10-Q 1 a2193888z10-q.htm 10-Q

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TABLE OF CONTENTS
TABLE OF CONTENTS ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
TABLE OF CONTENTS RESULTS OF OPERATIONS
TABLE OF CONTENTS LIQUIDITY AND CAPITAL RESOURCES
TABLE OF CONTENTS MARKET RISK EXPOSURES

Table of Contents

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



Form 10-Q

(Mark one)    

ý

 

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

For the Quarterly Period Ended June 30, 2009

or

o

 

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

For the transition period from                               to                              

Commission file number 333-68630



EDISON MISSION ENERGY
(Exact name of registrant as specified in its charter)

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

18101 Von Karman Avenue, Suite 1700
Irvine, California

(Address of principal executive offices)

 

  
92612
(Zip Code)

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



        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 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 "large accelerated filer," "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
(Do not check if a smaller
reporting company)
  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

        Number of shares outstanding of the registrant's Common Stock as of August 7, 2009: 100 shares (all shares held by an affiliate of the registrant).


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GLOSSARY

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

Btu   British thermal units

CAA

 

Clean Air Act

CPS

 

Combined Pollutant Standard

Commonwealth Edison

 

Commonwealth Edison Company

CONE

 

cost of new entry

DOJ

 

United States Department of Justice

EME

 

Edison Mission Energy

EME Homer City

 

EME Homer City Generation L.P.

EMMT

 

Edison Mission Marketing & Trading, Inc.

FASB

 

Financial Accounting Standards Board

FERC

 

Federal Energy Regulatory Commission

Fitch

 

Fitch Ratings

FSP SFAS No. 132(R)-1

 

Financial Accounting Standards Board Staff Position SFAS No. 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets"

FSP SFAS No. 157-4

 

Financial Accounting Standards Board Staff Position SFAS No. 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that Are Not Orderly"

GAAP

 

generally accepted accounting principles

GWh

 

gigawatt-hours

Illinois Plants

 

EME's largest power plants (fossil fuel) located in Illinois

ISO(s)

 

independent system operator(s)

LIBOR

 

London Interbank Offered Rate

MD&A

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

Midwest Generation

 

Midwest Generation, LLC

MMBtu

 

million British thermal units

Moody's

 

Moody's Investors Service, Inc.

MW

 

megawatts

MWh

 

megawatt-hours

NAPP

 

Northern Appalachian

NOV

 

notice of violation

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NOX   nitrogen oxide

NYISO

 

New York Independent System Operator

PADEP

 

Pennsylvania Department of Environmental Protection

PJM

 

PJM Interconnection, LLC

PRB

 

Powder River Basin

RPM

 

reliability pricing model

S&P

 

Standard & Poor's Ratings Services

SCAQMD

 

South Coast Air Quality Management District

SCE

 

Southern California Edison Company

SFAS

 

Statement of Financial Accounting Standards issued by the FASB

SFAS No. 133

 

Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities"

SFAS No. 141(R)

 

Statement of Financial Accounting Standards No. 141(R), "Business Combinations"

SFAS No. 157

 

Statement of Financial Accounting Standards No. 157, "Fair Value Measurements"

SFAS No. 160

 

Statement of Financial Accounting Standards No. 160, "Noncontrolling Interests in Consolidated Financial Statements"

SFAS No. 161

 

Statement of Financial Accounting Standards No. 161, "Disclosures About Derivative Instruments and Hedging Activities" (an amendment of FASB No. 133)

SFAS No. 165

 

Statement of Financial Accounting Standards No. 165, "Subsequent Events"

SFAS No. 167

 

Statement of Financial Accounting Standards No. 167, "Amendments to FASB Interpretation No. 46(R)"

SO2

 

sulfur dioxide

US EPA

 

United States Environmental Protection Agency

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PART I—FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, Unaudited)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 

Operating Revenues

  $ 557   $ 613   $ 1,169   $ 1,332  

Operating Expenses

                         
 

Fuel

    172     157     359     344  
 

Plant operations

    146     195     295     331  
 

Plant operating leases

    44     44     88     88  
 

Depreciation and amortization

    56     46     112     90  
 

(Gain) on buyout of contract and (gain) loss on sale of assets

            1     (16 )
 

Administrative and general

    51     50     95     98  
                   
   

Total operating expenses

    469     492     950     935  
                   
 

Operating income

    88     121     219     397  
                   

Other Income (Expense)

                         
 

Equity in income from unconsolidated affiliates

    20     37     26     49  
 

Dividend income

    9     9     10     10  
 

Interest income

    3     7     6     15  
 

Interest expense

    (73 )   (66 )   (147 )   (137 )
 

Other income (expense), net

    1     (1 )   2     5  
                   
   

Total other income (expense)

    (40 )   (14 )   (103 )   (58 )
                   
 

Income from continuing operations before income taxes

    48     107     116     339  
 

Provision for income taxes

    2     34     17     116  
                   

Income From Continuing Operations

    46     73     99     223  
 

Loss from operations of discontinued subsidiaries, net of tax (Note 6)

    (7 )   (1 )   (4 )   (6 )
                   

Net Income

    39     72     95     217  
                   

Net Loss Attributable to Noncontrolling Interest

    1         1      
                   

Net Income Attributable to Common Shareholders of EME

  $ 40   $ 72   $ 96   $ 217  
                   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions, Unaudited)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 

Net Income

  $ 39   $ 72   $ 95   $ 217  

Other comprehensive income (loss), net of tax:

                         
 

Pension and postretirement benefits other than pensions:

                         
   

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

    1         1      
 

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

                         
   

Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(50) and $(212) for the three months and $48 and $(304) for the six months ended June 30, 2009 and 2008, respectively

    (90 )   (316 )   61     (454 )
   

Reclassification adjustments included in net income, net of income tax expense (benefit) of $(9) and $(95) for the three months and $23 and $(89) for the six months ended June 30, 2009 and 2008, respectively

    17     143     (32 )   135  
                   

Other comprehensive income (loss)

   
(72

)
 
(173

)
 
30
   
(319

)
                   

Comprehensive Income (Loss)

   
(33

)
 
(101

)
 
125
   
(102

)
                   

Comprehensive Loss Attributable to Noncontrolling Interest

   
1
   
   
1
   
 
                   

Comprehensive Income (Loss) Attributable to Common Shareholders of EME

 
$

(32

)

$

(101

)

$

126
 
$

(102

)
                   

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

 
 
June 30,
2009
 
December 31,
2008
 

Assets

             

Current Assets

             
 

Cash and cash equivalents

  $ 1,656   $ 1,807  
 

Short-term investments

    2     4  
 

Accounts receivable—trade

    203     241  
 

Receivables from affiliates

    184     18  
 

Inventory

    220     189  
 

Derivative assets

    223     170  
 

Restricted cash

    188      
 

Margin and collateral deposits

    100     88  
 

Prepaid expenses and other

    106     144  
           
   

Total current assets

    2,882     2,661  
           

Investments in Unconsolidated Affiliates

    353     362  
           

Property, Plant and Equipment

    5,775     5,643  
 

Less accumulated depreciation and amortization

    1,350     1,241  
           
   

Net property, plant and equipment

    4,425     4,402  
           

Other Assets

             
 

Deferred financing costs

    46     36  
 

Long-term derivative assets

    165     170  
 

Restricted cash

    44     43  
 

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

    991     878  
 

Other long-term assets

    626     528  
           
   

Total other assets

    1,872     1,655  
           

Total Assets

  $ 9,532   $ 9,080  
           

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

 
 
June 30,
2009
 
December 31,
2008
 

Liabilities and Shareholder's Equity

             

Current Liabilities

             
 

Accounts payable

  $ 103   $ 95  
 

Payables to affiliates

    5     18  
 

Accrued liabilities

    259     380  
 

Derivative liabilities

    7     22  
 

Interest payable

    30     30  
 

Deferred taxes

    95     66  
 

Current maturities of long-term obligations

    39     24  
           
   

Total current liabilities

    538     635  
           

Long-term obligations net of current maturities

    4,769     4,638  

Deferred taxes and tax credits

    760     541  

Deferred revenues

    65     63  

Long-term derivative liabilities

    13     5  

Other long-term liabilities

    497     434  
           

Total Liabilities

    6,642     6,316  
           

Commitments and Contingencies (Note 11)

             

Equity

             
 

Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of June 30, 2009 and December 31,  2008

    64     64  
 

Additional paid-in capital

    1,337     1,335  
 

Retained earnings

    1,180     1,085  
 

Accumulated other comprehensive income

    230     200  
           
   

Total EME common shareholder's equity

    2,811     2,684  
           

Noncontrolling Interest

    79     80  
           

Total Equity

    2,890     2,764  
           

Total Liabilities and Equity

  $ 9,532   $ 9,080  
           

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, Unaudited)

 
  Six Months Ended June 30,  
 
 
2009
 
2008
 

Cash Flows From Operating Activities

             
 

Net income

  $ 95   $ 217  
 

Loss from discontinued operations

    4     6  
           
 

Income from continuing operations, net

  $ 99   $ 223  
 

Adjustments to reconcile income to net cash used in operating activities:

             
   

Equity in income from unconsolidated affiliates

    (26 )   (48 )
   

Distributions from unconsolidated affiliates

    21     40  
   

Depreciation and amortization

    115     92  
   

Deferred taxes and tax credits

    209     28  
   

(Gain) on buyout of contract and (gain) loss on sale of assets

    1     (16 )
 

Changes in operating assets and liabilities:

             
   

Increase in margin and collateral deposits

    (12 )   (93 )
   

Increase in accounts receivable

    (127 )   (127 )
   

Increase in inventory

    (31 )   (23 )
   

Decrease in prepaid expenses and other

    36     42  
   

Increase in restricted cash

    (188 )    
   

Increase in rent payments in excess of levelized rent expense

    (113 )   (113 )
   

Increase (decrease) in accounts payable and other current liabilities

    (144 )   48  
   

Increase in derivative assets and liabilities

    (1 )   (131 )
   

Other operating—assets

    (2 )   (33 )
   

Other operating—liabilities

    72     5  
           
 

Operating cash flow from continuing operations

    (91 )   (106 )
 

Operating cash flow from discontinued operations

    (4 )   (6 )
           
   

Net cash used in operating activities

    (95 )   (112 )
           

Cash Flows From Financing Activities

             
 

Borrowings on long-term debt

    189     182  
 

Payments on long-term debt agreements

    (43 )   (133 )
 

Cash contributions from noncontrolling interests

    1      
 

Cash dividends to noncontrolling interests

    (1 )    
 

Payments to affiliates related to stock-based awards

    (1 )   (8 )
 

Excess tax benefits related to stock-based awards

        1  
 

Financing costs

    (13 )   (1 )
           
   

Net cash provided by financing activities

    132     41  
           

Cash Flows From Investing Activities

             
 

Capital expenditures

    (138 )   (214 )
 

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

    11     7  
 

Proceeds from sale of membership interest

        28  
 

Purchase of interest of acquired companies

    (7 )   (7 )
 

Maturities of short-term investments

    2     70  
 

Increase in restricted cash

    (1 )    
 

Investments in other assets

    (55 )   (222 )
           
   

Net cash used in investing activities

    (188 )   (338 )
           

Net decrease in cash and cash equivalents

    (151 )   (409 )

Cash and cash equivalents at beginning of period

    1,807     994  
           

Cash and cash equivalents at end of period

  $ 1,656   $ 585  
           

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2009
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

        EME's significant accounting policies were described in "Note 1—Summary of Significant Accounting Policies" on page 110 of EME's annual report on Form 10-K for the year ended December 31, 2008. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2009 as discussed below in "—New Accounting Pronouncements." This quarterly report should be read in conjunction with such financial statements.

        In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position and results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the six months ended June 30, 2009 are not necessarily indicative of the operating results for the full year.

        Certain prior year reclassifications have been made to conform to the current year financial statement presentation pertaining to the adoption of SFAS No. 160. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

        Management has performed an evaluation of subsequent events through August 7, 2009, the date the financial statements were issued.

Cash, Cash Equivalents and Short-term Investments

        Cash, cash equivalents and short-term investments as of June 30, 2009 and December 31, 2008 consisted of the following:

 
 
June 30,
2009
 
December 31,
2008
 
 
  (in millions)
 

Cash

  $ 85   $ 31  
           

Money market funds

  $ 1,560   $ 1,581  

U.S. government agency securities

        164  

Commercial paper

        30  

Time deposits (certificates of deposit)

    11     1  
           
 

Total cash equivalents

  $ 1,571   $ 1,776  
           

Commercial paper

  $ 1   $ 1  

Money market funds

    1     3  
           
 

Total short-term investments

  $ 2   $ 4  
           
 

Total cash, cash equivalents and short-term investments

  $ 1,658   $ 1,811  
           

        Cash equivalents, with the exception of money market funds, were stated at amortized cost plus accrued interest. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months. For further discussion of money market funds, see Note 2—Fair Value Measurements. For a discussion of restricted cash, see "—Restricted Cash."

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        At June 30, 2009 and December 31, 2008, EME had classified all marketable debt securities as held-to-maturity under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The securities were carried at amortized cost plus accrued interest, which was equal to its fair value. Held-to-maturity securities all mature within one year.

Inventory

        Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2009 and December 31, 2008 consisted of the following:

 
 
June 30,
2009
 
December 31,
2008
 
 
  (in millions)
 

Coal, fuel oil and other raw materials

  $ 158   $ 131  

Spare parts, materials and supplies

    62     58  
           

Total

  $ 220   $ 189  
           

New Accounting Pronouncements

Accounting Principles Adopted

Statement of Financial Accounting Standards No. 165—

        In May 2009, the FASB issued SFAS No. 165, "Subsequent Events." SFAS No. 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize these events or transactions; and the disclosures that an entity should make. EME adopted SFAS No. 165 effective April 1, 2009. The adoption of this standard had no impact on EME's consolidated results of operations, financial position or cash flows.

FSP SFAS No. 157-4—

        In April 2009, the FASB issued FSP SFAS No. 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that Are Not Orderly." FSP SFAS No. 157-4 affirms the objective of a fair value measurement, which is to identify the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction at the measurement date between market participants ("exit price") under current market conditions. FSP SFAS No. 157-4 includes guidance on identifying circumstances that indicate when there is no active market or transactions where the price inputs being used represent distressed or forced sales. If either of these conditions exists, FSP SFAS No. 157-4 provides additional direction for estimating fair value and requires disclosure of a change in valuation technique (and the related inputs) resulting from the application of this position and to quantify its effects, if practicable. This position also requires disclosures on a more disaggregated basis for investments in debt and equity securities measured at fair value. EME adopted FSP SFAS No. 157-4 effective April 1, 2009. The adoption of this position had no impact on EME's consolidated results of operations, financial position or cash flows.

FSP SFAS No. 115-2 and SFAS No. 124-2—

        In April 2009, the FASB issued FSP SFAS No. 115-2 and SFAS No. 124-2, "Recognition and Presentation of Other-Than-Temporary Impairments." This position amends existing guidance for determining whether impairment is other than temporary for debt securities. Under this position, an entity writes down to fair value through earnings, impaired debt securities that it currently intends to sell or for which it is more likely than not it will be required to sell before the anticipated recovery. If

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an entity does not intend and will not be required to sell a debt security but it is probable that the entity will not collect all amounts due, the entity will separate the other-than-temporary impairment into two components: 1) the amount due to credit loss would be recognized in earnings, and 2) the remaining portion would be recognized in other comprehensive income. EME adopted this position effective April 1, 2009, resulting in increased disclosures. The adoption of this position did not have an impact on EME's consolidated results of operations, financial position or cash flows. For disclosures, see "—Cash and Cash Equivalents and Short-term Investments."

FSP SFAS No. 107-1 and APB No. 28-1—

        In April 2009, the FASB issued FSP SFAS No. 107-1 and APB No. 28-1, "Interim Disclosures about Fair Value of Financial Instruments." This position requires disclosures about the fair value of all financial instruments, for which it is practicable to estimate that fair value, for interim reporting periods as well as annual statements. EME adopted this position effective April 1, 2009. Since FSP SFAS No. 107-1 and APB No. 28-1 impacts disclosure only, the adoption of this position did not have an impact on EME's consolidated results of operations, financial position or cash flows. For disclosures, see Note 2—Fair Value Measurements.

Statement of Financial Accounting Standards No. 157—

        Effective January 1, 2009, EME adopted SFAS No. 157 for nonrecurring fair value measurements of nonfinancial assets and liabilities. The adoption of SFAS No. 157 for nonrecurring fair value measurements did not have a material impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 141(R)—

        In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. Adoption of this standard had no impact on EME's consolidated results of operations, financial position or cash flows because there were no business combinations during the first six months of 2009.

Statement of Financial Accounting Standards No. 141(R)-1—

        In April 2009, the FASB issued FSP SFAS No. 141(R)-1, "Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies" to amend guidance in SFAS No. 141(R). FSP SFAS No. 141(R)-1 addresses the initial recognition, measurement and subsequent accounting for assets and liabilities arising from contingencies in a business combination, and requires that such assets acquired or liabilities assumed be initially recognized at fair value at the acquisition date if fair value can be determined during the measurement period. If the acquisition-date fair value cannot be determined, the asset acquired or liability assumed arising from a contingency is recognized only if certain criteria are met. This position also requires that a systematic and rational basis for subsequently measuring and accounting for the assets or liabilities be developed depending on their nature. This position was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. Adoption of this standard had no impact on EME's consolidated results of operations, financial position or cash flows because there were no business combinations during the first six months of 2009.

Statement of Financial Accounting Standards No. 160—

        In December 2007, the FASB issued SFAS No. 160, which requires an entity to present noncontrolling interests that reflect the ownership interests in subsidiaries held by parties other than

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the entity, within the equity section but separate from the entity's equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interests to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interests to be accounted for similarly as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary to be measured at fair value. EME adopted this pronouncement effective January 1, 2009. In accordance with this standard, EME reclassified noncontrolling interests of $80 million at December 31, 2008 to a component of equity on EME's consolidated balance sheet. For additional information regarding the adoption of SFAS No. 160, see Note 7—Noncontrolling Interests.

Statement of Financial Accounting Standards No. 161—

        In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. EME adopted this pronouncement effective January 1, 2009. Since SFAS No. 161 impacts disclosures only, the adoption of this standard did not have an impact on EME's consolidated results of operations, financial position or cash flows. For additional information regarding the adoption of SFAS No. 161, see Note 3—Derivative Instruments.

FSP SFAS No. 142-3—

        In April 2008, the FASB issued FSP SFAS No. 142-3, "Determination of the Useful Life of Intangible Assets," which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, "Goodwill and Other Intangible Assets." The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other GAAP. EME adopted this pronouncement effective January 1, 2009. The adoption of this position had no impact on EME's consolidated results of operations, financial position or cash flows.

EITF Issue No. 08-6—

        In November 2008, the FASB ratified the consensus in EITF Issue No. 08-6, "Equity Method Investment Accounting Considerations." This issue clarifies the accounting for certain transactions and impairment considerations involving equity method investments. Effective January 1, 2009, EME adopted this issue prospectively. The adoption had no impact on EME's consolidated financial statements.

Accounting Principles Not Yet Adopted

FSP SFAS No. 132(R)-1—

        In December 2008, the FASB issued FSP SFAS No. 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets." This position requires additional plan asset disclosures about the major categories of assets, the inputs and valuation techniques used to measure fair value, the level within the fair value hierarchy, the effect of using significant unobservable inputs (Level 3) and significant concentrations of risk. This position is effective for years ending after December 15, 2009 and therefore, EME will adopt FSP SFAS No. 132(R)-1 at year-end 2009. FSP SFAS No. 132(R)-1 will impact disclosures only and will not have an impact on EME's consolidated results of operations, financial position or cash flows.

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Statement of Financial Accounting Standards No. 167—

        In June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)." SFAS No. 167 changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance. EME will adopt SFAS No. 167 on January 1, 2010 and is currently evaluating the impact, if any, that the adoption of this standard will have on its consolidated financial statements.

Statement of Financial Accounting Standards No. 168—

        In June 2009, the FASB issued SFAS No. 168, "The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles." This Statement establishes the Codification to become the source of authoritative, nongovernmental U.S. GAAP superseding existing FASB, American Institute of Certified Public Accountants (AICPA), Emerging Issues Task Force (EITF) and related literature. Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, the FASB will issue Accounting Standards Updates. Two levels of U.S. GAAP will exist: authoritative and non-authoritative. Codification is not intended to change U.S. GAAP or guidance issued by the SEC. However, Codification will affect the way EME researches accounting issues and references U.S. GAAP in its notes to consolidated financial statements and MD&A. EME will adopt this Statement in the third quarter of 2009.

Restricted Cash

        Cash balances that are restricted to pay amounts required for lease payments, margining, or to provide collateral are classified as restricted cash. Cash balances that are restricted under margining agreements are classified as short term as such amounts change frequently based on forward market prices.

Note 2. Fair Value Measurements

        SFAS No. 157 defines fair value 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" in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity's nonperformance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure 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 three levels of the fair value hierarchy under SFAS No. 157 are:

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

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

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

        EME's assets and liabilities carried at fair value primarily consist of derivative contracts and money market funds. Derivative contracts primarily relate to power and include contracts for forward physical

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sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange traded or over-the-counter traded.

        The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. The majority of derivative contracts used for hedging purposes are based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades. The majority of the fair value of EME's derivative contracts determined in this manner are classified as Level 2.

        Derivatives that trade infrequently (such as financial transmission rights and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant nonperformance risks, as discussed below, and long-term power agreements are classified as Level 3. For illiquid financial transmission rights, EME reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when EME concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where EME cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

        In assessing nonperformance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. EME reduced the fair value of derivative assets for nonperformance risks by $5 million at June 30, 2009.

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

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        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 June 30, 2009 and December 31, 2008:

As of June 30, 2009
 
Level 1
 
Level 2
 
Level 3
 
Netting and
Collateral(2)
 
Total
 
 
  (in millions)
 

Assets at Fair Value

                               
 

Money market funds(1)

  $ 1,560   $   $ 1   $   $ 1,561  
 

Derivative contracts

    19     497     266     (394 )   388  

Liabilities at Fair Value

                               
 

Derivative contracts

  $   $ (159 ) $ (26 ) $ 165   $ (20 )

 

As of December 31, 2008
 
Level 1
 
Level 2
 
Level 3
 
Netting and
Collateral(2)
 
Total
 
 
  (in millions)
 

Assets at Fair Value

                               
 

Money market funds(1)

  $ 1,581   $   $ 3   $   $ 1,584  
 

Derivative contracts

    2     417     221     (300 )   340  

Liabilities at Fair Value

                               
 

Derivative contracts

  $   $ (145 ) $ (8 ) $ 126   $ (27 )

(1)
Included in cash and cash equivalents and short-term investments on EME's consolidated balance sheet.

(2)
Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

        The following table sets forth a summary of changes in the fair value of assets and liabilities, net categorized as Level 3 for the periods ended June 30, 2009 and 2008:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Fair value at beginning of periods

  $ 269   $ 111   $ 216   $ 120  

Total realized/unrealized gains (losses):

                         
 

Included in earnings(1)

    (49 )   59     97     92  
 

Included in accumulated other comprehensive income

        (4 )       (6 )

Purchases and settlements, net

    29     (38 )   (60 )   (75 )

Transfers in or out of Level 3

    (8 )   (7 )   (12 )   (10 )
                   

Fair value at June 30

  $ 241   $ 121   $ 241   $ 121  
                   

Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at June 30(1)

  $ 13   $ 34   $ 71   $ 37  
                   

(1)
Reported in operating revenues on EME's consolidated statements of income.

        The increase in the fair value of Level 3 derivative contracts during the first six months of 2009 is primarily due to load requirements services contracts. The energy price risk related to these contracts was substantially hedged, but such hedge contracts are classified as Level 2 and, therefore, not reflected as an offsetting position in Level 3.

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Long-term Obligations

        The carrying amounts and fair values of EME's long-term obligations as of June 30, 2009 and December 31, 2008 were as follows:

 
  June 30, 2009   December 31, 2008  
 
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
 
 
  (in millions)
 

Long-term obligations

  $ 4,769   $ 3,894   $ 4,638   $ 3,982  

Long-term obligations due within one year

    39     39     24     24  

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

Note 3. Derivative Instruments

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

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

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

    full requirements services contracts or load requirements services contracts for the procurement of power for electric utilities' customers, with such services providing for the delivery of a bundled product including, but not limited to, energy, transmission, capacity, and ancillary services, generally for a fixed unit price,

    capacity transactions, and

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

        The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine if forward market prices are sufficiently attractive compared to the risks associated with the fluctuating spot market. Second, EME evaluates the sufficiency of its credit capacity at EME and Midwest Generation and whether the forward sales markets have sufficient liquidity to enable EME to identify appropriate counterparties for hedge transactions. Hedge transactions entered into by EME are accounted for under SFAS No. 133.

        SFAS No. 133, as amended and interpreted by accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires a company to record derivatives on its balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as a normal sale and purchase. Under SFAS No. 133, 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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        SFAS No. 133 sets forth the accounting requirements for cash flow hedges. SFAS No. 133 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.

        Many of the derivative instruments entered into for risk management purposes (also referred to as non-trading purposes) meet the requirements for hedge accounting under SFAS No. 133. However, not all derivative instruments entered into for risk management purposes will qualify for hedge accounting treatment. Furthermore, EME utilizes derivative contracts that are designed to adjust financial and/or physical positions that reduce costs or increase gross margin. Accordingly, risk management positions may not be designated as cash flow hedges and are thus marked to market through current period earnings (derivatives that are entered into for risk management, but which are not designated as cash flow hedges, are referred to as economic hedges).

        SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on the settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from commodity contracts in operating revenues or fuel expenses based on the item being hedged. In addition, the results of derivative activities are recorded in cash flows from operating activities in the consolidated statements of cash flows.

        Derivative instruments that are utilized for trading purposes are measured at fair value and included in the balance sheet as derivative assets or liabilities. In the absence of quoted market prices, derivative instruments are valued at fair value as determined through the methodology outlined in Note 2—Fair Value Measurements. Resulting gains and losses are recognized in operating revenues in the accompanying consolidated income statements in the period of change in accordance with EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."

        Where EME's derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (FIN) No. 39 "Offsetting of Amounts Related to Certain Contracts" are met, EME presents its derivative assets and liabilities on a net basis in its balance sheet.

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Notional Volumes of Derivative Instruments

        The following table summarizes the notional volumes of derivatives used for hedging and trading activities at June 30, 2009:

 
   
   
   
  Hedging Activities    
 
Commodity
 
Instrument
 
Classification
 
Unit of
Measure
 
Cash Flow
Hedges
 
Economic
Hedges
 
Trading
Activities
 
Electricity   Forwards   Sales   GWh     16,809 (1)   20,215 (3)   21,651  
Electricity   Forwards   Purchases   GWh         19,088 (3)   23,238  
Electricity   Capacity   Sales   MW-Day
(in thousands)
    386 (2)       91 (2)
Electricity   Capacity   Purchases   MW-Day
(in thousands)
    25 (2)   5 (2)   554 (2)
Electricity   Congestion   Sales   GWh         136 (4)   7,570 (4)
Electricity   Congestion   Purchases   GWh         3,328 (4)   171,875 (4)
Natural gas   Forwards   Sales   billion cubic feet         9.8     42.0  
Natural gas   Forwards   Purchases   billion cubic feet             44.8  
Fuel oil   Forwards   Sales   Barrels             90,000  
Fuel oil   Forwards   Purchases   Barrels         600,000     140,000  

(1)
EME's hedge products include forward and futures contracts that qualify for hedge accounting under SFAS No. 133. This category excludes power contracts for the Illinois Plants which meet the normal sales and purchase exception under SFAS No. 133 and are accounted for on the accrual method.

(2)
EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM RPM auction is not accounted for as a derivative under SFAS No. 133.

(3)
EME also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges under SFAS No. 133.

(4)
Congestion contracts are financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

        In addition, Viento Funding II, Inc., an EME subsidiary, in conjunction with the closing of its wind portfolio financing, entered into seven-year amortizing interest rate swaps accounted for as cash flow hedges with a total notional amount of approximately $170 million at June 30, 2009. The interest rate swaps entitle Viento Funding II to receive a floating (six-month LIBOR) rate and pay a fixed rate of 3.175%. The interest rate swap agreements expire in June 2016.

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Fair Value of Derivative Instruments

        The following table summarizes the gross fair value of derivative instruments at June 30, 2009:

 
  Derivative Assets   Derivative Liabilities    
 
 
 
Short-term
 
Long-term
 
Subtotal
 
Short-term
 
Long-term
 
Subtotal
 
Net Assets
 
 
  (in millions)
 

Non-trading activities

                                           
 

Cash flow hedges

  $ 346   $ 125   $ 471   $ 15   $ 17   $ 32   $ 439  
 

Economic hedges

    245     80     325     232     63     295     30  

Trading activities

    485     178     663     432     103     535     128  
                               

  $ 1,076   $ 383   $ 1,459   $ 679   $ 183   $ 862   $ 597  

Netting and collateral received

    (853 )   (218 )   (1,071 )   (672 )   (170 )   (842 )   (229 )
                               
 

Total

  $ 223   $ 165   $ 388   $ 7   $ 13   $ 20   $ 368  
                               

Income Statement Impact of Derivative Instruments

        The following table provides the activity of accumulated other comprehensive income for the six months ended June 30, 2009, containing the information about the changes in the fair value of cash flow hedges and reclassification from accumulated other comprehensive income into results of operations:

 
 
Cash Flow
Hedge Activity(1)
 
Income
Statement Location
 
  (in millions)
   

Accumulated other comprehensive income derivative gain at December 31, 2008

  $ 398    

Effective portion of changes in fair value

    109    

Reclassification from accumulated other comprehensive income to net income

    (55 ) Operating revenues(2)
         

Accumulated other comprehensive income derivative gain at June 30, 2009

  $ 452    
         

(1)
Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at June 30, 2009 and December 31, 2008 were $269 million and $240 million, respectively.

(2)
Represents reclassification of unrealized gains to operating revenues.

        Under SFAS No. 133, 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 $5 million and $(18) million during the second quarters of 2009 and 2008, respectively, and $5 million and $(31) million during the six months ended June 30, 2009 and 2008, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues in the income statement.

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        The effect of realized and unrealized gains from derivative instruments used for economic hedging and trading purposes on the consolidated statement of income for the periods ended June 30, 2009 is presented below:

Type
 
Income
Statement Location
 
Three Months
Ended
June 30, 2009
 
Six Months
Ended
June 30, 2009
 
 
   
  (in millions)
 

Economic hedges

  Operating revenue   $ 3   $ 16  

  Fuel expense     14     14  

Trading activities

 

Operating revenue

   
17
   
27
 

Contingent Features/Credit Related Exposure

        Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT also has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position on June 30, 2009 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

Margin and Collateral Deposits

        Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. In accordance with FIN No. 39-1, "Amendment of FASB Interpretation No. 39," EME presents a portion of its margin and cash collateral deposits net with its derivative positions on EME's consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $46 million and $51 million at June 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $275 million and $225 million at June 30, 2009 and December 31, 2008, respectively.

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Note 4. Accumulated Other Comprehensive Income

        Accumulated other comprehensive income consisted of the following:

 
 
Unrealized
Gains on Cash
Flow Hedges
 
Unrecognized Losses
and Prior Service
Adjustments, Net(1)
 
Accumulated Other
Comprehensive
Income
 
 
  (in millions)
 

Balance at December 31, 2008

  $ 240   $ (40 ) $ 200  

Current period change

    29     1     30  
               

Balance at June 30, 2009

  $ 269   $ (39 ) $ 230  
               

(1)
For further detail, see Note 9—Compensation and Benefit Plans.

        The amount of commodity hedges included in unrealized gains on cash flow hedges, net of tax, at June 30, 2009 was a gain of $270 million. The amount of interest rate hedges included in unrealized gains on cash flow hedges, net of tax, at June 30, 2009 was a loss of $1 million.

        Unrealized gains on commodity hedges included those related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. As EME's hedged positions for continuing operations are realized, $209 million, after tax, of the net unrealized gains on cash flow hedges at June 30, 2009 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2011.

Note 5. Restructuring Costs

        As a result of the continuing downturn in economic conditions, EME reduced approximately 75 positions in its regional and corporate offices in April 2009. As a result, EME recorded charges of approximately $5 million (pre-tax) during the second quarter of 2009 included in administrative and general expense on EME's consolidated statement of income.

Note 6. Discontinued Operations

        Summarized financial information for discontinued operations is as follows:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Loss before income taxes and minority interest

  $ (12 ) $   $ (6 ) $ (6 )

Provision (benefit) for income taxes

    (5 )   1     (2 )    
                   

Loss from operations of discontinued foreign subsidiaries

  $ (7 ) $ (1 ) $ (4 ) $ (6 )
                   

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

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Note 7. Noncontrolling Interests

        Pursuant to SFAS No. 160, EME is providing a consolidated statement of changes in equity and a schedule summarizing the amounts of income from continuing operations and discontinued operations attributable to EME.

Consolidated Statement of Changes in Equity

        Consolidated statement of changes in equity at the beginning and the end of the six months ended June 30, 2009 and 2008:

 
   
  EME Shareholders    
 
Six months ended June 30, 2009
 
Total
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Common
Stock
 
Additional
Paid-in
Capital
 
Non-
controlling
Interest
 
 
  (in millions)
 

Balance at December 31, 2008

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

Net income (loss)

    95     96                       (1 )

Other comprehensive income

    30           30                    

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

    (1 )   (1 )                        

Other stock transactions, net

    2                       2        

Cash contributions from noncontrolling interests

    1                             1  

Cash distributions to noncontrolling interests

    (1 )                           (1 )
                           

Balance at June 30, 2009

  $ 2,890   $ 1,180   $ 230   $ 64   $ 1,337   $ 79  
                           

Six months ended June 30, 2008

 

 


 

 


 

 


 

 


 

 


 

 


 

Balance at December 31, 2007

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

Net income

    217     217                          

Other comprehensive loss

    (319 )         (319 )                  

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

    (11 )   (11 )                        

Other stock transactions, net

    3                       3        

Sale of membership interest in noncontrolling interest

    28                             28  

Cash distributions to noncontrolling interests

    (1 )                           (1 )
                           

Balance at June 30, 2008

  $ 1,882   $ 802   $ (382 ) $ 64   $ 1,329   $ 69  
                           

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Summarized Financial Information for EME

        Amounts attributable to EME common shareholders:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 
Income from continuing operations, net of tax   $ 47   $ 73   $ 100   $ 223  
Discontinued operations, net of tax     (7 )   (1 )   (4 )   (6 )
                   
Net income attributable to EME common shareholders   $ 40   $ 72   $ 96   $ 217  
                   

Note 8.  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 June 30, 2009 and December 31, 2008, EME had majority interests in 15 wind projects with a total generating capacity of 700 MW that had minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. Minority interest holders have key rights over matters such as budgets, incurrence of debt, and sale of the project, and in certain cases, receive a higher allocation of income and losses after a minimum return is earned by EME. In determining that EME was the primary beneficiary, a key factor was the conclusion that the power sales agreements did not constitute a variable interest since the agreements have a fixed unit price and do not absorb expected losses. As a result, the determination of EME as the primary beneficiary was based on the allocation of income and losses with EME expected to earn a majority of the expected gains or absorb the majority of the expected losses based on its ownership interest.

        The following table presents summarized financial information of the wind projects that had minority interests held by others consolidated by EME at June 30, 2009 and December 31, 2008:

 
 
June 30, 2009
 
December 31, 2008
 
 
  (in millions)
 

Current assets

  $ 35   $ 31  

Net property, plant and equipment

    976     957  

Other long-term assets

    2     2  
           
 

Total assets

  $ 1,013   $ 990  
           

Current liabilities

  $ 29   $ 29  

Long-term obligations net of current maturities

    22     25  

Deferred revenues

    20     15  

Other long-term liabilities

    20     18  
           
 

Total liabilities

  $ 91   $ 87  
           

Noncontrolling interest

  $ 79   $ 77  
           

        Assets serving as collateral for the debt obligations had a carrying value of $84 million at each June 30, 2009 and December 31, 2008, and primarily consist of property, plant and equipment. The consolidated statement of income and cash flow for the six months ended June 30, 2009 includes $1 million of pre-tax loss and $32 million of operating cash flow related to variable interest entities that are consolidated.

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Projects that are not Consolidated

        EME has a number of investments in power projects that are accounted for under the equity method. Under the equity method, the project assets and related liabilities are not consolidated on EME's consolidated balance sheet. Rather, EME's financial statements reflect its investment in each entity and it records only its proportionate ownership share of net income or loss.

        Entities formed to own these projects are generally structured with a management committee in which EME exercises significant influence but cannot exercise unilateral control over the operating, funding or construction activities of the project entity. Two of these projects have secured long-term debt to finance the assets constructed and/or acquired by them. These financings generally are secured by a pledge of the assets of the project entity, but do not provide for any recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's project investment, but would generally not require EME to contribute additional capital. At June 30, 2009, entities which EME has accounted for under the equity method had indebtedness of $247 million, of which $111 million is proportionate to EME's ownership interest in these projects. At December 31, 2008, entities which EME has accounted for under the equity method had indebtedness of $294 million, of which $128 million is proportional to EME's ownership interest in these projects.

        As of June 30, 2009 and December 31, 2008, EME has five significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. These projects are natural gas-fired facilities with a total generating capacity of 1,782 MW. An operations and maintenance subsidiary of EME operates the Big 4 projects, but EME does not supply the fuel consumed or purchase the power generated by these facilities. EME concluded that the power purchase agreements for these projects represented variable interests in the related projects and, therefore, it was not the primary beneficiary of these entities. Accordingly, EME continues to account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities, which totaled $321 million and $326 million as of June 30, 2009 and December 31, 2008, respectively, and is classified as investments in unconsolidated affiliates on EME's consolidated balance sheets.

        As of June 30, 2009 and December 31, 2008, EME has a 50% interest in the March Point project. EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. The obligations under this indemnification agreement as of June 30, 2009 and December 31, 2008, if payment were required, would be $47 million and $56 million, respectively. EME has not recorded a liability related to the indemnity. EME's maximum exposure to loss at June 30, 2009 is $50 million. During the first quarter of 2009, EME commenced recording its share of equity in income from the March Point project. EME recorded $1 million and $3 million during the second quarter and six months ended June 30, 2009, respectively. To the extent that cash is received from the project in excess of EME's investment, such amount will be recorded as equity in income.

Note 9.  Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

        As of June 30, 2009, EME had made approximately $2 million in contributions to its pension plans and estimates to make $7 million of contributions in the last six months of 2009.

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        The following are components of pension expense:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 
Service cost   $ 4   $ 3   $ 7   $ 8  
Interest cost     3     2     6     6  
Expected return on plan assets     (2 )   (2 )   (4 )   (5 )
Amortization of net loss     1         2      
                   
Total expense   $ 6   $ 3   $ 11   $ 9  
                   

Postretirement Benefits Other Than Pensions

        As of June 30, 2009, EME had made approximately $1 million in contributions to its postretirement benefits other than pensions and estimates to make $1 million of contributions in the last six months of 2009.

        The following are components of postretirement benefits expense:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 
Service cost   $   $   $ 1   $ 1  
Interest cost     2     2     3     3  
Amortization of prior service credit     (1 )   (1 )   (1 )   (1 )
Amortization of net loss     1     1     1     1  
                   
Total expense   $ 2   $ 2   $ 4   $ 4  
                   

Note 10.  Income Taxes

        EME's income tax provision from continuing operations was $17 million and $116 million for the six months ended June 30, 2009 and 2008, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the six months ended June 30, 2009 and 2008, EME recognized $30 million and $20 million, respectively, of production tax credits related to wind projects. In addition, EME recognized additional income tax benefits of $1 million and $3 million during the six months ended June 30, 2009 and 2008, respectively, related to estimated additional taxes or benefits allocated from Edison International. Effective January 1, 2009, the state of Massachusetts changed its tax regulations from a separate return, where each entity files separately, to a combined return for Edison International and its subsidiaries.

        EME's investments in wind-powered electric generation qualify for federal production tax credits under Section 45 of the Internal Revenue Code. The American Recovery and Reinvestment Act of 2009 provides for an option to claim investment tax credits (30% of eligible property placed in service during 2009 through 2011) or obtain cash grants for specified renewable energy projects in lieu of tax credits (also 30% of eligible property placed in service during 2009 through 2011). These options would be in lieu of the production tax credits for wind projects which may otherwise be claimed at an annually indexed rate per megawatt-hour (currently 2.1 cents per kilowatt hour) on actual production during the first 10 years of operation. The election to claim production tax credits or investment tax credits is made at the time a tax return is filed for the first year in which the property is placed in service. Payment in lieu of tax credits (sometimes referred to as cash grants) would be obtained

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separate from the tax return under rules and regulations published by the U. S. Treasury Department. EME has placed the Elkhorn Ridge, Phase II of the Goat Wind and High Lonesome wind projects in service during 2009. EME and its partner in the Elkhorn Ridge project have agreed to continue to claim production tax credits. EME is currently planning to claim investment tax credits for Phase II of the Goat Wind and High Lonesome wind projects. However, this plan is subject to change based on review of the rules and regulations regarding the payments in lieu of tax credits recently issued by the U. S. Treasury Department and tax planning activities during the second part of 2009. EME accounts for investment tax credits on the deferred method and, accordingly, will recognize tax benefits related to such credits over the estimated useful life of the projects.

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

Income Tax Uncertainties

        At June 30, 2009, EME had unrecognized tax benefits of $111 million, all of which, if recognized, would impact the effective tax rate. During the six months ended June 30, 2009, unrecognized tax benefits were reduced by $33 million primarily due to the settlement of tax items with the Internal Revenue Service. The total amount of accrued interest and penalties was $10 million as of June 30, 2009. EME believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $24 million within the next 12 months.

Note 11.  Commitments and Contingencies

Contractual Obligations

Long-term Debt

        EME's long-term debt maturities as of June 30, 2009 for the remainder of 2009 and the following four years were:

 
  (in millions)
 

July through December 2009

  $ 16  

2010

    37  

2011

    36  

2012

    865  

2013

    545  

        These amounts have been updated to reflect EME's financing activities completed during the second quarter of 2009. In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse portfolio financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The portfolio 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 has entered into interest rate swap agreements to hedge the majority of the variable interest rate under the term loan. For further details regarding the interest rate swap agreements, see Note 3—Derivative Instruments.

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Commitments

Capital Improvements

        At June 30, 2009, EME's subsidiaries had firm commitments to spend approximately $110 million during the remainder of 2009 and $14 million in 2010 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects and non-environmental improvements at both the Illinois Plants and the Homer City facilities. These expenditures are planned to be financed by cash on hand and cash generated from operations.

Turbine Commitments

        EME had entered into various turbine supply agreements with vendors to support its wind development efforts. At June 30, 2009, EME had secured the rights to 484 wind turbines (942 MW) for use in future projects for an aggregate purchase price of $1.2 billion, with remaining commitments of $596 million in 2009 and $242 million in 2010. At June 30, 2009, EME had recorded wind turbine deposits of $410 million, included in other long-term assets on its consolidated balance sheet. EME has executed non-binding letter agreements with two of its vendors to provide vendor financing. EME and such vendors are in the process of negotiating definitive agreements based on the non-binding letter agreements, but there is no assurance that final binding agreements will be executed or executed on terms that conform to the letter agreements. If definitive agreements are executed substantially in accordance with the terms of the letter agreements, turbine commitments would be reduced to approximately $191 million in 2009, $229 million in 2010, and $210 million in 2011, and the remaining $206 million due based on specified conditions (expected during the time period of 2011 and 2014). These commitments would be further reduced during this period if a third turbine supplier agrees to provide vendor financing. Furthermore, EME can elect under the existing turbine supply agreement with this supplier to terminate the agreement for convenience which would further reduce turbine commitments to $9 million in 2009 and $49 million in 2010 (in such case, EME would write off approximately $90 million in previously made non-refundable deposits).

Fuel Supply Contracts

        At June 30, 2009, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $417 million, summarized as follows: remainder of 2009—$230 million, 2010—$177 million, and 2011—$10 million.

        In July 2009, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements through 2011, are currently estimated to be $136 million for 2010, $264 million for 2011 and $134 million for 2012.

Standby Letters of Credit

        At June 30, 2009, standby letters of credit under EME and its subsidiaries' credit facilities aggregated $143 million and were scheduled to expire as follows: $60 million in 2009 and $83 million in 2010.

Guarantees and Indemnities

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

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Tax Indemnity Agreements

        In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities.

Indemnities Provided as Part of the Acquisition of the Illinois Plants

        In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. 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 NOV discussed below under "—Contingencies—Midwest Generation New Source Review Notice of Violation" and potential litigation by private groups related to the NOV. Except as discussed below, EME has not recorded a liability related to the environmental indemnity specified in the acquisition agreement.

        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 2010. There were approximately 214 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2009. Midwest Generation had recorded a $51 million liability at June 30, 2009 related to this matter.

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        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.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

        In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by EME Homer City and associated indemnity claims, see "—Contingencies—EME Homer City New Source Review Notice of Violation." EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements

        The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2009, EME had recorded a liability of $97 million (of which $52 million is classified as a current liability) related to these matters.

        In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2009, EME had recorded a liability of $3 million related to these matters.

Contingencies

RPM Buyers' Complaint

        On May 30, 2008, a group of entities referring to themselves as the "RPM Buyers" filed a complaint at the FERC asking that PJM's RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. On September 19, 2008, the FERC dismissed the RPM Buyers' complaint, finding that the RPM Buyers had failed to allege or prove that any party violated PJM's tariff and market rules, and that the prices determined during the transition period were determined in accordance with PJM's FERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC's order dismissing their complaint. On June 18, 2009, the FERC denied rehearing of the order.

Midwest Generation New Source Review Notice of Violation

        On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of

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the CAA, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV.

        On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV. On July 28, 2009, Midwest Generation received a sixty-day Notice of Intent to Sue signed by the same groups, stating their intent to file a citizen suit alleging exceedances of CAA opacity limits and violations of permit requirements related to monitoring and reporting.

        By letter dated August 8, 2007, Commonwealth Edison 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 NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

        Midwest Generation cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

EME Homer City New Source Review Notice of Violation

        On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the CAA. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009, the US EPA issued a request for information to EME Homer City under Section 114 of the CAA. EME Homer City is working on a response to the request. EME Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME Homer City cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

        EME Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.

        EME Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, have sought indemnification and defense from EME Homer City for costs and liability associated with the EME Homer City NOV. EME Homer City responded by undertaking the indemnity obligation and defense of the claims.

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Environmental Matters and Regulations

        The construction and operation of power plants are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with existing environmental regulatory requirements. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which EME and its subsidiaries conduct their businesses and could require substantial additional capital or operational expenditures or the ceasing of operations at certain of their facilities. There is no assurance that EME's financial position and results of operations would not be materially adversely affected. EME is unable to predict the precise extent to which additional laws and regulations may affect its future operations and capital expenditure requirements. For a more complete discussion of EME's environmental contingencies, refer to "Note 12—Commitments and Contingencies—Environmental Matters and Regulations" on page 156 of EME's annual report on Form 10-K for the year ended December 31, 2008.

        Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects, which may involve significant capital or operational expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by federal and state regulatory authorities.

        With respect to EME's potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $5 million at June 30, 2009 for estimated environmental investigation and remediation costs for the Illinois 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 requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

Note 12. Supplemental Cash Flows Information

 
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
 
  (in millions)
 
Cash paid              
  Interest (net of amount capitalized)(1)   $ 139   $ 124  
  Income taxes     12     142  
  Cash payments under plant operating leases     200     201  

(1)
Interest capitalized for the six months ended June 30, 2009 and 2008 was $10 million and $18 million, respectively.

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ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect EME's current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by EME that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this quarterly report on Form 10-Q, 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, or that otherwise could impact EME or its subsidiaries, include but are not limited to:

    EME's ability to borrow funds and access capital markets on reasonable terms, particularly in light of current credit conditions in the capital markets and uncertainty over the global economic outlook;

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

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

    the cost and availability of fuel and fuel transportation services;

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

    the cost and availability of emission credits or allowances;

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

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

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

    EME's ability to successfully implement its business strategy, including development projects and future acquisitions;

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

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

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

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

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

    project development risks, including those related to siting, financing, construction, permitting, and governmental approvals;

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

    general political, economic and business conditions;

    weather conditions, natural disasters and other unforeseen events; and

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

        Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in "Item 1A. Risk Factors" on page 27 of EME's annual report on Form 10-K for the year ended December 31, 2008. Readers are urged to read this entire quarterly report on Form 10-Q 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.

        This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2008, and as compared to the second quarter of 2008 and six months ended June 30, 2008. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2008.

        This MD&A is presented in four sections:

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MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Overview

Introduction

        EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. As of June 30, 2009, EME's subsidiaries and affiliates owned or leased interests in 38 operating projects and one wind project under construction. Since EME as a holding company does not directly own any revenue producing generation facilities, it depends for the most part on cash distributions from its projects to meet its debt service obligations, and to pay for general and administrative expenses. Distributions to EME from projects are subject to approval of the applicable entities' governing bodies and are generally only available after all obligations, including debt service if applicable, at the project level have been paid. In addition, to the extent there is project level debt, distributions may be restricted by contractual limitations included in such project level debt obligations. For further information on distributions to EME, see "Liquidity and Capital Resources—EME's Liquidity as a Holding Company."

Economic Conditions and Commodity Prices

        Continuation of the economic recession, among other factors, contributed to declines in electrical demand for Northern Illinois and PJM West Hub locations during the six months ended June 30, 2009. The electrical load, calculated from published data by PJM, for these locations declined 6% and 4%, respectively, compared to the six months ended June 30, 2008. The decline in price of natural gas, which often serves as the marginal fuel source in the region, together with lower electrical demand have resulted in significantly lower energy prices. Furthermore, spot energy prices affecting the Illinois Plants were adversely impacted, particularly during some off-peak periods, by congestion affecting the Northern Illinois control area. The average 24-hour PJM market price for energy at the Northern Illinois Hub and the PJM West Hub declined to $30.08/MWh and $41.40/MWh, respectively, during the six months ended June 30, 2009 as compared to $52.42/MWh and $72.17/MWh, respectively, during the six months ended June 30, 2008. In the first six months ended June 30, 2009, Midwest Generation's and EME Homer City's average realized energy price per MWh were higher than the average 24-hour PJM market prices due to higher hedge prices. As reflected in the net income summary below, these factors had an adverse impact on the results of operations during the second quarter and six months ended June 30, 2009. Lower electrical load has also generally decreased congestion in the eastern power grid, thereby resulting in lower trading income in the second quarter and six months ended June 30, 2009.

Environmental Compliance Plans and Costs

        As discussed in the 2008 Annual Report on Form 10-K, Midwest Generation is subject to various commitments with respect to environmental compliance for the Illinois Plants under the CPS. During the second quarter of 2009, Midwest Generation conducted tests of selective non-catalytic NOX removal technologies and reagent based SO2 removal technologies that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has preliminarily concluded that installation of selective non-catalytic NOX removal technologies, in lieu of selective catalytic removal technologies, should meet the NOX portion of the CPS. Testing of flue gas desulfurization technology based on injection of dry sodium sorbent demonstrated significant reductions in SO2; however, further analysis and evaluation are required to determine the appropriate path forward to comply with the SO2 portion of the CPS. These technologies may be deployed at the Illinois Plants in a manner which could

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optimize compliance, subject to approval of construction permits by the Illinois EPA. A decision regarding whether or not to proceed with the alternative compliance program, as described above, will occur following further analysis and evaluation of results. Under current conditions, Midwest Generation cannot predict what specific method will be used or all costs that will be incurred to comply with the CPS.

Climate Change Legislation

        On June 26, 2009, the American Clean Energy and Security Act was passed by the U.S. House of Representatives. The bill would establish a 20% mandatory federal combined efficiency and renewable electricity standard for certain retail electricity suppliers and establish a cap-and-trade system for carbon emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate greenhouse gas emissions from all covered entities would be established and decline over time. Emitters of greenhouse gases would be required to have allowances for greenhouse gas emissions emitted during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated (including allocation to merchant generators) free of charge in declining amounts over time. Emitters of greenhouse gases would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative greenhouse gas conservation efforts). Legislation to regulate greenhouse gas emissions is now being considered by the U.S. Senate, and the timing, content, and potential effects on EME of climate change legislation, if any that may be ultimately passed by the Congress and signed into law by the President remain uncertain.

Business Development and Capital Commitments

        At June 30, 2009, EME had 1,085 MW of wind projects in service and one project (100 MW) under construction (completed in July 2009). EME's wind projects under construction are currently funded through internally generated funds and cash on hand. During the second quarter of 2009, a subsidiary of EME completed a $202 million project financing of EME's interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For further discussion of this financing, see "Liquidity and Capital Resources—Wind Financing."

        EME is continuing to preserve capital by focusing on a selective growth strategy, primarily on completion of projects under construction and development of sites for future renewable projects deploying current turbine commitments. EME has contracts for the purchase of 942 MW of new wind turbines with scheduled payment obligations of up to $596 million in 2009 and $242 million in 2010. A significant portion of turbine payments scheduled during the first half of 2009 were deferred by agreement with certain suppliers. EME has executed non-binding letter agreements with two of its vendors to provide vendor financing. EME and such vendors are in the process of negotiating definitive agreements based on the non-binding letter agreements, but there is no assurance that final binding agreements will be executed or executed on terms that conform to the letter agreements. If definitive agreements are executed substantially in accordance with the terms of the letter agreements, turbine commitments would be reduced to approximately $191 million in 2009, $229 million in 2010, and $210 million in 2011, and the remaining $206 million due based on specified conditions (expected during the time period of 2011 and 2014). These commitments would be further reduced during this period if a third turbine supplier agrees to provide vendor financing. Furthermore, EME can elect under the existing turbine supply agreement with this supplier to terminate the agreement for convenience which would further reduce turbine commitments to $9 million in 2009 and $49 million in 2010 (in such case, EME would write off approximately $90 million in previously made non-refundable deposits).

        Subject to completion of definitive agreements discussed above, EME plans to use the wind turbines currently under contract to complete the Big Sky wind project. EME plans to defer

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construction expenditures for other new wind projects until financing becomes available, which may require power purchase agreements. EME continues to participate in requests for proposals issued by potential customers and negotiate with potential customers for which proposals have been short-listed, but there is no assurance that these power purchase agreements will be executed or executed in a timely manner. Furthermore, delays by customers in the award of new power purchase agreements would increase the time to complete development of new wind projects, thereby delaying EME's expectation on timing of new projects. If EME is unable to obtain power purchase agreements, complete development of wind projects, and obtain project financing on acceptable terms and conditions, it may terminate a portion of the turbines on order. Such an event would likely result in a material charge. EME plans to store turbines that are delivered until needed for construction of new wind projects.

Net Income Attributable to EME Summary

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Income from continuing operations

  $ 47   $ 73   $ 100   $ 223  

Loss from discontinued operations

    (7 )   (1 )   (4 )   (6 )
                   

Net Income attributable to EME common shareholders

  $ 40   $ 72   $ 96   $ 217  
                   

        EME's decrease in income from continuing operations during the second quarter and six months ended June 30, 2009, compared to the second quarter and six months ended June 30, 2008 was primarily attributable to a significant decline in earnings from the Illinois Plants from lower power prices and generation levels as well as lower energy trading income. These decreases were partially offset by higher earnings from the Homer City facilities. Income from continuing operations during the six months ended June 30, 2008 included the favorable buyout of a coal contract at the Illinois Plants.

        For further discussion of EME's operating results, see "Results of Operations."

Critical Accounting Policies and Estimates

        For a discussion of EME's critical accounting policies, refer to "Critical Accounting Policies and Estimates" in Item 7 on page 45 of EME's annual report on Form 10-K for the year ended December 31, 2008.

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RESULTS OF OPERATIONS

Introduction

        This section discusses operating results for the second quarters of 2009 and 2008 and six months ended June 30, 2009 and 2008, and is organized under the following headings:


Results of Continuing Operations

Overview

        EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the Illinois Plants and the Homer City facilities. Equity in income from unconsolidated affiliates relates to energy projects accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

        EME uses the words "earnings" or "losses" in this section to describe adjusted operating income (loss) as described below.

        The following section and table provide a summary of results of EME's operating projects and corporate expenses for the second quarters of 2009 and 2008 and six months ended June 30, 2009 and 2008, 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 of EME's projects:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Illinois Plants

  $ 74   $ 111   $ 188   $ 342  

Homer City

    47     (13 )   83     41  

Renewable energy projects

    11     25     37     33  

Energy trading

    17     51     27     92  

Big 4 projects

    11     28     17     36  

Sunrise

    6     6     1     5  

Doga

    8     8     8     8  

March Point

    1         3      

Westside projects

        1     3     5  

Other non-wind projects

    3     4     5     6  
                   

    178     221     372     568  

Corporate administrative and general

    (43 )   (42 )   (79 )   (82 )

Corporate depreciation and amortization

    (3 )   (2 )   (6 )   (5 )
                   

Adjusted Operating Income(1)

  $ 132   $ 177   $ 287   $ 481  
                   

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Adjusted Operating Income

  $ 132   $ 177   $ 287   $ 481  

Less:

                         
 

Equity in earnings of unconsolidated affiliates

    20     37     26     49  
 

Dividend income from projects

    9     9     10     10  
 

Production tax credits

    14     11     30     20  
 

Other income (expense), net

    1     (1 )   2     5  
                   

Operating Income

  $ 88   $ 121   $ 219   $ 397  
                   

(1)
Adjusted operating income is equal to operating income under GAAP, plus equity in earnings of unconsolidated affiliates, dividend income from projects, production tax credits and other income and expenses. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Adjusted operating income is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits and other income and expenses in adjusted operating income is more meaningful for investors as these components are integral to the operating results of EME.

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Earnings from Consolidated Operations

Illinois Plants

        The following table presents additional data for the Illinois Plants:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating Revenues

  $ 340   $ 391   $ 724   $ 859  

Operating Expenses

                         
 

Fuel(1)

    110     106     233     224  
 

Gain on sale of emission allowances(2)

        (1 )       (3 )
 

Plant operations

    106     125     202     219  
 

Plant operating leases

    19     18     38     37  
 

Depreciation and amortization

    27     27     54     52  
 

Gain on buyout of contract and disposal of assets

                (16 )
 

Administrative and general

    5     5     10     11  
                   
 

Total operating expenses

    267     280     537     524  
                   

Operating Income

    73     111     187     335  
                   

Other Income (Expense)

    1         1     7  
                   

Adjusted Operating Income(3)

  $ 74   $ 111   $ 188   $ 342  
                   

Statistics(4)

                         
 

Generation (in GWh):

                         
   

Energy only contracts

    6,361     5,533     12,117     12,071  
   

Load requirements services contracts(5)

    447     1,287     1,333     3,132  
                   
   

Total

    6,808     6,820     13,450     15,203  
 

Aggregate plant performance:

                         
   

Equivalent availability(6)

    78.5%     72.6%     80.6%     77.5%  
   

Capacity factor(7)

    57.1%     57.2%     51.2%     63.7%  
   

Load factor(8)

    72.7%     78.7%     63.5%     82.2%  
   

Forced outage rate(9)

    5.7%     6.5%     6.4%     9.3%  
 

Average realized price/MWh:

                         
   

Energy only contracts(10)

  $ 41.38   $ 52.67   $ 44.41   $ 52.94  
   

Load requirements services contracts(11)

  $ 62.47   $ 62.48   $ 62.52   $ 62.40  
 

Capacity revenue only (in millions)

  $ 42   $ 20   $ 81   $ 29  
 

Average realized fuel costs/MWh(12)

  $ 18.19   $ 15.56   $ 18.37   $ 14.74  

(1)
Included in fuel costs were $14 million and $33 million during the second quarter and six months ended June 30, 2009 related to the net cost of emission allowances. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

(2)
The Illinois Plants sold excess SO2 emission allowances to the Homer City facilities at fair market value. Sales to the Homer City facilities were $2 million during the six months ended June 30, 2008. These sales reduced operating expenses. EME recorded $3 million of intercompany profit during the six months ended June 30, 2008 consisting of $2 million related to emission allowances sold by the Illinois Plants to the Homer City facilities during the fourth quarter of 2007, but not used by the Homer City facilities until the first quarter of 2008, and $1 million related to emission allowances sold by the Illinois Plants to the Homer City facilities during the first quarter of 2008, but not used by the Homer City facilities until the second quarter of 2008.

(3)
As described above, adjusted operating income is equal to operating income plus other income (expense). Adjusted operating income is a non-GAAP performance measure and may not be comparable to those of other companies.

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    Management believes that inclusion of other income (expense) is more meaningful for investors as the components of other income (expense) are integral to the results of the Illinois Plants.

(4)
This table summarizes key performance measures related to coal-fired generation, which represents the majority of the operations of the Illinois Plants.

(5)
Represents two load requirements services contracts, awarded as part of an Illinois auction, with Commonwealth Edison that commenced on January 1, 2007. One contract expired in May 2008 and the remaining contract expired in May 2009.

(6)
The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(7)
The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.

(8)
The load factor is determined by dividing capacity factor by the equivalent availability factor.

(9)
Midwest Generation refers to unplanned maintenance as a forced outage.

(10)
The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized gains (losses) and other non-energy related revenue by (ii) generation as shown in the table below. Revenue related to capacity sales are excluded from the calculation of average realized energy price.
 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating revenues

  $ 340   $ 391   $ 724   $ 859  

Less:

                         
 

Load requirements services contracts

    (28 )   (81 )   (83 )   (196 )
 

Unrealized (gains) losses

    (5 )   3     (20 )   8  
 

Capacity and other revenues

    (44 )   (22 )   (83 )   (32 )
                   

Realized revenues

  $ 263   $ 291   $ 538   $ 639  
                   

Generation (in GWh)

    6,361     5,533     12,117     12,071  

Average realized energy price/MWh

  $ 41.38   $ 52.67   $ 44.41   $ 52.94  

    The average realized energy price is presented as an aid in understanding the operating results of the Illinois 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 more meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the Illinois Plants operating revenues presented above to consolidated operating revenues is set forth below.

 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating revenues:

                         
 

Illinois Plants

  $ 340   $ 391   $ 724   $ 859  
 

Homer City facilities

    161     127     326     312  
 

Renewable energy projects

    31     34     75     50  
 

Other revenues

    25     61     44     111  
                   

Consolidated operating revenues as reported

  $ 557   $ 613   $ 1,169   $ 1,332  
                   
(11)
The average realized price reflects the contract price for sales to Commonwealth Edison under load requirements services contracts that include energy, capacity and ancillary services. It is determined by dividing (i) contract revenue less PJM operating and ancillary charges by (ii) generation.

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(12)
The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including the effects of hedges. It is determined by dividing (i) fuel expense adjusted for unrealized gains (losses) by (ii) generation as shown in the table below.
 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Fuel expenses

  $ 110   $ 106   $ 233   $ 224  

Add back:

                         
 

Unrealized gains (losses)

    14         14      
                   

Realized fuel expenses

  $ 124   $ 106   $ 247   $ 224  
                   

Generation (in GWh)

    6,808     6,820     13,450     15,203  

Average realized fuel costs/MWh

  $ 18.19   $ 15.56   $ 18.37   $ 14.74  

    The average realized fuel cost is presented as an aid in understanding the operating results of the Illinois Plants. Average realized fuel cost is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel expenses. Management believes that average realized fuel cost is more meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the Illinois Plants fuel expense presented above to consolidated fuel expense is set forth below.

 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Fuel expense:

                         
 

Illinois Plants

  $ 110   $ 106   $ 233   $ 224  
 

Homer City facilities

    63     52     127     124  
 

Other

    (1 )   (1 )   (1 )   (4 )
                   

Consolidated fuel expense as reported

  $ 172   $ 157   $ 359   $ 344  
                   

        Earnings from the Illinois Plants decreased $37 million and $154 million in the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The 2009 decreases in earnings were primarily attributable to decreases in realized gross margin of $77 million and $186 million in the second quarter and six months ended June 30, 2009, respectively, partially offset by higher unrealized gains related to hedge contracts (described below) and lower plant operations expense. Realized gross margin was affected by the following factors:

    lower average realized energy prices and lower generation due to lower energy prices and increased congestion affecting the Northern Illinois control area;

    higher fuel costs primarily due to annual NOX emission allowance costs commencing in January 2009, operation of mercury controls and an increase in the cost of coal; and

    partially offsetting the above, higher capacity revenue primarily due to higher capacity prices in the RPM auction.

        In addition, earnings were lower for the six months ended June 30, 2009 due to a gain of $15 million recorded in 2008 related to the buyout of a fuel contract and an estimated insurance recovery of approximately $6 million recorded in 2008 primarily related to the outages at the Powerton Station.

        Included in operating revenues were unrealized gains (losses) of $5 million and $(3) million for the second quarters of 2009 and 2008, respectively, and $20 million and $(8) million for the six months ended June 30, 2009 and 2008, respectively. Unrealized gains in 2009 were primarily due to hedge contracts that are not accounted for as cash flow hedges under SFAS No. 133 (referred to as economic hedges). Unrealized losses in 2008 were primarily due to the ineffective portion of hedge contracts at

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the Illinois Plants attributable to changes in the difference between energy prices at NiHub (the settlement point under forward contracts) and the energy prices at the Illinois Plants busbars (the delivery point where power generated by the Illinois Plants is delivered into the transmission system) resulting from marginal losses. Included in fuel expenses were unrealized gains of $14 million for the second quarter and six months ended June 30, 2009 due to oil futures contracts that were accounted for as economic hedges. The contracts were entered into to hedge a portion of a fuel adjustment provision of a rail transportation contract. For more information regarding forward market prices and unrealized gains (losses), see "Market Risk Exposures—Commodity Price Risk" and "Market Risk Exposures—Accounting for Derivative Instruments," respectively.

Homer City

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating Revenues

  $ 161   $ 127   $ 326   $ 312  

Operating Expenses

                         
 

Fuel(1)

    63     52     127     124  
 

Loss on sale of emission allowances(2)

    1         1      
 

Plant operations

    21     57     55     86  
 

Plant operating leases

    25     26     50     51  
 

Depreciation and amortization

    3     4     8     8  
 

Administrative and general

    1     1     2     2  
                   
 

Total operating expenses

    114     140     243     271  
                   

Operating Income (Loss)

    47     (13 )   83     41  
                   

Other Income

                 
                   

Adjusted Operating Income (Loss)(3)

  $ 47   $ (13 ) $ 83   $ 41  
                   

Statistics

                         
 

Generation (in GWh)

    3,025     2,250     5,683     5,442  
 

Equivalent availability(4)

    90.5%     61.6%     83.7%     74.6%  
 

Capacity factor(5)

    73.4%     54.6%     69.3%     66.0%  
 

Load factor(6)

    81.1%     88.7%     82.8%     88.6%  
 

Forced outage rate(7)

    7.0%     12.1%     9.5%     10.6%  
 

Average realized energy price/MWh(8)

  $ 46.24   $ 53.81   $ 51.29   $ 55.06  
 

Capacity revenue only (in millions)

  $ 18   $ 11   $ 30   $ 19  
 

Average fuel costs/MWh

  $ 20.91   $ 23.23   $ 22.36   $ 22.84  

(1)
Included in fuel costs were $1 million and $2 million during the second quarters of 2009 and 2008, respectively, and $8 million and $7 million during the six months ended June 30, 2009 and 2008, respectively, related to the net cost of emission allowances. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

(2)
The Homer City facilities sold seasonal NOX emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $1 million during the six months ended June 30, 2009. These sales reduced operating expenses. EME recorded $1 million of intercompany loss during the second quarter of 2009 related to emission allowances sold by the Homer City facilities to the Illinois Plants during the first quarter of 2009, but not used by the Illinois Plants until the second quarter of 2009.

(3)
As described above, adjusted operating income (loss) is equal to operating income (loss) plus other income. Adjusted operating income (loss) is a non-GAAP performance measure and may not be comparable to those of other companies.

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    Management believes that inclusion of other income is more meaningful for investors as the components of other income are integral to the results of the Homer City facilities.

(4)
The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(5)
The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.

(6)
The load factor is determined by dividing capacity factor by the equivalent availability factor.

(7)
Homer City refers to unplanned maintenance as a forced outage.

(8)
The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized gains (losses) and other non-energy related revenue by (ii) total generation as shown in the table below. Revenue related to capacity sales are excluded from the calculation of average realized energy price.
 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating revenues

  $ 161   $ 127   $ 326   $ 312  

Less:

                         
 

Unrealized (gains) losses

    (5 )   6     (5 )   7  
 

Capacity and other revenues

    (17 )   (11 )   (30 )   (19 )
                   

Realized revenues

  $ 139   $ 122   $ 291   $ 300  
                   

Generation (in GWh)

    3,025     2,250     5,683     5,442  

Average realized energy price/MWh

  $ 46.24   $ 53.81   $ 51.29   $ 55.06  

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

 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating revenues:

                         
 

Illinois Plants

  $ 340   $ 391   $ 724   $ 859  
 

Homer City facilities

    161     127     326     312  
 

Renewable energy projects

    31     34     75     50  
 

Other revenues

    25     61     44     111  
                   

Consolidated operating revenues as reported

  $ 557   $ 613   $ 1,169   $ 1,332  
                   

        Earnings from Homer City increased $60 million and $42 million for the second quarter and six months ended June 30, 2009, compared to the corresponding periods of 2008. The second quarter increase in earnings was primarily attributable to higher realized gross margin and lower plant maintenance expenses. The increase in realized gross margin was primarily due to higher capacity revenues and higher generation (driven primarily by higher availability), partially offset by lower average realized energy prices. The year-to-date increase in earnings was primarily attributable to lower plant maintenance expenses. In 2008, higher forced outages, lower off-peak dispatch and extended planned overhauls contributed to lower generation and higher maintenance expenses.

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        Included in operating revenues were unrealized gains (losses) from hedging activities of $5 million and $(6) million for the second quarters of 2009 and 2008, respectively, and $5 million and $(7) million for the six months ended June 30, 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 under SFAS No. 133. The ineffective portion of hedge contracts at Homer City was primarily attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains (losses), see "Market Risk Exposures—Commodity Price Risk" and "Market Risk Exposures—Accounting for Derivative Instruments," respectively.

Seasonal Disclosure

        Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the Illinois Plants and the Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinois Plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants" and "—Energy Price Risk Affecting Sales from the Homer City Facilities."

Renewable Energy Projects

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Operating Revenues

  $ 31   $ 34   $ 75   $ 50  

Production Tax Credits

    14     11     30     20  
                   

    45     45     105     70  
                   

Operating Expenses

                         
   

Plant operations

    12     8     25     14  
   

Depreciation and amortization

    21     12     41     22  
   

Administrative and general

    1     1     2     2  
                   
   

Total operating expenses

    34     21     68     38  
                   

Other Income

        1         1  
                   

Adjusted Operating Income(1)

  $ 11   $ 25   $ 37   $ 33  
                   

Statistics

                         
 

Generation (in GWh)

    718     565     1,538     1,065  
 

Aggregate plant performance:

                         
   

Equivalent availability

    87.3%     81.8%     84.2%     83.2%  
   

Capacity factor

    30.5%     36.4%     33.4%     37.1%  

(1)
Adjusted operating income is equal to operating income (loss) plus production tax credits and other income. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and

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    state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, adjusted operating income represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in adjusted operating income for wind projects is more meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles adjusted operating income as shown above to operating income (loss) under GAAP:

 
  Three Months Ended
June 30
  Six Months Ended
June 30
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Adjusted Operating Income

  $ 11   $ 25   $ 37   $ 33  

Less:

                         
 

Production tax credits

    14     11     30     20  
 

Other income (expense)

        1         1  
                   

Operating Income (Loss)

  $ (3 ) $ 13   $ 7   $ 12  
                   

        Earnings from renewable energy projects decreased $14 million and increased $4 million for the second quarter and six months ended June 30, 2009, compared to the corresponding periods of 2008. The second quarter decrease in earnings was primarily due to cumulative liquidated damages related to Suzlon wind turbines being recorded during the second quarter of 2008. Earnings for the second quarter of 2009 and 2008 included $5 million and $13 million, respectively, of liquidated damages for availability guarantees provided by Suzlon Wind Energy Corporation. The year-to-date increase in earnings was primarily due to new projects that commenced operations in the last six months of 2008. Earnings for the six months ended June 30, 2009 and 2008 included $16 million and $13 million, respectively, of the Suzlon liquidated damages. At June 30, 2009, EME had a receivable from this vendor of $20 million.

Energy Trading

        EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, and transmission congestion primarily in the eastern power grid using products available over the counter, through exchanges, and from ISOs. Earnings from energy trading activities decreased $34 million and $65 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The 2009 decreases in earnings from energy trading activities were primarily attributable to lower congestion in the eastern power grid resulting primarily from lower electrical load.

Earnings from Unconsolidated Affiliates

Big 4 Projects

        Earnings from the Big 4 projects decreased $17 million and $19 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. Lower earnings in 2009 were primarily due to lower natural gas prices affecting electricity and steam revenues. Partially offsetting these decreases was an increase in earnings from the Kern River project due to a planned outage in 2008. For further discussion regarding power sales from the Midway-Sunset, Sycamore and Watson projects, all of which are selling power to SCE under the terms and conditions contained in their prior long-term power purchase agreements, with revised pricing terms as mandated by California Public Utilities Commission Decision 07-09-040, dated September 20, 2007, and a description of the dispute between SCE and Watson, refer to "Big 4 Projects" in Item 1 on page 12 of EME's annual report on Form 10-K for the year ended December 31, 2008.

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Sunrise

        Earnings from the Sunrise project decreased $4 million for the six months ended June 30, 2009, compared to the corresponding period of 2008. The 2009 year-to-date decrease was primarily due to a planned outage in the first quarter of 2009.

March Point

        During the second quarter and six months ended June 30, 2009, EME recorded its share of equity in income of $1 million and $3 million, respectively, from the March Point project. During the first quarter of 2009, EME commenced recording its share of equity in income from the March Point project. Previously, EME suspended equity accounting since 2005 when its investment in the March Point project was fully impaired. Declining natural gas prices reduced fuel expenses and returned the project to profitability. To the extent that cash is received from the project in excess of EME's investment, such amount will be recorded as equity in income.

Seasonal Disclosure

        EME's third quarter equity in income from its energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer months.

Corporate Administrative and General Expenses

        Administrative and general expenses increased $1 million and decreased $3 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The second quarter increase was primarily due to charges for severance and related costs of $5 million. Partially offsetting this decrease and contributing to the year-to-date decrease was lower employee benefits and consulting costs. In April 2009, EME reduced approximately 75 positions in its regional and corporate offices.

Interest Related Income (Expense)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Interest income

  $ 3   $ 7   $ 6   $ 15  
                   

Interest expense:

                         
 

EME debt

  $ (68 ) $ (61 ) $ (136 ) $ (123 )
 

Non-recourse debt:

                         
   

Midwest Generation

    (2 )       (5 )   (7 )
   

EME CP Holding Co. 

    (1 )   (2 )   (2 )   (3 )
   

Other project

    (2 )   (3 )   (4 )   (4 )
                   

  $ (73 ) $ (66 ) $ (147 ) $ (137 )
                   

Interest Income

        EME's interest income decreased $4 million and $9 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The decreases were primarily attributable to lower interest rates in 2009 compared to 2008.

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Interest Expense

        EME's interest expense to third parties, before capitalized interest, increased $2 million for both the second quarter and six months ended June 30, 2009, compared to the corresponding periods of 2008. The increases were primarily due to higher debt balances under EME's and Midwest Generation's credit facilities in 2009, compared to 2008. Capitalized interest decreased $5 million and $8 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008, due to a reduction in projects under construction.

Income Taxes

        EME's income tax provision from continuing operations was $17 million and $116 million for the six months ended June 30, 2009 and 2008, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the six months ended June 30, 2009 and 2008, EME recognized $30 million and $20 million, respectively, of production tax credits related to wind projects. In addition, EME recognized additional income tax benefits of $1 million and $3 million during the six months ended June 30, 2009 and 2008, respectively, related to estimated additional taxes or benefits allocated from Edison International. Effective January 1, 2009, the state of Massachusetts changed its tax regulations from a separate return basis, where each entity files separately, to a combined return basis where Edison International and its subsidiaries file together.

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


Results of Discontinued Operations

        Loss from discontinued operations, net of tax, was $7 million and $1 million for the second quarters of 2009 and 2008, respectively, and $4 million and $6 million for the six months ended June 30, 2009 and 2008, respectively. The losses in 2009 and 2008 included foreign exchange gains (losses) and interest associated with contract indemnities related to EME's sale of its international projects in December 2004. In addition, EME increased its estimated liability for a tax indemnity by $6 million during the second quarter of 2009.


New Accounting Pronouncements

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

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LIQUIDITY AND CAPITAL RESOURCES

Introduction

        The following discussion of liquidity and capital resources is organized in the following sections:

        For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2008.


EME's Liquidity

        At June 30, 2009, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.7 billion, EME had a total of $88 million of available borrowing capacity under its $600 million corporate credit facility, and Midwest Generation had a total of $22 million of available borrowing capacity under its $500 million working capital facility. EME's consolidated debt at June 30, 2009 was $4.8 billion, of which $39 million was current. In addition, EME's subsidiaries had $3.4 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 26 years.

        The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2009:

 
 
EME
 
Midwest
Generation
 
 
  (in millions)
 

Commitment

  $ 600   $ 500  

Less: Commitment from Lehman Brothers subsidiary

    (36 )    
           

    564     500  

Outstanding borrowings

    (351 )   (475 )

Outstanding letters of credit

    (125 )   (3 )
           

Amount available

  $ 88   $ 22  
           

        On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Commercial Paper Inc., a lender in EME's credit agreement representing a commitment of $36 million, in September 2008 declined requests for funding under that agreement and in October 2008, filed for bankruptcy protection.

        As a result of the recent credit ratings actions described under "—Credit Ratings," the margins applicable to EME's $600 million corporate credit facility and Midwest Generation's $500 million working capital facility increased. The applicable margin on borrowings outstanding under EME's credit

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facility was increased by 50 basis points to 2%. The interest rate on borrowings outstanding under Midwest Generation's credit facility is LIBOR plus 0.875%, except if average utilized commitments during a period exceed $250 million, in which case the margin increases to 1%, which was the case at June 30, 2009. This represents an increase in the applicable margin, assuming utilization exceeds $250 million, of 35 basis points due to the recent credit ratings actions.

        Access to the capital markets remains uncertain due to the financial market and economic conditions discussed in "Management's Overview; Critical Accounting Policies and Estimates—Management's Overview," and also in "Management's Overview" in Item 7 on page 41 of EME's annual report on Form 10-K for the year ended December 31, 2008, though very preliminary signs of improvement are beginning to show as evidenced by EME's successful closing of the $202 million non-recourse wind portfolio financing at the end of the second quarter of 2009. Accordingly, EME's liquidity is currently comprised of cash on hand and cash flow generated from operations. Pending full recovery of the capital markets, EME intends to preserve capital by focusing on a selective growth strategy, primarily on completion of projects under construction and development of sites for future renewable projects deploying current turbine commitments, and using its cash on hand and future cash flow to meet its existing contractual commitments. Long-term disruption in the capital markets could adversely affect EME's business plans and financial position.


Capital Expenditures

        At June 30, 2009, the estimated capital expenditures through 2011 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

 
 
July through
December 2009
 
2010
 
2011
 
 
  (in millions)
 

Illinois Plants

                   
 

Plant capital expenditures

  $ 35   $ 96   $ 62  
 

Environmental expenditures

    9     (1)     (1)  

Homer City Facilities

                   
 

Plant capital expenditures

    13     55     29  
 

Environmental expenditures

        15     32  

New Projects

                   
 

Projects under construction

    55          
 

Turbine commitments(2)

    596     242      

Other capital expenditures

    17     9     7  
               

Total

  $ 725   $ 417   $ 130  
               

(1)
See discussion below regarding capital expenditures for environmental improvements at the Illinois Plants.

(2)
See "Management's Overview; Critical Accounting Policies and Estimates—Management's Overview—Business Development and Capital Commitments" for discussion of potential changes to EME's turbine commitments.

Expenditures for Existing Projects

        Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kv switchgear and main power transformer replacement.

        Midwest Generation is subject to various commitments with respect to environmental compliance. Midwest Generation continues to review all technology and unit shutdown combinations, including interim and alternative compliance solutions. For more information on the current status of environmental improvements in Illinois, see "Management's Overview; Critical Accounting Policies and

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Estimates—Management's Overview—Environmental Compliance Plans and Costs." For further discussion of environmental regulations, refer to "Note 12—Commitments and Contingencies—Environmental Matters and Regulations" on page 156 of EME's annual report on Form 10-K for the year ended December 31, 2008.

Expenditures for New Projects

        At June 30, 2009, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 942 MW. The turbine commitments generally represent approximately two-thirds of the total capital costs of EME's wind projects. As of June 30, 2009, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project 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. Furthermore, successful completion of a wind project is dependent upon obtaining permits and agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed, or that EME will be able to successfully develop projects utilizing all of its turbine commitments. For further discussion, see "Management's Overview; Critical Accounting Policies and Estimates—Management's Overview—Business Development and Capital Commitments."

Big Sky Wind Project

        The Big Sky wind project is a 240 MW planned wind project in Illinois. EME has commenced pre-construction activities for equipment purchases, site development and interconnection activities (approximately $100 million capitalized at June 30, 2009). EME plans to use wind turbines currently under contract to complete the Big Sky wind project. The costs to complete the project, including construction and turbine transportation and installation, are expected to be approximately $165 million. This estimate excludes the turbine costs set forth as turbine commitments in the table above and costs incurred to date. Upon completion, the project plans to sell electricity into the PJM market as a merchant generator or to third-party customers under power sales contracts.

Walnut Creek Project

        Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a ten-year power sales contract starting in 2013 for the output of the Walnut Creek project. In July 2008, the Los Angeles Superior Court found that actions taken by the SCAQMD, in promulgating rules that had made available a "Priority Reserve" of emissions credits for new power generation projects, did not satisfy California environmental laws. In November 2008, the Los Angeles Superior Court enjoined the SCAQMD from issuing Priority Reserve emission credits to any facility, including new power projects, until a satisfactory environmental analysis is completed. Legal challenges related to the Priority Reserve emission credits are continuing. In the air basins regulated by SCAQMD, the need for particulate matter (PM10) and SO2 emission credits exceeds available supply, and it is difficult to create new qualifying credits. Walnut Creek will be unable to begin construction until the legal challenges to the Priority Reserve emission credits have been favorably resolved or another source of credits for the project has been identified. The capital costs to construct this project, excluding interest, are estimated in the range of $500 million to $600 million.

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EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

        Cash used in operating activities from continuing operations decreased $15 million in the first six months of 2009, compared to the first six months of 2008. The 2009 decrease was primarily attributable to an increase in margin deposits received from counterparties related to hedge activities at June 30, 2009, net of the restricted cash balances under margin agreements.

Consolidated Cash Flows from Financing Activities

        Cash provided by financing activities from continuing operations increased $91 million in the first six months of 2009, compared to the first six months of 2008. The 2009 increase was primarily attributable to the proceeds received from the issuance of a $189 million term loan as part of a $202 million project financing completed in June 2009. For further discussion of this financing, see "—Wind Financing." Financing activities in 2008 included net borrowings of $50 million under Midwest Generation's working capital facility.

Consolidated Cash Flows from Investing Activities

        Cash used in investing activities from continuing operations decreased $150 million in the first six months of 2009, compared to the first six months of 2008. The 2009 decrease was primarily due to lower capital expenditures and turbine deposits in 2009, compared to 2008. Partially offsetting this decrease was lower maturities of short-term investments in 2009, compared to 2008, and proceeds from the sale of 33% of EME's membership interest in the Elkhorn Ridge wind project recorded during the second quarter of 2008.


Credit Ratings

Overview

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

 
 
Moody's Rating
 
S&P Rating
 
Fitch Rating

EME(1)

         B2          B          BB-

Midwest Generation(2)

         Ba1          BB-          BBB-

EMMT

  Not Rated          B   Not Rated

(1)
Senior unsecured rating.

(2)
First priority senior secured rating.

        On July 13, 2009, S&P lowered the credit ratings of EME, Midwest Generation and EMMT from BB- to B, BB+ to BB-, and BB- to B, respectively. On June 30, 2009, Moody's lowered the credit ratings of EME and Midwest Generation from B1 to B2 and Baa3 to Ba1, respectively. The S&P ratings remain on negative outlook, while the Moody's rating outlook is stable. In addition, on July 2, 2009, Fitch placed the credit ratings for EME and Midwest Generation on Rating Watch Negative. 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. Furthermore, EME's senior notes do not contain any cross-defaults to subsidiary financings. However, coal contracts at Midwest Generation include provisions that provide the right to

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request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. For discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts".

Credit Rating of EMMT

        The Homer City sale-leaseback documents restrict EME Homer City's ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents also include a requirement that EME Homer City's counterparty to such transactions, whether it is EMMT or another party, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. In order to continue to sell forward the output of the Homer City facilities through EMMT, either: (1) a consent from the sale-leaseback owner participant must be obtained; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participants that allows EME Homer City to enter into such sales, under specified conditions, through March 1, 2014. EME 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 participant at any time. The sale-leaseback owner participants have not indicated that they intend to revoke the consent; however, there can be no assurance that they will not do so in the future. An additional consequence of EMMT's lowered credit rating is that outstanding accounts receivable between EMMT and EME Homer City have been reduced to zero, as required under the terms of the consent. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. For further discussion, see "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities."


Margin, Collateral Deposits and Other Credit Support for Energy Contracts

        To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT, an EME subsidiary engaged in the power marketing and trading business. 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, because the credit ratings of EMMT and EME are below investment grade, 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 June 30, 2009, EMMT had deposited $47 million in cash with clearing brokers in support of futures contracts and had deposited $53 million in cash with counterparties in support of forward energy and congestion contracts. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $46 million at June 30, 2009. In addition, EME had received cash collateral of $275 million at June 30, 2009, to support credit risk of counterparties under margin agreements; $188 million of which is classified as restricted cash. The liability for margin deposits received from counterparties has been offset against net derivative assets.

        Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2009, if wholesale energy prices or the amount hedged changes. EME estimates that margin

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and collateral requirements for energy and congestion contracts outstanding as of June 30, 2009 could increase by approximately $85 million over the remaining life of the contracts using a 95% confidence level. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings." Furthermore, the hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions would result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position on June 30, 2009 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

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


EME's Liquidity as a Holding Company

Overview

        At June 30, 2009, EME had corporate cash and cash equivalents and short-term investments of $858 million to meet liquidity needs. Since EME, as a holding company, does not directly own any revenue-producing generation facilities, it depends for the most part on cash distributions and tax payments from its projects to pay debt service, tax payments, contractual obligations and general and administrative expenses. Distributions to EME from projects are generally only available after all current debt service obligations at the project level have been paid and are further restricted by contractual restrictions on distributions included in the documentation evidencing the project level debt obligations. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. For further discussion, see "—Dividend Restrictions in Major Financings."

Intercompany Tax-Allocation Agreement

        EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. In connection with the settlement of federal tax disputes

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and affirmative claims with the Internal Revenue Service for open tax years 1986 through 2002, EME made a payment of $18 million and assigned a tax receivable of $125 million to its parent, Mission Energy Holding Company, in satisfaction of its obligations under a tax-allocation agreement. In addition, EME received tax-allocation payments, net of $15 million and made tax-allocation payments of $126 million during the first six months of 2009 and 2008, respectively.

EME Homer City Interim Funding Arrangements

        During April 2009, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $25 million to EME Homer City under the subordinated revolving loan agreement in place between Edison Mission Finance and EME Homer City. The funds were used to assist EME Homer City with working capital needs. The proceeds of the subordinated loans were deposited in EME Homer City's operating account. In July 2009, EME Homer City made a repayment of principal and interest of $38 million under the subordinated revolving loan agreement.

EME's Credit Facility Financial Ratios

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

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        The following table sets forth the major components of the interest coverage ratio for the 12 months ended June 30, 2009 and December 31, 2008:

 
  12 Months Ended  
 
 
June 30,
2009
 
December 31,
2008
 
 
  (in millions)
 

Funds Flow Available for Interest

             
 

Distributions:

             
   

Midwest Generation

  $ 290   $ 206  
   

EME Homer City

    80     110  
   

Big 4 Projects(1)

    107     114  
   

Viento Funding II(2)

    164      
   

Other projects

    60     55  
 

Tax payments received from subsidiaries

    230     364  
 

Realized trading income

    78     175  
 

Tax allocation receipts (payments)

    31     (92 )
 

Operating expenses

    (153 )   (155 )
 

Other items, net

    (15 )   (14 )
           

  $ 872   $ 763  
           

Net Interest Expense:

             
 

EME corporate debt

  $ 261   $ 248  
 

Addback: Capitalized interest

    24     32  
 

Powerton-Joliet intercompany notes

    112     112  
 

EME interest income

    (4 )   (6 )
           

  $ 393   $ 386  
           

Ratio

    2.22     1.98  

Covenant threshold (not less than)

    1.20     1.20  

(1)
Prior to the repayment of the Series B bonds of EME Funding Corp. in September 2008, distributions from the Big 4 projects represented funds transferred to EME after meeting debt service and restricted cash provisions set forth in this financing.

(2)
In June 2009, a subsidiary of EME, Viento Funding II, Inc., completed a non-recourse portfolio financing of EME's interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For further details of this financing, see "—Wind Financing." The proceeds of the financing, net of financing costs, were distributed to EME.

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        The following table sets forth the major components of the corporate-debt-to-corporate-capital ratio at June 30, 2009 and December 31, 2008:

 
 
June 30,
2009
 
December 31,
2008
 
 
  (in millions)
 

Corporate Debt

             
 

Indebtedness for money borrowed

  $ 4,526   $ 4,564  
 

Powerton-Joliet termination value

    1,106     1,163  
 

Letters of credit

    128     132  
           

  $ 5,760   $ 5,859  
           

Corporate Capital

             
 

Common shareholder's equity

  $ 2,811   $ 2,684  
 

Less:

             
   

Non-cash cumulative changes in accounting

    1     1  
   

Accumulated other comprehensive income

    (230 )   (200 )
 

Adjustments:

             
   

After-tax losses incurred on termination of Collins lease

    587     587  
   

Dividend to MEHC for repayment of 13.5% notes

    899     899  
           

    4,068     3,971  
           
 

Corporate debt

    5,760     5,859  
           

  $ 9,828   $ 9,830  
           

Corporate-debt-to-corporate-capital ratio

    0.59     0.60  

Covenant threshold (not more than)

    0.75     0.75  


Dividend Restrictions in Major Financings

General

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

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

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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 June 30, 2009 or for the 12 months ended June 30, 2009:

Subsidiary
  Financial Ratio   Covenant   Actual  

Midwest Generation
(Illinois Plants)

 

Debt to Capitalization Ratio

 

Less than or equal to 0.60 to 1

    0.27 to 1  

EME Homer City
(Homer City facilities)

 

Senior Rent Service Coverage Ratio

 

Greater than 1.7 to 1

   
2.57 to 1
 

        For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" in Item 7 on page 74 of EME's annual report on Form 10-K for the year ended December 31, 2008.

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

        EME is restricted from the sale or disposition of assets, which includes the making of a distribution, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding such sale or disposition. At June 30, 2009, the maximum sale or disposition of EME assets is determined as follows:

 
 
June 30, 2009
 
 
  (in millions)
 

Consolidated Net Tangible Assets

       
 

Total consolidated assets

  $ 9,532  
 

Less:

       
   

Consolidated current liabilities

    (538 )
   

Intangible assets

    (135 )
       

  $ 8,859  
       

10% Threshold

  $ 886  

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

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

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Wind Financing

        In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse portfolio financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The portfolio financing included a:

    $189 million seven-year term loan that is expected to fully amortize within the seven years via scheduled principal payments and cash sweeps from a portion of excess cash flow; and

    $13 million letter of credit facility which replaced project letters of credit previously issued under the EME corporate credit facility.

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

        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 has entered into interest rate swap agreements to hedge the majority of the variable interest rate under the term loan. The interest rate swap agreements fixed the majority of the LIBOR rate under the term loan to 3.175%, before amortization of the deferred financing costs. At June 30, 2009, the swap adjusted rate was 7.05%. Distributions from Viento Funding II are subject to compliance with the terms and conditions of credit facilities, including a covenant to meet a 12-month historic debt service coverage ratio as specified in the agreement of 1.20 to 1.0.

        In connection with this financing, EME entered into an agreement with Viento Funding II to make quarterly payments for production tax credits irrespective of whether such credits can be realized on Edison International's consolidated tax returns.


Contractual Obligations

Long-term Debt

        EME's long-term principal debt maturities plus interest payments as of June 30, 2009 were $165 million for the remainder of 2009, $334 million in 2010, $330 million in 2011, $1,152 million in 2012, $804 million in 2013, and $4.7 billion thereafter. These amounts have been updated to reflect EME's financing activities completed during the second quarter of 2009. For further details, see "—Wind Financing."

Fuel Supply Contracts

        At June 30, 2009, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $417 million, summarized as follows: remainder of 2009—$230 million, 2010—$177 million, and 2011—$10 million.

        In July 2009, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements through 2011, are currently estimated to be $136 million for 2010, $264 million for 2011 and $134 million for 2012.

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Off-Balance Sheet Transactions

        For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 on page 81 of EME's annual report on Form 10-K for the year ended December 31, 2008. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report.


Environmental Matters and Regulations

        For a discussion of EME's environmental matters, refer to "Note 12—Commitments and Contingencies—Environmental Matters and Regulations" on page 156 of EME's annual report on Form 10-K for the year ended December 31, 2008. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as follows:

Clean Water Act—Cooling Water Standards and Regulations

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

Air Quality Regulations—Pennsylvania

        The PADEP opacity regulations limit stack opacity to 20% on a one-minute average. PADEP's prior policy recognized the occurrence of transient exceedances of the standard, and allowed such exceedances within certain parameters (below 30% opacity and up to 1.5% of a unit's operating time). On April 18, 2009, the PADEP changed its opacity policy, eliminating many exemptions and reducing the allowable exceedance rate to 0.5% of a unit's operating time, effective as of April 1, 2009. EME has undertaken optimization of unit ramp rates and combustion parameters at the Homer City facilities to reduce the deratings required to meet the opacity standards. Additional capital improvements may also be required. EME Homer City has operated below the 0.5% exceedance rate during the second quarter of 2009.

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MARKET RISK EXPOSURES

Introduction

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

        This section discusses these market risk exposures under the following headings:

        For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2008.


Commodity Price Risk

Introduction

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

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

        EME uses "gross margin at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions at the Illinois Plants, the Homer City facilities, and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure with respect to its trading positions. The use of these measures allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss, and gross margin at risk measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and counterparty credit exposure limits.

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Energy Price Risk Affecting Sales from the Illinois Plants

        All the energy and capacity from the Illinois Plants is sold under terms, including price 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. As discussed further below, power generated at the Illinois Plants is generally sold into the PJM market.

        Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois Plants are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including the Cinergy Hub in the Midwest Independent Transmission System Operator (MISO). These trading hubs have been the most liquid locations for hedging purposes. For further discussion, see "—Basis Risk" below.

        PJM has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in the PJM control area and are physically connected to high-voltage transmission lines serving this market.

        The following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2009 and 2008:

 
  24-Hour
Northern Illinois Hub
Historical Energy Prices(1)
 
 
 
2009
 
2008
 

January

  $ 42.10   $ 47.09  

February

    33.33     54.46  

March

    26.74     58.58  

April

    26.93     53.87  

May

    25.81     44.49  

June

    25.59     56.06  
           

Six-Month Average

  $ 30.08   $ 52.42  
           

(1)
Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.

        Forward market prices at the Northern Illinois 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 Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

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        The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2009:

 
 
24-Hour
Northern Illinois Hub
Forward Energy Prices(1)
 

2009

       
 

July

  $ 31.54  
 

August

    30.33  
 

September

    26.33  
 

October

    25.82  
 

November

    28.63  
 

December

    30.91  

2010 Calendar "strip"(2)

 
$

33.39
 

(1)
Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.

(2)
Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.

        EMMT engages in hedging activities for the Illinois Plants to hedge the risk of future change in the price of electricity. Hedging activities are typically weighted toward on-peak periods. The following table summarizes Midwest Generation's hedge position for contracts entered into at both the Northern Illinois Hub and AEP/Dayton Hub at June 30, 2009:

 
 
2009
 
2010
 
2011
 

GWh

    5,352     6,981     612  

Average price/MWh(1)

  $ 63.91   $ 67.30   $ 76.40  

(1)
The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions at June 30, 2009 are not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

        In addition, as of June 30, 2009, EMMT has entered into 9.8 billion cubic feet of natural gas futures contracts (equivalent to approximately 1,600 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) to hedge Midwest Generation energy price risks during 2009 and 2010.

Energy Price Risk Affecting Sales from the Homer City Facilities

        All the energy and capacity from the Homer City facilities is sold under terms, including price 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. Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

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        The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and the PJM West Hub (EME Homer City's primary trading hub) during the first six months of 2009 and 2008:

 
  Historical Energy Prices(1)
24-Hour PJM
 
 
  Homer City   West Hub  
 
 
2009
 
2008
 
2009
 
2008
 

January

  $ 53.22   $ 54.32   $ 59.32   $ 66.80  

February

    42.86     61.74     46.31     68.29  

March

    38.08     65.37     41.63     70.48  

April

    32.64     61.99     34.48     69.12  

May

    31.39     49.37     33.40     59.84  

June

    29.87     78.72     33.25     98.50  
                   

Six-Month Average

  $ 38.01   $ 61.92   $ 41.40   $ 72.17  
                   

(1)
Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub using historical hourly real-time prices provided on the PJM web-site.

        Forward market prices at the 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 Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below.

        The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2009:

 
 
24-Hour
PJM West Hub
Forward Energy Prices(1)
 

2009

       
 

July

  $ 41.24  
 

August

    41.10  
 

September

    36.23  
 

October

    35.25  
 

November

    38.72  
 

December

    45.15  

2010 Calendar "strip"(2)

 
$

48.63
 

(1)
Energy prices were determined by obtaining broker quotes and information from other public sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.

(2)
Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.

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        EMMT engages in hedging activities for the Homer City facilities to hedge the risk of future change in the price of electricity. Hedging activities are typically weighted toward on-peak periods. The following table summarizes EME Homer City's hedge position at June 30, 2009:

 
 
2009
 
2010
 

GWh

    2,064     2,662  

Average price/MWh(1)

  $ 82.88   $ 90.61  

(1)
The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at June 30, 2009 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

        The average price/MWh for EME Homer City's hedge position is based on the PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. For a discussion of the difference, see "—Basis Risk" below.

Capacity Price Risk

        On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region's need for generation capacity, the cost of which is allocated to load-serving entities through a locational reliability charge.

        The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at June 30, 2009:

 
   
   
   
  RPM Capacity Sold in
Base Residual Auction
  Other Capacity
Sales, net
of Purchases(2)(3)
   
 
 
 
Installed
Capacity
MW
 
Unsold
Capacity(1)
MW
 
Capacity
Sold
MW
 
Aggregate
Average Price
per MW-day
 
 
 
MW
 
Price per
MW-day
 
MW
 
Average Price
per MW-day
 

July 1, 2009 to May 31, 2010

                                                 
 

Midwest Generation

    5,776     (878 )   4,898     5,329   $ 102.04     (431 ) $ 99.23   $ 102.29  
 

EME Homer City

    1,884     (206 )   1,678     1,670     191.32     8     191.32     191.32  

June 1, 2010 to May 31, 2011

                                                 
 

Midwest Generation

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

EME Homer City

    1,884     (71 )   1,813     1,813     174.29             174.29  

June 1, 2011 to May 31, 2012

                                                 
 

Midwest Generation

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

EME 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  
 

EME Homer City

    1,884     (148 )   1,736     1,736     133.37             133.37  

(1)
Capacity not sold arises from: (1) capacity retained to meet forced outages under the RPM auction guidelines, and (2) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.

(2)
Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.

(3)
Includes 342 MW purchases in January 2009 from RPM incremental auction at $40 per MW-day.

        The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $16.46 per MW-day was substantially lower than previous capacity prices. The decrease in forward capacity prices was attributable to a substantial increase in demand side management

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resources. The impact of lower capacity prices for this period on available resources and energy prices is uncertain.

        Revenues from the sale of capacity from Midwest Generation and EME 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 CONE.

Basis Risk

        Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City facilities and for settlement points at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Illinois 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 the six months ended June 30, 2009 and 2008, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 8% and 14%, respectively. The monthly average difference between prices at the Homer City busbar and those at the PJM West Hub during the 12 months ended June 30, 2009 ranged from 5% to 21%. During the six months ended June 30, 2009, transmission congestion in PJM has resulted in prices at the individual busbars of the Illinois Plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 17% and less than 1%, respectively.

        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 EME Homer City and Midwest Generation. A financial transmission right is a financial instrument that entitles the holder to receive the difference between actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME's hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal and Transportation Price Risk

        The Illinois Plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively.

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Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at June 30, 2009 for the remainder of 2009 and the following two years:

 
  Amount of Coal Under Contract
in Millions of Equivalent Tons(1)
 
 
 
July through
December 2009
 
2010
 
2011
 

Illinois Plants(2)

    8.8     11.7      

Homer City facilities(3)

    2.6     1.0     0.2  

(1)
The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Illinois Plants and 13,000 Btu equivalent for the Homer City facilities.

(2)
In July 2009, Midwest Generation entered into additional contractual agreements for the purchase of coal of 5.4 million tons for 2010, 9.8 million tons for 2011 and 9.8 million tons for 2012.

(3)
At June 30, 2009, there are options to purchase additional coal of 0.5 million tons for 2010, 0.6 million tons for 2011, 0.5 million tons for 2012, and 0.1 million tons for 2013.

        EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City facilities, decreased during 2009 from 2008 year-end prices. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) decreased to $46.50 per ton at July 2, 2009 from $76 per ton at January 9, 2009, as reported by the Energy Information Administration. The 2009 decrease in NAPP coal prices was due in part to current global economic conditions that have lessened demand for coal, high levels of inventories and fuel switching. 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 Illinois Plants declined during 2009. The price of PRB coal decreased to $9.00 per ton at July 2, 2009 from $13 per ton at January 9, 2009, as reported by the Energy Information Administration. The 2009 decrease in PRB coal prices was due to lower demand and higher levels of inventory.

        EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are approximately 50% of the delivered cost of PRB coal to the Illinois Plants).

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 Clean Air Interstate Rule, electric generating stations are required to hold seasonal and annual NOX allowances beginning January 1, 2009. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to emission allowances that have been or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. For further discussion of the Clean Air Interstate Rule, refer to "Note 12—Commitments and Contingencies—Environmental Matters and Regulations—Air Quality Regulation—Clean Air Interstate Rule" on page 157 of EME's annual report on Form 10-K for the year ended December 31, 2008.

        EME is subject to price risk for purchases of emission allowances required for actual emissions greater than allowances held. The market price for emission allowances may vary significantly. The average purchase price of SO2 allowances decreased to $66 per ton during the six months ended June 30, 2009 from $315 per ton during 2008. Based on broker's quotes and information from public

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sources, the spot price for SO2 allowances and annual NOX allowances was $70 per ton and $1,113 per ton, respectively, at June 30, 2009.

        For a discussion of environmental regulations related to emissions, refer to "Note 12—Commitments and Contingencies—Environmental Matters and Regulations" on page 156 of EME's annual report on Form 10-K for the year ended December 31, 2008.


Accounting for Derivative Instruments

        EME uses derivative instruments to reduce its exposure to market risks that arise from fluctuations in electricity, capacity and fuel prices, emission allowances and transmission rights. These derivative instruments include forward sales transactions entered into on a bilateral basis with third parties, futures contracts, full requirements services contracts or load requirements services contracts and capacity transactions. SFAS No. 133 requires changes in the fair value of each derivative instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do 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. For further discussion of derivative instruments, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 3. Derivative Instruments," and also refer to "Derivative Financial Instruments and Hedging Activities" in Item 7 on page 45 of EME's annual report on Form 10-K for the year ended December 31, 2008.

        EME classifies unrealized gains and losses from derivative instruments as part of operating revenues or fuel expenses. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the second quarters of 2009 and 2008 and six months ended June 30, 2009 and 2008:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
 
2009
 
2008
 
2009
 
2008
 
 
  (in millions)
 

Illinois Plants

                         
 

Non-qualifying hedges

  $ 18   $ 2   $ 34   $ 2  
 

Ineffective portion of cash flow hedges

    1     (5 )       (10 )

Homer City facilities

                         
 

Non-qualifying hedges

    1     1         2  
 

Ineffective portion of cash flow hedges

    4     (7 )   5     (9 )
                   

Total unrealized gains (losses)

 
$

24
 
$

(9

)

$

39
 
$

(15

)
                   

        At June 30, 2009, unrealized gains of $33 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($6 million for the remainder of 2009, $22 million for 2010, and $5 million for 2011).


Fair Value of Derivative Instruments

        EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. For further discussion of EME's adoption of SFAS No. 157, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Fair Value Measurements."

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Non-Trading Derivative Instruments

        The fair value of outstanding non-trading commodity derivative instruments at June 30, 2009 and December 31, 2008 was $470 million and $375 million, respectively. In assessing the fair value of EME's non-trading commodity derivative instruments, EME uses quoted market prices and forward market prices adjusted for credit risk. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The increase in fair value of commodity contracts at June 30, 2009 as compared to December 31, 2008 is attributable to a decline in the average market prices for power as compared to contracted prices at June 30, 2009, which is the valuation date. The following table summarizes the maturities and the related fair value of EME's commodity derivative assets and liabilities before the impact of offsetting collateral under FIN No. 39-1 as of June 30, 2009:

 
 
Total Fair
Value
 
Maturity
<1 year
 
Maturity
1 to 3
years
 
Maturity
4 to 5
years
 
Maturity
>5 years
 
 
  (in millions)
 

Prices actively quoted

  $ 17   $ 10   $ 7   $   $  

Prices provided by external sources

    450     332     118          

Price based on models and other valuation methods

    3     2     1          
                       

Total

  $ 470   $ 344   $ 126   $   $  
                       

        Prices actively quoted in the preceding table include exchange-traded derivatives. Prices provided by external sources include derivatives whose fair value is based on forward market prices in active markets adjusted for nonperformance risks which would be considered Level 2 derivative positions when there are no unobservable inputs that are significant to the valuation. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.

Energy Trading Derivative Instruments

        The fair value of outstanding energy trading derivative instruments at June 30, 2009 and December 31, 2008 was $128 million and $112 million, respectively. The change in the fair value of trading contracts for the six months ended June 30, 2009 was as follows:

 
  (in millions)
 

Fair value of trading contracts at January 1, 2009

  $ 112  

Net gains from energy trading activities

    30  

Amount realized from energy trading activities

    (24 )

Other changes in fair value

    10  
       

Fair value of trading contracts at June 30, 2009

  $ 128  
       

        The impact of changes to the various inputs used to determine the fair value of Level 3 derivatives is not currently material to EME's results of operations as such changes are offset by similar changes in derivatives classified within Level 3 as well as other categories.

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        The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities before the impact of offsetting collateral under FIN No. 39-1 (as of June 30, 2009):

 
 
Total Fair
Value
 
Maturity
<1 year
 
Maturity
1 to 3
years
 
Maturity
4 to 5
years
 
Maturity
>5 years
 
 
  (in millions)
 

Prices actively quoted

  $ 2   $ 1   $ 1   $   $  

Prices provided by external sources

    (111 )   (99 )   (7 )   (5 )    

Prices based on models and other valuation methods

    237     151     41     28     17  
                       

Total

  $ 128   $ 53   $ 35   $ 23   $ 17  
                       

        In the table above, prices actively quoted include exchange-traded derivatives. Prices provided by external sources include non-exchange-traded derivatives. These are priced based on forward market prices adjusted for nonperformance risks which would be considered Level 2 derivative positions when there are no unobservable inputs that are significant to the valuation. Fair values for Level 2 derivative positions are determined using the same methodology previously described for non-trading derivative instruments. Fair values for Level 3 derivative positions are determined using prices based on models and other valuation methods and include load requirements services contracts, illiquid financial transmission rights, over-the-counter derivatives at illiquid locations and long-term power agreements. For long-term power agreements, EME's subsidiary records these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.


Credit Risk

        In conducting EME's hedging and trading activities, EME contracts with a number of 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 re-contracting the product at a price different from the original contracted price if the nonperforming counterparty were unable to pay the resulting damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.

        To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that EME would expect to incur if a counterparty failed to perform pursuant to the terms of its contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure.

        EME has established processes to determine and monitor the creditworthiness of counterparties. EME manages the credit risk of its counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

        The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair

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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 June 30, 2009, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

 
  June 30, 2009  
Credit Rating(1)
 
Exposure(2)
 
Collateral
 
Net
Exposure
 
 
  (in millions)
 
A or higher   $ 468   $ (263 ) $ 205  
A-     54         54  
BBB+     38         38  
BBB     150         150  
BBB-     4         4  
Below investment grade     3         3  
               
Total   $ 717   $ (263 ) $ 454  
               

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

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

        The credit risk exposure set forth in the above table is comprised of $149 million of net accounts receivable and payables and $568 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties.

        Included in the table above are exposures to financial institutions with credit ratings of A or above. Due to developments in the financial markets, the credit ratings may not be reflective of the related credit risks. For further discussion, refer to "Financial Markets and Economic Conditions" in Item 7 on page 42 of EME's annual report on Form 10-K for the year ended December 31, 2008. The total net exposure to financial institutions at June 30, 2009 was $186 million. This total net exposure excludes positions with Lehman Brothers Holdings and its subsidiaries. Five financial institutions comprise 38% of the net exposure above with the largest single net exposure with a financial institution representing 13%. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $100 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

        EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a power purchase agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power project.

        In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

        EME's merchant plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM

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accounted for approximately 41% of EME's consolidated operating revenues for the six months ended June 30, 2009. Moody's rates PJM's debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At June 30, 2009, EME's account receivable due from PJM was $46 million.

        For the six months ended June 30, 2009, a second customer, Constellation Energy Commodities Group, Inc., accounted for 24% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from EME's merchant plants and largely consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB by S&P and Baa3 by Moody's. At June 30, 2009, EME's account receivable due from Constellation was $25 million.

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


Interest Rate Risk

        Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. In June 2009, EME's subsidiary, Viento Funding II, Inc., entered into interest rate swap agreements in connection with the non-recourse portfolio financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For details, see "Liquidity and Capital Resources—Wind Financing." The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated long-term obligations (including current portion) was $3.9 billion at June 30, 2009, compared to the carrying value of $4.8 billion.


Regulatory Matters

        For a discussion of EME's regulatory matters, refer to "Regulatory Matters" in Item 1 on page 22 of EME's annual report on Form 10-K for the year ended December 31, 2008. There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing of EME's annual report on Form 10-K for the year ended December 31, 2008, except as follows:

RPM CONE

        On March 26, 2009, the FERC issued an order accepting the CONE values submitted by PJM in its February 9, 2009 filing. The FERC-accepted CONE as proposed for the May 2009 RPM auction for the 2012/2013 delivery year is higher than the previously approved CONE value. In addition, the FERC approved a proposal that would set a higher net region-wide CONE value. The FERC also accepted other RPM provisions, such as the holdback of 2.5% of the reliability requirement from the Base Residual Auction to encourage Demand Side Management which could reduce the clearing price for market capacity. Finally, the FERC RPM order directed PJM to file a proposal in September 2009 that would automate the adjustment of CONE (as compared to the existing tariff that requires a CONE evaluation and FERC filing every three years). Several parties have requested rehearing of the order. This matter is currently pending before the FERC.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7 on page 85 of EME's annual report on Form 10-K for the year ended December 31, 2008. For an update to that disclosure, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

ITEM 4T.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

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.

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PART II—OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

        For a discussion of EME's legal proceedings, refer to "Item 3. Legal Proceedings" on page 35 of EME's annual report on Form 10-K for the year ended December 31, 2008. There have been no significant developments with respect to legal proceedings specifically affecting EME since the filing of EME's annual report on Form 10-K for the year ended December 31, 2008.

ITEM 1A.    RISK FACTORS

        For a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial condition, or future results, refer to "Item 1A. Risk Factors" on page 27 of EME's annual report on Form 10-K for the year ended December 31, 2008. The risks described in EME's annual report on Form 10-K and in this report are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.

ITEM 6.    EXHIBITS

Exhibit No.
 
Description
31.1   Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2   Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
32   Statement Pursuant to 18 U.S.C. Section 1350.
101   Financial statements from the quarterly report on Form 10-Q of Edison Mission Energy for the quarter ended June 30, 2009, filed on August 7, 2009, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

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SIGNATURES

        Pursuant to the requirements 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

 

By:

 

/s/ John P. Finneran, Jr.

John P. Finneran, Jr.
Senior Vice President and
Chief Financial Officer
(Duly Authorized Officer and
Principal Financial Officer)

 

Date:

 

August 7, 2009

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