creek project reflected in "Asset write-downs, gain on buyout of contract and loss on termination of contract, net" on EME's consolidated statement of income.
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Note 16. Quarterly Financial Data (unaudited)
(in millions) |
First |
Second |
Third |
Fourth |
Total |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
2010 |
|||||||||||||||||
Operating revenues |
$ | 651 | $ | 493 | $ | 691 | $ | 588 | $ | 2,423 | |||||||
Operating income (loss) |
130 | (46 | ) | 179 | 44 | 307 | |||||||||||
Income (loss) from continuing |
75 | (20 | ) | 118 | (14 | ) | 159 | ||||||||||
Income (loss) from operations of |
6 | 3 | (5 | ) | | 4 | |||||||||||
Net income (loss) |
81 | (17 | ) | 113 | (14 | )1 | 163 | ||||||||||
2009 |
|||||||||||||||||
Operating revenues |
$ | 612 | $ | 557 | $ | 593 | $ | 615 | $ | 2,377 | |||||||
Operating income |
131 | 88 | 80 | 90 | 389 | ||||||||||||
Income from continuing operations |
53 | 46 | 53 | 49 | 201 | ||||||||||||
Income (loss) from operations of |
3 | (7 | ) | (1 | ) | (2 | ) | (7 | ) | ||||||||
Net income |
56 | 39 | 52 | 47 | 194 | ||||||||||||
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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Omitted pursuant to General Instruction I.(2)(c).
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to General Instruction I.(2)(c).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Omitted pursuant to General Instruction I.(2)(c).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Omitted pursuant to General Instruction I.(2)(c).
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
INDEPENDENT ACCOUNTANT FEES
The following table sets forth the aggregate fees billed to EME (consolidated total including EME and its subsidiaries), for the fiscal years ended December 31, 2010 and December 31, 2009, by PricewaterhouseCoopers LLP:
|
EME and Subsidiaries | ||||||
---|---|---|---|---|---|---|---|
($000) |
2010 |
2009 |
|||||
Audit fees |
$ | 3,178 | $ | 2,962 | |||
Audit related fees1 |
53 | 197 | |||||
Tax fees2 |
343 | 385 | |||||
All other fees |
| | |||||
Total |
$ | 3,574 | $ | 3,544 | |||
The Edison International Audit Committee reviews with management and pre-approves all audit services to be performed by the independent accountants and all non-audit services that are not prohibited and that require pre-approval under the Securities Exchange Act. The Edison International Audit Committee's pre-approval responsibilities may be delegated to one or more Edison International Audit Committee members, provided that such delegate(s) presents any pre-approval decisions to the Edison International Audit Committee at its next
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meeting. The Committee has delegated such pre-approval responsibilities to the Committee Chair. The independent auditors must assure that all audit and non-audit services provided to EME and its subsidiaries have been approved by the Edison International Audit Committee.
During the fiscal year ended December 31, 2010, all services performed by the independent accountants were pre-approved by the Edison International Audit Committee, regardless of whether the services required pre-approval under the Securities Exchange Act.
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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents have been filed as part of this report or, where noted, incorporated by reference:
See Index to Consolidated Financial Statements at Item 8 of this report.
The following financial statement schedules are included in this report:
All other schedules have been omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
The exhibit list below is incorporated herein by reference as the list of exhibits required as part of this report.
The agreements included or incorporated by reference as exhibits to this report contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of "materiality" that are different from "materiality" under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
EME acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this report not misleading.
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Exhibit No. |
Description |
||
---|---|---|---|
2.1 | Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998. | ||
2.2 | Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998. | ||
2.3 | Purchase Agreement, dated July 20, 2004, between Edison Mission Energy and Origin Energy New Zealand Limited, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 8-K filed October 4, 2004. | ||
2.4 | Purchase Agreement, dated July 29, 2004, by and among Edison Mission Energy, IPM Eagle LLP, International Power plc, Mitsui & Co., Ltd. and the other sellers on the signature page thereto, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2004. | ||
3.1 | Certificate of Incorporation of Edison Mission Energy, dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K filed October 29, 2001. | ||
3.1.1 | Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy, dated May 4, 2004, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004. | ||
3.1.2 | Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy, dated August 8, 2007, incorporated by reference to Exhibit 3.1.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2007. | ||
3.2 | Amended By-Laws of Edison Mission Energy, dated April 1, 2008, incorporated by reference to Exhibit 3.2 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2008. | ||
4.1 | Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 10, 2007. | ||
4.1.1 | First Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed May 10, 2007. | ||
4.1.2 | Second Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed May 10, 2007. | ||
4.1.3 | Third Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.3 to Edison Mission Energy's Form 8-K filed May 10, 2007. | ||
4.1.4 | Fourth Supplemental Indenture, dated as of August 22, 2007, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of May 7, 2007, incorporated by reference to Exhibit 4.1.4 to Edison Mission Energy's Form S-4 filed September 10, 2007. | ||
162
Exhibit No. |
Description |
||
---|---|---|---|
4.2 | Second Supplemental Indenture, dated as of April 30, 2007, between Edison Mission Energy and The Bank of New York, as trustee, supplementing the Indenture, dated as of June 28, 1999, pursuant to which Edison Mission Energy's 7.73% Senior Notes due 2009 were issued, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed May 1, 2007. | ||
4.3 | Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K filed June 8, 2006. | ||
4.3.1 | First Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed June 8, 2006. | ||
4.3.2 | Second Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed June 8, 2006. | ||
4.4 | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.4.1 | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.4 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.5 | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.5.1 | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.5 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.6 | Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.12 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.6.1 | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.6 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
163
Exhibit No. |
Description |
||
---|---|---|---|
4.7 | Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.7.1 | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.7 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001. | ||
4.8 | Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000. | ||
4.8.1 | Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.8 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000. | ||
4.9 | Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001. | ||
4.9.1 | Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001. | ||
4.9.2 | Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.4.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2004. | ||
4.10 | Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001. | ||
4.10.1 | Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.10 hereto, incorporated by reference to Exhibit 4.9.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2003. | ||
10.1 | Purchase & Reservation Agreement, dated as of June 4, 2007, between Edison Mission Energy and Suzlon Wind Energy Corporation, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2007. | ||
10.2 | Supply Agreement, dated as of March 28, 2007, between Edison Mission Energy and Mitsubishi Power Systems Americas, Inc., incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2007. | ||
164
Exhibit No. |
Description |
||
---|---|---|---|
10.3 | Credit Agreement, dated as of June 15, 2006, between Edison Mission Energy, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 8-K filed June 21, 2006. | ||
10.3.1 | Amendment No. 1 to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.3 herein), dated as of May 7, 2007, among Edison Mission Energy, the Lenders party thereto, the Issuing Lenders party thereto, and Citigroup North America Inc., as administrative agent, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 8-K filed May 10, 2007. | ||
10.4 | Credit Agreement, dated as of April 27, 2004 among Midwest Generation, LLC, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 4.3 to Midwest Generation, LLC's Form 10-Q for the quarter ended March 31, 2004. | ||
10.4.1 | First Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated as of April 18, 2005 among Midwest Generation, LLC, the Lenders referred to therein the Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended March 31, 2005. | ||
10.4.2 | Second Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated as of December 15, 2005, among Midwest Generation, LLC, the Lenders referred to therein and Citicorp North America, Inc. as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.6.2 to Midwest Generation, LLC's Form 10-K for the year ended December 31, 2005. | ||
10.4.3 | Third Amended and Restated Credit Agreement (amending and restating the Credit Agreement listed as Exhibit 10.4 herein), dated June 29, 2007, among Midwest Generation, LLC and the Lenders referred to therein and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended June 30, 2007. | ||
10.5 | Security Agreement, dated as of June 15, 2006, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.2 to Edison Mission Energy's Form 8-K filed June 21, 2006. | ||
10.6 | Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998. | ||
10.7 | Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.16.4 to EME Homer City Generation L.P.'s Form 10-K for the year ended December 31, 2001. | ||
165
Exhibit No. |
Description |
||
---|---|---|---|
10.8 | Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001. | ||
10.9 | Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000. | ||
10.10 | Reimbursement Agreement, dated as of October 26, 2001, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.15 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004. | ||
10.11 | Tax Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002. | ||
10.12 | Administrative Agreement Re Tax Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002. | ||
31.1* | Certification of the President pursuant to Section 302 of the Sarbanes-Oxley Act. | ||
31.2* | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. | ||
32* | Statement Pursuant to 18 U.S.C. Section 1350. | ||
101** | Financial statements from the annual report on Form 10-K of Edison Mission Energy for the year ended December 31, 2010, filed on February 28, 2011, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Total Equity, (iv) the Consolidated Statements of Comprehensive Income, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements tagged as blocks of text. | ||
166
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EDISON MISSION ENERGY (REGISTRANT) |
||||
By: |
/s/ Maria Rigatti Maria Rigatti Vice President, Chief Financial Officer and Treasurer |
|||
Date: |
February 28, 2011 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature |
Title |
Date |
|||
---|---|---|---|---|---|
/s/ Pedro J. Pizarro Pedro J. Pizarro |
President (Principal Executive Officer) |
February 28, 2011 |
|||
/s/ Maria Rigatti Maria Rigatti |
Vice President and Financial Officer (Principal Financial Officer) |
February 28, 2011 |
|||
/s/ Joanne M. Collins Joanne M. Collins |
Vice President and Controller (Controller or Principal Accounting Officer) |
February 28, 2011 |
|||
/s/ W. James Scilacci W. James Scilacci |
Director |
February 28, 2011 |
|||
/s/ Robert L. Adler Robert L. Adler |
Director |
February 28, 2011 |
167
EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
(in millions)
|
December 31, | |||||||
---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
||||||
Assets |
||||||||
Cash and cash equivalents |
$ | 427 | $ | 180 | ||||
Affiliate receivables |
91 | 22 | ||||||
Other current assets |
5 | 1 | ||||||
Total current assets |
523 |
203 |
||||||
Investments in subsidiaries |
7,792 |
7,756 |
||||||
Other long-term assets |
316 | 469 | ||||||
Total Assets |
$ |
8,631 |
$ |
8,428 |
||||
Liabilities and Shareholder's Equity |
||||||||
Accounts payable and accrued liabilities |
$ | 75 | $ | 58 | ||||
Affiliate payables |
580 | 417 | ||||||
Total current liabilities |
655 |
475 |
||||||
Long-term debt |
3,700 |
3,700 |
||||||
Long-term affiliate debt |
1,343 | 1,348 | ||||||
Deferred taxes and other |
116 | 144 | ||||||
Total Liabilities |
5,814 |
5,667 |
||||||
Total EME Common Shareholder's Equity |
2,817 |
2,761 |
||||||
Total Liabilities and Shareholder's Equity |
$ |
8,631 |
$ |
8,428 |
||||
The accompanying notes are an integral part of these condensed financial statements.
168
SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
(in millions)
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||
Operating revenues |
$ | 4 | $ | 6 | $ | 9 | ||||
Operating expenses |
(114 | ) | (121 | ) | (124 | ) | ||||
Operating loss |
(110 | ) | (115 | ) | (115 | ) | ||||
Equity in income from continuing operations of subsidiaries |
463 | 488 | 809 | |||||||
Interest expense and other |
(355 | ) | (393 | ) | (398 | ) | ||||
Income (loss) before income taxes |
(2 | ) | (20 | ) | 296 | |||||
Benefit for income taxes |
(166 | ) | (217 | ) | (205 | ) | ||||
Net income attributable to EME common shareholder |
$ | 164 | $ | 197 | $ | 501 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
169
SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
|
Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
2008 |
|||||||
Net cash provided by operating activities |
$ | 576 | $ | 100 | $ | 215 | ||||
Net cash provided by (used in) financing activities |
(245 | ) | (517 | ) | 219 | |||||
Net cash used in investing activities |
(84 | ) | (152 | ) | (349 | ) | ||||
Net increase (decrease) in cash and cash equivalents |
247 | (569 | ) | 85 | ||||||
Cash and cash equivalents at beginning of period |
180 | 749 | 664 | |||||||
Cash and cash equivalents at end of period |
$ | 427 | $ | 180 | $ | 749 | ||||
Cash dividends received from subsidiaries |
$ | 125 | $ | 367 | $ | 206 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
170
SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT
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.
For a description and details of long-term debt of EME, including the parent company only, see "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 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 StatementsNote 9. Commitment and Contingencies" of this report.
171
EDISON MISSION ENERGY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(in millions)
|
|
Additions | |
|
|||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Description |
Balance at Beginning of Year |
Charged to Costs and Expenses |
Charged to Other Accounts |
Deductions |
Balance at End of Year |
||||||||||||
Year Ended December 31, 2010 |
|||||||||||||||||
Uncollectible accounts |
|||||||||||||||||
Customers |
$ | 2 | $ | | $ | 3 | 1 | $ | | $ | 5 | ||||||
All others |
48 | | | 48 | 2 | | |||||||||||
Total |
$ | 50 | $ | | $ | 3 | $ | 48 | $ | 5 | |||||||
Year Ended December 31, 2009 |
|||||||||||||||||
Uncollectible accounts |
|||||||||||||||||
Customers |
$ | 2 | $ | | $ | | $ | | $ | 2 | |||||||
All others |
48 | | | | 48 | ||||||||||||
Total |
$ | 50 | $ | | $ | | $ | | $ | 50 | |||||||
Year Ended December 31, 2008 |
|||||||||||||||||
Uncollectible accounts |
|||||||||||||||||
Customers |
$ | 2 | $ | | $ | | $ | | $ | 2 | |||||||
All others |
| | 48 | 2 | | 48 | |||||||||||
Total |
$ | 2 | $ | | $ | 48 | $ | | $ | 50 | |||||||
172