Use these links to rapidly review the documentTABLE 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 COMMISSIONWashington, D.C. 20549



Form 10-Q

(Mark one)ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the Quarterly Period Ended March 31, 2009oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For 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 May 8, 2009: 100 shares (all shares held by an affiliate of the registrant).



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TABLE OF CONTENTS



PageGlossary

iiPART IFinancial InformationItem 1.

Financial Statements

1Item 2.

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

25Item 3.

Quantitative and Qualitative Disclosures about Market Risk

61Item 4T.

Controls and Procedures

61PART IIOther InformationItem 1.

Legal Proceedings

62Item 1A.

Risk Factors

62Item 6.

Exhibits

62Signatures

63


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Table of Contents

GLOSSARY

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

Btu

British thermal unitsCAA

Clean Air ActCommonwealth Edison

Commonwealth Edison CompanyCONE

cost of new entryDOJ

United States Department of JusticeEME

Edison Mission EnergyEME Homer City

EME Homer City Generation L.P.EMMT

Edison Mission Marketing & Trading, Inc.FASB

Financial Accounting Standards BoardFERC

Federal Energy Regulatory CommissionFitch

Fitch RatingsGAAP

generally accepted accounting principlesGWh

gigawatt-hoursIllinois Plants

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

independent system operator(s)MD&A

Management's Discussion and Analysis of Financial Condition and Results of OperationsMidwest Generation

Midwest Generation, LLCMMBtu

million British thermal unitsMoody's

Moody's Investors Service, Inc.MW

megawattsMWh

megawatt-hoursNAPP

Northern AppalachianNOV

notice of violationNOX

nitrogen oxideNYISO

New York Independent System OperatorPADEP

Pennsylvania Department of Environmental ProtectionPJM

PJM Interconnection, LLCPRB

Powder River BasinRPM

reliability pricing modelS&P

Standard & Poor's Ratings Services


ii

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Table of Contents

SCAQMD

South Coast Air Quality Management DistrictSCE

Southern California Edison CompanySFAS

Statement of Financial Accounting Standards issued by the FASBSFAS 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)SO2

sulfur dioxideUS EPA

United States Environmental Protection Agency


iii

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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 March 31,2009

2008Operating Revenues

$
612

$
719Operating ExpensesFuel


187


187Plant operations


149


136Plant operating leases


44


44Depreciation and amortization


56


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


1


(16
)Administrative and general


44


48Total operating expenses


481


443Operating income


131


276Other Income (Expense)Equity in income from unconsolidated affiliates


6


12Dividend income


1


1Interest income


3


8Interest expense


(74
)

(71
)Other income (expense), net


1


6Total other income (expense)


(63
)

(44
)Income from continuing operations before income taxes


68


232Provision for income taxes


15


82Income From Continuing Operations


53


150Income (loss) from operations of discontinued subsidiaries, net of tax (Note 5)


3


(5
)Net Income


56


145Net (Income) Loss Attributable to Noncontrolling Interest





Net Income Attributable to Common Shareholders of EME

$
56

$
145


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 March 31,2009

2008Net Income

$
56

$
145Other comprehensive income (loss), net of tax:Unrealized gains (losses) on derivatives qualified as cash flow hedges:Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $98 and $(92) for the three months ended March 31, 2009 and 2008, respectively


151


(138
)Reclassification adjustments included in net income, net of income tax expense of $32 and $6 for the three months ended March 31, 2009 and 2008, respectively


(49
)

(8
)Other comprehensive income (loss)


102


(146
)Comprehensive Income (Loss)


158


(1
)Comprehensive Income (Loss) Attributable to Noncontrolling Interest





Comprehensive Income (Loss) Attributable to Common Shareholders of EME

$
158

$
(1
)


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)

March 31,
2009

December 31,
2008AssetsCurrent AssetsCash and cash equivalents

$
1,986

$
1,807Short-term investments


3


4Accounts receivabletrade


204


241Receivables from affiliates


44


18Inventory


227


189Derivative assets


216


170Margin and collateral deposits


109


88Prepaid expenses and other


123


144Total current assets


2,912


2,661Investments in Unconsolidated Affiliates


348


362Property, Plant and Equipment


5,733


5,643Less accumulated depreciation and amortization


1,294


1,241Net property, plant and equipment


4,439


4,402Other AssetsDeferred financing costs


35


36Long-term derivative assets


166


170Restricted cash


43


43Rent payments in excess of levelized rent expense under plant operating leases


926


878Other long-term assets


537


528Total other assets


1,707


1,655Total Assets

$
9,406

$
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 (Continued)  (In millions, Unaudited)

March 31,
2009

December 31,
2008Liabilities and Shareholder's EquityCurrent LiabilitiesAccounts payable

$
118

$
95Payables to affiliates


5


18Accrued liabilities


372


380Derivative liabilities


29


22Interest payable


98


30Deferred taxes


110


66Current maturities of long-term obligations


24


24Total current liabilities


756


635Long-term obligations net of current maturities


4,610


4,638Deferred taxes and tax credits


615


541Deferred revenues


62


63Long-term derivative liabilities


2


5Other long-term liabilities


439


434Total Liabilities


6,484


6,316Commitments and Contingencies(Note 10)EquityCommon stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of March 31 2009 and December 31, 2008


64


64Additional paid-in capital


1,336


1,335Retained earnings


1,140


1,085Accumulated other comprehensive income


302


200Total EME common shareholder's equity


2,842


2,684Noncontrolling Interest


80


80Total Equity


2,922


2,764Total Liabilities and Equity

$
9,406

$
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)

Three Months Ended March 31,2009

2008Cash Flows From Operating ActivitiesNet income

$
56

$
145Less: (Income) loss from discontinued operations


(3
)

5Income from continuing operations, net

$
53

$
150Adjustments to reconcile income to net cash provided by operating activities:Equity in income from unconsolidated affiliates


(6
)

(12
)Distributions from unconsolidated affiliates


9


15Depreciation and amortization


56


46Deferred taxes and tax credits


51


11(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


(21
)

(27
)Decrease (increase) in accounts receivable


11


(17
)Increase in inventory


(38
)

(7
)Decrease (increase) in prepaid expenses and other


19


(6
)Increase in rent payments in excess of levelized rent expense


(49
)

(49
)Increase (decrease) in accounts payable and other current liabilities


(5
)

50Increase in interest payable


68


68Decrease (increase) in derivative assets and liabilities


129


(71
)Other operatingassets





(7
)Other operatingliabilities


1


6Operating cash flow from continuing operations


279


134Operating cash flow from discontinued operations


3


(5
)Net cash provided by operating activities


282


129Cash Flows From Financing ActivitiesBorrowings on long-term debt





76Payments on long-term debt agreements


(27
)

(6
)Payments to affiliates related to stock-based awards


(1
)

(5
)Excess tax benefits related to stock-based awards





1Financing costs





(1
)Net cash provided by (used in) financing activities


(28
)

65Cash Flows From Investing ActivitiesCapital expenditures


(94
)

(117
)Proceeds from return of capital and loan repayments and sale of assets


10


8Purchase of interest of acquired companies


(6
)

Maturities of short-term investments


1


47Decrease in restricted cash





2Proceeds from other assets


14


1Net cash used in investing activities


(75
)

(59
)Net increase in cash and cash equivalents


179


135Cash and cash equivalents at beginning of period


1,807


994Cash and cash equivalents at end of period

$
1,986

$
1,129


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  MARCH 31, 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 three months ended March 31, 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.

Cash, Cash Equivalents and Short-term Investments

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

March 31,
2009

December 31,
2008(in millions)Cash

$
127

$
31Money market funds

$
1,847

$
1,581U.S. government agency securities





164Commercial paper





30Time deposits (certificates of deposit)


12


1Total cash equivalents

$
1,859

$
1,776Commercial paper

$
1

$
1Money market funds


2


3Total short-term investments

$
3

$
4Total cash, cash equivalents and short-term investments

$
1,989

$
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 approximates fair value due to maturities of less than three months. For further discussion of money market funds, see Note 2Fair Value Measurements.

At
March 31, 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 approximated

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their
fair value. Gross unrealized holding gains and losses were not material. Held-to-maturity securities all mature within one year.

Inventory

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

March 31,
2009

December 31,
2008(in millions)Coal, fuel oil and other raw materials

$
168

$
131Spare parts, materials and supplies


59


58Total

$
227

$
189


New Accounting Pronouncements

Accounting Principles Adopted

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 quarter 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 shall be 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 quarter 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 6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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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") in the current inactive market. 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. EME will adopt FSP SFAS No. 157-4 in the second
quarter of 2009 and is currently evaluating the impact, if any, that the adoption of this position could have on its consolidated financial statements.

FSP
SFAS No. 115-2

In
April 2009, the FASB issued FSP SFAS No. 115-2, "Recognition and Presentation of Other-Than-Temporary Impairments." FSP SFAS
No. 115-2 changes existing guidance for determining whether impairment is other than temporary for debt securities. Under FSP SFAS No. 115-2, an entity would
write 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 have to sell before recovery. If 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 will adopt FSP SFAS No. 115-2 in the second quarter of 2009 and is currently evaluating the impact, if any, that the adoption of this
position could have on its consolidated financial statements.

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 will
adopt this position in the second quarter of 2009. Since FSP SFAS No. 107-1 and APB No. 28-1 impacts disclosure only, the adoption of this position will not have
an impact on EME's consolidated results of operations, financial position or cash flows.

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:



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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 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
$16 million at March 31, 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. In 2008, EME had
invested $20 million in the Reserve Primary Fund (a money market fund). The Reserve incurred a loss related to debt securities of Lehman Brothers Holdings and had announced liquidation of the
Reserve. EME reduced the fair value of the investment by $1 million and transferred the remaining balance into Level 3 during the third quarter of 2008 as observable market prices were
not available. EME subsequently received $17 million ($16 million and $1 million in 2008 and 2009, respectively) in settlements resulting in the ending balance of
$2 million at March 31, 2009 classified in Level 3.

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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 March 31,
2009 and December 31, 2008:

As of March 31, 2009

Level 1

Level 2

Level 3

Netting and
Collateral(2)

Total(in millions)Assets at Fair ValueMoney market funds(1)

$
1,847

$


$
2

$


$
1,849Derivative contracts


9


577


285


(489
)

382Liabilities at Fair ValueDerivative contracts

$


$
(182
)
$
(18
)
$
169

$
(31
)




As of December 31, 2008

Level 1

Level 2

Level 3

Netting and
Collateral(2)

Total(in millions)Assets at Fair ValueMoney market funds(1)

$
1,581

$


$
3

$


$
1,584Derivative contracts


2


417


221


(300
)

340Liabilities at Fair ValueDerivative contracts

$


$
(145
)
$
(8
)
$
126

$
(27
)


---

The following table sets forth a summary of changes in the fair value of EME's Level 3 derivative contracts, net for the periods ended
March 31, 2009 and 2008:

2009

2008(in millions)Fair value of derivative contracts, net at January 1, 2009 and 2008

$
213

$
120Total realized/unrealized gains (losses):Included in earnings(1)


146


33Included in accumulated other comprehensive income (loss)





(2
)Purchases and settlements, net


(89
)

(37
)Transfers in or out of Level 3


(3
)

(3
)Fair value of derivative contracts, net at March 31, 2009 and 2008

$
267

$
111Change during the periods in unrealized gains (losses) related to derivative contracts, net held at March 31, 2009 and 2008(1)

$
73

$
(4
)


---

The increase in the fair value of Level 3 derivative contracts during the first quarter 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.

Note 3.  Derivative Instruments

EME uses derivative instruments to reduce EME's exposure to fluctuations in the price of electricity, capacity and fuel, emission allowances and transmission
rights which may impact cash flow from its power plant operations. To the extent that EME does not use derivative instruments to hedge

11

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these
price 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:



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.

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 energy contracts in operating
revenues. 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

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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.

Notional Volumes of Derivative Instruments

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

Hedging ActivitiesCommodity

Instrument

Classification

Unit of
Measure

Cash Flow
Hedges

Economic
Hedges

Trading
ActivitiesElectricity

Forwards

Sales

GWh


19,879
(1)

23,361
(3)

23,034Electricity

Forwards

Purchases

GWh





22,005
(3)

23,511Electricity

Capacity

Sales

MW-Day
(in thousands)


315
(2)




574,225
(2)Electricity

Capacity

Purchases

MW-Day
(in thousands)


288
(2)




707,625
(2)Electricity

Congestion

Sales

GWh





136
(4)

5,049
(4)Electricity

Congestion

Purchases

GWh





1,041
(4)

105,917
(4)Natural gas

Forwards

Sales

billion cubic feet





9.2


28.8Natural gas

Forwards

Purchases

billion cubic feet








28.0Fuel oil

Forwards

Sales

Barrels








55,000Fuel oil

Forwards

Purchases

Barrels





25,200,000


55,000


---

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Table of Contents

Fair Value of Derivative Instruments

The following table summarizes the gross fair value of commodity derivative instruments at March 31, 2009:

Derivative Assets

Derivative LiabilitiesShort-term

Long-term

Subtotal

Short-term

Long-term

Subtotal

Net Assets(in millions)Non-trading activitiesCash flow hedges

$
372

$
203

$
575

$
17

$
15

$
32

$
543Economic hedges


282


122


404


276


113


389


15Trading activities


540


192


732


507


112


619


113$
1,194

$
517

$
1,711

$
800

$
240

$
1,040

$
671Netting and collateral received


(978
)

(351
)

(1,329
)

(771
)

(238
)

(1,009
)

(320
)Total

$
216

$
166

$
382

$
29

$
2

$
31

$
351


Income Statement Impact of Derivative Instruments

The following table provides the activity of accumulated other comprehensive income for the three months ended March 31, 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

$
398Effective portion of changes in fair value


249Reclassification from accumulated other comprehensive income to net income


(81
)
Operating revenues(2)Accumulated other comprehensive income derivative gain at March 31, 2009

$
566


---

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 losses of none and $13 million during the first quarters of 2009 and 2008, respectively,
representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues in the income statement.

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 period ended
March 31, 2009 is presented below:

Type

Location

Amount(in millions)Economic hedges

Operating revenue

$
14Trading activities

Operating revenue


10


14

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Table of Contents

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 margining, 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 margining, 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 March 31, 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 $53 million and $51 million at March 31, 2009 and December 31, 2008, respectively.
Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $373 million and $225 million at March 31, 2009 and
December 31, 2008, respectively.

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
)
$
200Current period change


102





102Balance at March 31, 2009

$
342

$
(40
)
$
302


---

Unrealized gains on cash flow hedges, net of tax, at March 31, 2009, included unrealized gains on commodity hedges 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, $229 million, after tax, of the net unrealized gains on cash flow hedges at March 31,
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

15

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Table of Contents

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.  Discontinued Operations

Summarized financial information for discontinued operations is as follows:

Three Months Ended
March 31,2009

2008(in millions)Income (loss) before income taxes and minority interest

$
6

$
(6
)Provision (benefit) for income taxes


3


(1
)Income (loss) from operations of discontinued foreign subsidiaries

$
3

$
(5
)


Note 6.  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

EME ShareholdersTotal

Retained
Earnings

Accumulated
Other
Comprehensive
Income

Common
Stock

Additional
Paid-in
Capital

Non-
controlling
InterestBalance at December 31, 2008

$
2,764

$
1,085

$
200

$
64

$
1,335

$
80Net income


56


56Other comprehensive income


102





102Payments to Edison International for stock purchases related to stock-based compensation


(1
)

(1
)Other stock transactions, net


1











1Balance at March 31, 2009

$
2,922

$
1,140

$
302

$
64

$
1,336

$
80


Summarized Financial Information for EME

Amounts attributable to EME common shareholders:

Three Months Ended
March 31,2009

2008(in millions)Income from continuing operations, net of tax

$
53

$
150Discontinued operations, net of tax


3


(5
)Net Income

$
56

$
145


16

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Table of Contents

Note 7.  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
March 31, 2009 and December 31, 2008, EME had majority interests in 15 wind projects with a total generating capacity of 630 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 March 31, 2009 and
December 31, 2008:

March 31, 2009

December 31, 2008(in millions)Current assets

$
35

$
31Net property, plant and equipment


982


957Other long-term assets


3


2Total assets

$
1,020

$
990Current liabilities

$
27

$
29Long-term obligations net of current maturities


23


25Deferred revenues


16


15Other long-term liabilities


20


18Total liabilities

$
86

$
87Noncontrolling interest

$
80

$
77


Assets serving as collateral for the debt obligations had a carrying value of $85 million at each March 31, 2009 and
December 31, 2008, and primarily consist of property, plant and equipment. The consolidated statement of income and cash flow for the three months ended March 31, 2009 includes
$2 million of pre-tax income and $15 million of operating cash flow related to variable interest entities that are consolidated.

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

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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 March 31, 2009, entities which EME
has accounted for under the equity method had indebtedness of $269 million, of which $121 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 March 31, 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 $315 million and $326 million as of March 31, 2009 and
December 31, 2008, respectively, and is classified as investments in unconsolidated affiliates on EME's consolidated balance sheets.

As
of March 31, 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 March 31, 2009 and December 31, 2008, if payment were required, would be $49 million and $56 million,
respectively. EME has not recorded a liability related to the indemnity. EME's maximum exposure to loss at March 31, 2009 is $51 million. During the first quarter of 2009, EME commenced
recording its share of equity in income of $2 million from the March Point project. 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 8.  Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

As of March 31, 2009, EME had made approximately $1 million in contributions to its pension plans and estimates to make
$8 million of contributions in the last nine months of 2009.

The
following are components of pension expense:

Three Months Ended
March 31,2009

2008(in millions)Service cost

$
3

$
5Interest cost


3


4Expected return on plan assets


(2
)

(3
)Amortization of net loss


1


Total expense

$
5

$
6


18

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Postretirement Benefits Other Than Pensions

As of March 31, 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 nine months of 2009.

The
following are components of postretirement benefits expense:

Three Months Ended
March 31,2009

2008(in millions)Service cost

$
1

$
1Interest cost


1


1Total expense

$
2

$
2


Note 9.  Income Taxes

EME's income tax provision from continuing operations was $15 million and $82 million for the three months ended March 31, 2009 and 2008,
respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the three months ended March 31, 2009 and 2008, EME
recognized $16 million and $9 million, respectively, of production tax credits related to wind projects. In addition, EME recognized additional income tax expense of $1 million
and a benefit of $2 million during the first quarters of 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.

Note 10.  Commitments and Contingencies

Commitments

Capital Improvements

At March 31, 2009, EME's subsidiaries had firm commitments to spend approximately $106 million during the remainder of
2009 and $12 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 has entered into various turbine supply agreements with vendors to support its wind development efforts. At March 31, 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 $667 million in 2009
and $240 million in 2010. Turbine payments scheduled during the first quarter of 2009 were deferred by agreement with certain suppliers. EME and Suzlon Wind Energy Corporation are discussing a
number of contractual performance matters and related turbine payments. With respect to turbine payments scheduled for the balance of 2009, EME has continued to engage in discussions with each of the
turbine suppliers to defer the payment of the remaining commitments under each of the turbine supply agreements. At March 31, 2009, EME had recorded wind turbine deposits of
$336 million, included in other long-term assets on its consolidated balance sheet. Under certain of these agreements, EME may terminate the purchase of individual turbines, or
groups of turbines, for

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convenience.
If EME terminated one or more turbine supply agreements, it would result in a charge related to such termination.

Fuel Supply Contracts

At March 31, 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 $535 million,
summarized as follows: remainder of 2009$360 million, 2010$165 million, and 2011$10 million.

Standby Letters of Credit

At March 31, 2009, standby letters of credit aggregated $130 million and were scheduled to expire as follows:
$86 million in 2009 and $44 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.

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

20

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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 238 cases for which Midwest Generation was potentially liable and
that had not been settled and dismissed at March 31, 2009. Midwest Generation had recorded a $52 million liability at March 31, 2009 related to this matter.

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 March 31, 2009, EME had
recorded a liability of $89 million (of which $49 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 March 31, 2009, EME had recorded a liability of
$3 million related to these matters.

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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. This matter is currently pending before the FERC. EME
cannot predict the outcome of this matter.

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

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.

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.

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. 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 at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.

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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.

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 $4 million at March 31, 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.

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Note 11.  Supplemental Cash Flows Information

Three Months Ended
March 31,2009

2008(in millions)Cash paid (received)Interest (net of amount capitalized(1))

$
8

$
47Income taxes


(7
)

60Cash payments under plant operating leases


92


92


---

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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:



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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 first quarter ended March 31, 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:



PageManagement's Overview; Critical Accounting Policies and Estimates

26Results of Operations

29Liquidity and Capital Resources

39Market Risk Exposures

48


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 March 31,
2009, EME's subsidiaries and affiliates owned or leased interests in 38 operating projects and 2 wind projects 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'

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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

Continuing economic recessionary conditions, among other things, were a contributing factor to a decline in electrical demand for
Northern Illinois and PJM West Hub locations during the first quarter of 2009. The electrical load, calculated from published data by PJM, for these locations declined 6% and 2%, respectively,
compared to the first quarter of 2008. The decline in natural gas prices together with lower electrical demand have resulted in significantly lower energy prices. Furthermore, spot energy prices
affecting the Illinois Plants were adversely impacted by congestion affecting power exported from 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 $34.06/MWh and $49.09/MWh, respectively, during the first quarter of 2009 as compared to $53.38/MWh and $68.52/MWh, respectively, during the
first quarter of 2008. In the first quarter of 2009, the average realized energy prices 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 first quarter of 2009. Lower electrical load has also generally decreased
congestion in the eastern power grid, thereby resulting in lower trading income in the first quarter of 2009.

Environmental Compliance Costs and Plans

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. Midwest Generation is testing selective non-catalytic NOX removal technologies and reagent based SO2
removal technologies that may be employed to meet compliance requirements. These technologies would be deployed at the Illinois Plants in a manner which could optimize compliance during 2010 through
2015, subject to approval of construction permits by the Illinois EPA. A decision regarding whether or not to proceed with the alternative compliance program will occur following completion of testing
and evaluation of results. Under the current conditions, Midwest Generation cannot predict what specific method will be used or the costs that will be incurred to comply with the Combined Pollutant
Standard.

Business Development and Capital Commitments

At March 31, 2009, EME had 1,015 MW of wind projects in service and another 170 MW of wind projects under construction, with
scheduled completion dates during 2009. EME's wind projects under construction are currently funded through equity. During the first quarter of 2009, EME completed construction and commenced
operations of the 80 MW Elkhorn Ridge project located in Nebraska.

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 turbines with scheduled payment obligations of up to $667 million in 2009 and
$240 million in 2010. Turbine payments scheduled during the first quarter of 2009 were deferred by agreement with certain suppliers. EME and Suzlon Wind Energy Corporation are discussing a
number of contractual performance matters and related turbine payments. With respect to turbine payments scheduled for the balance of 2009, EME has continued to engage in discussions with each of the
turbine suppliers to defer the payment of the remaining commitments under each of the turbine supply agreements. At March 31, 2009, EME had recorded wind turbine deposits of
$336 million, included in other long-term

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assets
on its consolidated balance sheet. Under certain of these agreements, EME may terminate the purchase of individual turbines, or groups of turbines, for convenience.

EME
plans to defer construction expenditures for new wind projects until financing becomes available, which may require power purchase agreements. EME has observed a trend toward delays
in the award of power purchase agreements by potential offtakers. As a result, the time to complete development of new wind projects has increased, 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 is comprised of the following components:

Three Months Ended
March 31,2009

2008(in millions)Income from continuing operations

$
53

$
150Income (loss) from discontinued operations


3


(5
)Net Income Attributable to EME

$
56

$
145


EME's decrease in income from continuing operations during the first quarter of 2009, compared to the first quarter of 2008 was primarily
attributable to a significant decline in earnings from the Illinois Plants and the Homer City facilities from lower power prices and generation levels as well as lower energy trading income. These
decreases were partially offset by higher earnings from the wind projects in operation. Income from continuing operations during the first quarter of 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 first quarters of 2009 and 2008, and is organized under the following headings:



PageResults of Continuing Operations

29Results of Discontinued Operations

38New Accounting Pronouncements

38


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 first quarters of 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 March 31,2009

2008(in millions)Illinois Plants

$
114

$
231Homer City


36


54Renewable energy projects


26


8Energy trading


10


41Big 4 projects


6


8Sunrise


(5
)

(1
)March Point


2


Westside projects


3


4Other non-wind projects


2


2194


347Corporate administrative and general


(36
)

(40
)Corporate depreciation and amortization


(3
)

(3
)Adjusted Operating Income(1)

$
155

$
304


29

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Table of Contents

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

Three Months ended March 31,2009

2008(in millions)Adjusted Operating Income

$
155

$
304Less:Equity in earnings of unconsolidated affiliates


6


12Dividend income from projects


1


1Production tax credits


16


9Other income (expense), net


1


6Operating Income

$
131

$
276


---

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Table of Contents

Earnings from Consolidated Operations

Illinois Plants

The following table presents additional data for the Illinois Plants:

Three Months Ended March 31,2009

2008(in millions)Operating Revenues

$
384

$
468Operating ExpensesFuel(1)


123


118Gain on sale of emission allowances(2)





(2
)Plant operations


96


94Plant operating leases


19


19Depreciation and amortization


27


25Gain on buyout of contract and disposal of assets





(16
)Administrative and general


5


6Total operating expenses


270


244Operating Income


114


224Other Income (Expense)





7Adjusted Operating Income(3)

$
114

$
231Statistics(4)Generation (in GWh):Energy only contracts


5,756


6,538Load requirements services contracts(5)


886


1,845Total


6,642


8,383Aggregate plant performance:Equivalent availability(6)


82.7%


82.5%Capacity factor(7)


56.3%


70.3%Load factor(8)


68.1%


85.3%Forced outage rate(9)


7.0%


11.8%Average realized price/MWh:Energy only contracts(10)

$
47.77

$
53.16Load requirements services contracts(11)

$
62.54

$
62.35Capacity revenue only (in millions)

$
39

$
9Average fuel costs/MWh

$
18.55

$
14.08


---

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Three Months Ended March 31,2009

2008(in millions)Operating revenues

$
384

$
468Less:Load requirements services contracts


(55
)

(115
)Unrealized (gains) losses


(15
)

5Capacity and other revenues


(39
)

(10
)Realized revenues

$
275

$
348Generation (in GWh)


5,756


6,538Average realized energy price/MWh

$
47.77

$
53.16


Earnings from the Illinois Plants decreased $117 million in the first quarter of 2009, compared to the first quarter of 2008. The 2009
decrease in earnings was primarily attributable to a decrease in realized gross margin of $109 million. Realized gross margin was affected by the following factors:



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In
addition, earnings were lower in 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 $15 million and $(5) million for the first quarters of 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 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. 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 March 31,2009

2008(in millions)Operating Revenues

$
165

$
185Operating ExpensesFuel(1)


64


72Loss on sale of emission allowances(2)





Plant operations


34


29Plant operating leases


25


25Depreciation and amortization


5


4Administrative and general


1


1Total operating expenses


129


131Operating Income


36


54Other Income





Adjusted Operating Income(3)

$
36

$
54StatisticsGeneration (in GWh)


2,658


3,192Equivalent availability(4)


76.8%


87.5%Capacity factor(5)


65.1%


77.5%Load factor(6)


84.7%


88.5%Forced outage rate(7)


12.3%


9.5%Average realized energy price/MWh(8)

$
57.03

$
55.94Capacity revenue only (in millions)

$
12

$
8Average fuel costs/MWh

$
24.01

$
22.57


---

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Three Months Ended March 31,2009

2008Operating revenues

$
165

$
185Less:Unrealized losses





1Capacity and other revenues


(13
)

(8
)Realized revenues

$
152

$
178Generation (in GWh)


2,658


3,192Average realized energy price/MWh

$
57.03

$
55.94


Earnings from Homer City decreased $18 million for the first quarter of 2009, compared to the first quarter of 2008. The 2009 decrease in
earnings was primarily attributable to lower realized gross margin and higher plant maintenance expenses. The decline in realized gross margin was due to lower generation driven primarily by lower
energy prices, particularly in off-peak periods, and annual NOX emission allowance costs beginning in 2009. Due to lower prices, Homer City accelerated its 2009 planned outages
into the first quarter of 2009 resulting in an additional 20 days of planned outages as compared to the first quarter of 2008. The planned outage acceleration reduced equivalent availability
and increased plant operations expense. The increase in forced outage rate was mainly attributed to forced unit deratings which were required to prevent stack opacity exceedances from reaching levels
in excess of the allowable limits. For more information regarding opacity regulations, see "Liquidity and Capital ResourcesEnvironmental Matters and RegulationsAir Quality
RegulationsPennsylvania." The number and duration of opacity limit exceedances has increased at Homer City as lower dispatch has resulted in more unit operation in a load ramping mode.
Recent efforts to optimize unit ramp rates and combustion parameters have reduced the deratings required to avoid stack opacity exceedances.

Included
in operating revenues were unrealized losses from hedging activities of $1 million for the first quarter of 2008. Unrealized 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.

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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 March 31,2009

2008(in millions)Operating Revenues

$
44

$
16Production Tax Credits


16


960


25Operating ExpensesPlant operations


13


6Depreciation and amortization


20


10Administrative and general


1


1Total operating expenses


34


17Other Income





Adjusted Operating Income(1)

$
26

$
8StatisticsGeneration (in GWh)


820


500Aggregate plant performance:Equivalent availability


79.6%


84.6%Capacity factor


36.6%


37.9%


---

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Table of Contents



Three Months Ended March 31,2009

2008Adjusted Operating Income

$
26

$
8Less:Production tax credits


16


9Other income (expense)





Operating Income (Loss)

$
10

$
(1
)


Earnings from renewable energy projects increased $18 million in the first quarter of 2009, compared to the first quarter of 2008. The 2009
increase in earnings was primarily due to new projects that commenced operations in the last nine months of 2008. Earnings for the first quarter of 2009 included $11 million of liquidated
damages for availability guarantees provided by Suzlon Wind Energy Corporation. At March 31, 2009, EME had a receivable from this vendor of $16 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 were $10 million and $41 million for the first quarters ended March 31, 2009
and 2008, respectively. The 2009 decrease in earnings from energy trading activities was 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 $2 million for the first quarter of 2009, compared to the first quarter of 2008. The
2009 decrease in earnings was primarily due to lower earnings from the Midway-Sunset, Sycamore and Watson projects. For further discussion regarding power sales from the Sycamore and Watson projects
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. Partially offsetting these decreases was an increase in earnings from the Kern River project due to a planned outage in 2008.

Sunrise

Losses from the Sunrise project increased $4 million for the first quarter of 2009, compared to the first quarter of 2008. The
2009 increase in losses was primarily due to a planned outage in the first quarter of 2009.

March Point

During the first quarter of 2009, EME commenced recording its share of equity in income of $2 million 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.

36

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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 decreased $4 million for the first quarter of 2009, compared to the first quarter of 2008,
primarily due to lower employee benefits and consulting costs. In April 2009, EME reduced approximately 75 positions in its regional and corporate offices which will result in a restructuring charge
of approximately $6 million during the second quarter of 2009.

Interest Related Income (Expense)

Three Months Ended March 31,2009

2008Interest income

$
3

$
8Interest expense:EME debt


(68
)

(62
)Non-recourse debt:Midwest Generation


(3
)

(7
)EME CP Holding Co.


(1
)

(1
)Other project


(2
)

(1
)$
(74
)
$
(71
)


Interest Income

EME's interest income decreased $5 million for the first quarter of 2009, compared to the first quarter of 2008. The decrease
was primarily attributable to lower interest rates in 2009 compared to 2008.

Interest Expense

EME's interest expense to third parties, before capitalized interest, was $80 million for each of the first quarters of 2009 and
2008. Capitalized interest decreased $3 million for the first quarter of 2009, compared to the first quarter of 2008, due to a reduction in projects under construction.

Income Taxes

EME's income tax provision from continuing operations was $15 million and $82 million for the three months ended
March 31, 2009 and 2008, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the three months ended
March 31, 2009 and 2008, EME recognized $16 million and $9 million, respectively, of production tax credits related to wind projects. In addition, EME recognized additional income
tax expense of $1 million and a benefit of $2 million during the first quarters of 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.

37

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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 are largely timing in nature. However, state income taxes may be affected under the tax-allocation agreement, including
changes to apportionment rates used to record deferred taxes.

Results of Discontinued Operations

Income (loss) from discontinued operations, net of tax, was $3 million and $(5) million for the first quarters of 2009 and 2008,
respectively. The income (loss) in 2009 and 2008 was primarily due to foreign exchange gains (losses) and interest associated with contract indemnities related to EME's sale of its international
projects in December 2004.

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:



PageEME's Liquidity

39Capital Expenditures

40EME's Historical Consolidated Cash Flow

41Credit Ratings

42Margin, Collateral Deposits and Other Credit Support for Energy Contracts

42EME's Liquidity as a Holding Company

43Dividend Restrictions in Major Financings

45Contractual Obligations

46Off-Balance Sheet Transactions

46Environmental Matters and Regulations

46


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 March 31, 2009, EME and its subsidiaries had cash and cash equivalents and short-term investments of
$2.0 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 March 31, 2009 was $4.6 billion, of which
$24 million was current. In addition, EME's subsidiaries had $3.5 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 March 31, 2009:

EME

Midwest
Generation(in millions)Commitment

$
600

$
500Less: Commitment from Lehman Brothers subsidiary


(36
)

564


500Outstanding 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.

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. Accordingly, EME's liquidity is

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currently
comprised of cash on hand and cash flow generated from operations. Pending 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 March 31, 2009, the estimated capital expenditures through 2011 by EME's subsidiaries for existing projects, corporate
activities and turbine commitments were as follows:

April through
December 2009

2010

2011(in millions)Illinois PlantsPlant capital expenditures

$
38

$
96

$
61Environmental expenditures


11


(a
)

(a
)Homer City FacilitiesPlant capital expenditures


25


55


29Environmental expenditures


2


15


32New ProjectsProjects under construction


33





Turbine commitments


667


240


Other capital expenditures


27


9


7Total

$
803

$
415

$
129


---

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 EstimatesManagement's OverviewEnvironmental Compliance Costs and Plans." 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 March 31, 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 March 31, 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,

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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 March 31, 2009). Release of the project for full construction is pending a
decision on selection of turbines and EME's access to project financing or capital markets. The costs to complete the Big Sky wind 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 offtakers 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 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.

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Cash provided by operating activities from continuing operations increased $145 million in the first quarter of 2009, compared
to the first quarter of 2008. The 2009 increase was primarily attributable to an increase in margin deposits received from counterparties related to hedge activities at March 31, 2009.

Consolidated Cash Flows from Financing Activities

Cash used in financing activities from continuing operations increased $93 million in the first quarter of 2009, compared to the
first quarter of 2008. The 2009 increase was primarily attributable to payments made on EME's corporate credit facility and lower borrowings in 2009. Borrowings in 2008 represented borrowings under
Midwest Generation's working capital facility.

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Consolidated Cash Flows from Investing Activities

Cash used in investing activities from continuing operations increased $16 million in the first quarter of 2009, compared to the
first quarter of 2008. The 2009 increase was primarily due to lower maturities of short-term investments in 2009, compared to 2008. Partially offsetting this increase was lower capital
expenditures in 2009, compared to 2008.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT, at March 31, 2009, were as follows:

Moody's Rating

S&P Rating

Fitch RatingEME

B1

BB-

BB-Midwest Generation(1)

Baa3

BB+

BBB-EMMT

Not Rated

BB-

Not Rated


---

On December 23, 2008, S&P assigned a negative outlook to its corporate ratings for EME, Midwest Generation, and EMMT. On March 24,
2009, Moody's placed its corporate and debt ratings for EME and Midwest Generation under review for possible downgrade. 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.

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 include a requirement that the counterparty to such transactions, 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 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 sales 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

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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 March 31, 2009, EMMT had deposited $47 million in cash with clearing brokers in
support of futures contracts and had deposited $62 million in cash with counterparties in support of forward energy and congestion contracts. In addition, EME had received cash collateral of
$373 million at March 31, 2009, to support credit risk of counterparties under margin agreements.

Future
cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2009, if wholesale energy prices or the amount hedged changes. EME
estimates that margin and collateral requirements for energy and congestion contracts outstanding as of March 31, 2009 could increase by approximately $88 million over the remaining life
of the contracts using a 95% confidence level. Certain EMMT hedge contracts do not require margining, 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 margining, 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 March 31, 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. At March 31, 2009,
Midwest Generation had available $22 million of borrowing capacity under its $500 million working capital facility. In addition, EME has cash on hand and $88 million of borrowing
capacity available under its $600 million working capital facility to provide credit support to subsidiaries. For further discussion, see "EME's Liquidity as a Holding Company."

EME's Liquidity as a Holding Company

Overview

At March 31, 2009, EME had corporate cash and cash equivalents and short-term investments of $1.1 billion 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."

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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 a cash shortfall resulting from
reduced revenues and higher maintenance expenses. The proceeds of the subordinated loans were deposited in EME Homer City's operating account. Depending on the timing of cash receipts and
disbursements before the summer period, EME may provide additional funds through Edison Mission Finance. Such loans are expected to be repaid by the end of 2009.

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.

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

Twelve Months EndedMarch 31,
2009

December 31,
2008(in millions)Funds Flow Available for InterestDistributions:Midwest Generation

$
171

$
206EME Homer City


80


110Big 4 Projects(1)


113


114Other projects


57


55Tax payments received from subsidiaries


313


364Realized trading income


139


175Tax allocation receipts (payments)


(79
)

(92
)Operating expenses


(156
)

(155
)Other items, net


(17
)

(14
)$
621

$
763Net Interest Expense:EME corporate debt

$
255

$
248Addback: Capitalized interest


29


32Powerton-Joliet intercompany notes


112


112EME interest income


(6
)

(6
)$
390

$
386Ratio


1.59


1.98Covenant threshold (not less than)


1.20


1.20


---

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

March 31,
2009

December 31,
2008(in millions)Corporate DebtIndebtedness for money borrowed

$
4,539

$
4,564Powerton-Joliet termination value


1,091


1,163Letters of credit


128


132$
5,758

$
5,859Corporate CapitalCommon shareholder's equity

$
2,842

$
2,684Less:Non-cash cumulative changes in accounting


1


1Accumulated other comprehensive income


(302
)

(200
)Adjustments:After-tax losses incurred on termination of Collins lease


587


587Dividend to MEHC for repayment of 13.5% notes


899


899Corporate debt


5,758


5,859$
9,785

$
9,830Corporate-debt-to-corporate-capital ratio


0.59


0.60Covenant threshold (not more than)


0.75


0.75


Dividend Restrictions in Major Financings

General

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

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at March 31, 2009 or for the
twelve months ended March 31, 2009:

Subsidiary

Financial Ratio

Covenant

ActualMidwest Generation
(Illinois Plants)

Debt to Capitalization Ratio

Less than or equal to 0.60 to 1


0.26 to 1EME Homer City
(Homer City facilities)

Senior Rent Service Coverage Ratio

Greater than 1.7 to 1


1.85 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.

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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 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. At March 31, 2009, the maximum sale or disposition of EME assets is determined as follows:

March 31, 2009(in millions)Consolidated Net Tangible AssetsTotal consolidated assets

$
9,406Less:Consolidated current liabilities


(756
)Intangible assets


(149
)$
8,50110% Threshold

$
850


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.

Contractual Obligations

Fuel Supply Contracts

At March 31, 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 $535 million,
summarized as follows: remainder of 2009$360 million, 2010$165 million, and 2011$10 million.

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

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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).

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.

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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:



PageCommodity Price Risk

48Accounting for Derivative Instruments

56Fair Value of Derivative Instruments

56Credit Risk

58Interest Rate Risk

60Regulatory Matters

60


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 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 is expected to 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 in respect of 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 three months of 2009 and 2008:

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

2008January

$
42.10

$
47.09February


33.33


54.46March


26.74


58.58Quarterly Average

$
34.06

$
53.38


---

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.

49

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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 March 31, 2009:

24-Hour
Northern Illinois Hub
Forward Energy Prices(1)2009April

$
25.07May


24.31June


27.84July


36.59August


31.48September


26.83October


27.38November


25.07December


28.632010 Calendar "strip"(2)

$
30.11


---

EMMT engages in hedging activities for the Illinois Plants to hedge the risk of future change in the price of electricity. Hedging activities for
energy only contracts are typically weighted toward on-peak periods. The following table summarizes Midwest Generation's hedge position at March 31, 2009:

2009

2010

2011GWh

Average
price/
MWh

GWh

Average
price/
MWh

GWh

Average
price/
MWhEnergy Only Contracts(1)
Northern Illinois HubAEP/Dayton Hub


7,953

$
63.19


6,555

$
68.68


612

$
76.40Load Requirements Services Contracts(2)(3)
Northern Illinois Hub


598


63.65











Total estimated GWh


8,551





6,555





612


---

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In addition, Midwest Generation has entered into 9.2 billion cubic feet of natural gas futures contracts during the first quarter of 2009
to hedge the energy price risks during 2009.

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.

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 three months of 2009 and 2008:

Historical Energy Prices(1)
24-Hour PJMHomer City

West Hub2009

2008

2009

2008January

$
53.22

$
54.32

$
59.32

$
66.80February


42.86


61.74


46.31


68.29March


38.08


65.37


41.63


70.48Quarterly Average

$
44.72

$
60.48

$
49.09

$
68.52


---

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.

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The
following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at March 31, 2009:

24-Hour
PJM West Hub
Forward Energy Prices(1)2009April

$
38.51May


37.95June


42.97July


54.07August


47.74September


41.35October


38.98November


41.12December


46.652010 Calendar "strip"(2)

$
50.00


---

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 March 31, 2009:

2009

2010GWh


3,088


2,662Average price/MWh(1)

$
83.65

$
90.61


---

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.

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The
following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at March 31, 2009:

Fixed Price Capacity SalesThrough RPM
Auction, Net

Non-unit Specific
Capacity Sales

Variable Capacity SalesMW

Price per
MW-day

MW

Price per
MW-day

MW

Price per
MW-dayApril 1, 2009 to May 31, 2009Midwest Generation


2,963

$
122.39
(1)

880

$
64.35





EME Homer City


820


111.92








905

$
58.57
(2)June 1, 2009 to May 31, 2010Midwest Generation


4,544


106.36


715


71.46





EME Homer City


1,670


191.32











June 1, 2010 to May 31, 2011Midwest Generation


4,929


174.29











EME Homer City


1,813


174.29











June 1, 2011 to May 31, 2012Midwest Generation


4,582


110.00











EME Homer City


1,771


110.00














---

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, and the CONE.

Midwest
Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In addition, the load service requirements contracts
entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a "bundled product"). Under PJM's business rules, Midwest
Generation sells all of its available capacity (defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This
means that the locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents on a net basis in the table above.

Prior
to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery period of June 1, 2008
through May 31, 2009. EME Homer City is not receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City is receiving for these capacity sales is a
function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions.

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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. EME's revenues with respect to such forward contracts include:



Under
PJM's market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load
requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by
transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal
transmission losses in addition to the component included for congestion. 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 three months ended
March 31, 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 9% and 12%, respectively. The
monthly average difference between prices at the Homer City busbar and those at the PJM West Hub during the 12 months ended March 31, 2009 ranged from 8% to 21%. During the three months
ended March 31, 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 16% and 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. A
financial transmission right is a financial instrument that entitles the holder to receive the difference of 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. Coal purchases are made under a variety of supply agreements extending through 2011. The following

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table
summarizes the amount of coal under contract at March 31, 2009 for the remainder of 2009 and the following two years:

Amount of Coal Under Contract
in Millions of Equivalent Tons(1)April through
December 2009

2010

2011Illinois Plants


15.6


11.7


Homer City facilities(2)


3.8


0.8


0.2


---

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 $43.50 per ton at May 1, 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 the current global economic conditions that have lessened the 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 $8.75 per
ton at May 1, 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 market volatility, 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 the 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 first quarter of 2009 from $315 per ton during 2008. Based on broker's quotes and
information from public sources, the spot

55

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price
for SO2 allowances and annual NOX allowances was $62 per ton and $2,125 per ton, respectively, at March 31, 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 fluctuations in the price of electricity, capacity and fuel, emission
allowances and transmission rights which may impact cash flow from its power plant operations. 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. 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 first quarters of 2009 and
2008:

Three Months Ended
March 31,2009

2008(in millions)Illinois PlantsNon-qualifying hedges

$
16

$
Ineffective portion of cash flow hedges


(1
)

(5
)Homer City facilitiesNon-qualifying hedges


(1
)

1Ineffective portion of cash flow hedges


1


(2
)Total unrealized gains (losses)

$
15

$
(6
)


At March 31, 2009, unrealized gains of $13 million were recognized from non-qualifying hedge contracts or the
ineffective portion of cash flow hedges related to subsequent periods ($2 million for the remainder of 2009, $9 million for 2010, and $2 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 derivative instruments at March 31, 2009 and December 31, 2008 was
$558 million and $375 million, respectively. In assessing the fair value of EME's non-trading 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 March 31, 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 March 31, 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 March 31, 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

$
8

$
5

$
3

$


$
Prices provided by external sources


542


351


191





Price based on models and other valuation methods


8


6


2





Total

$
558

$
362

$
196

$


$



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 March 31, 2009 and December 31, 2008 was
$113 million and $112 million, respectively. The change in the fair value of trading contracts for the quarter ended March 31, 2009 was as follows:

(in millions)Fair value of trading contracts at January 1, 2009

$
112Net gains from energy trading activities


12Amount realized from energy trading activities


(15
)Other changes in fair value


4Fair value of trading contracts at March 31, 2009

$
113


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Table of Contents

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.

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 March 31, 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

$
1

$
2

$
(1
)
$


$
Prices provided by external sources


(147
)

(101
)

(46
)




Prices based on models and other valuation methods


259


131


80


27


21Total

$
113

$
32

$
33

$
27

$
21


In the table above, prices actively quoted include exchange-traded derivatives. Prices provided by external sources include
non-exchange-traded derivatives which 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

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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 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 March 31, 2009, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as
follows:

March 31, 2009Credit Rating(1)

Exposure(2)

Collateral

Net
Exposure(in millions)A or higher

$
461

$
(295
)
$
166A-


114


(70
)

44BBB+


25





25BBB


144





144BBB-


53





53Below investment grade


9


(8
)

1Total

$
806

$
(373
)
$
433


---

The credit risk exposure set forth in the above table is comprised of $148 million of net accounts receivable and payables and
$658 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 March 31, 2009 was $167 million. This total net exposure
excludes positions with Lehman Brothers Holdings and its subsidiaries. Five financial institutions comprise 35% of the net exposure above with the largest single net exposure with a financial
institution representing 12%. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $109 million cash margin in the aggregate with PJM, NYISO, MISO, clearing
brokers and other counterparties to support hedging and trading activities. Margining 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

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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 capacity and energy on a bilateral basis. Sales
into PJM accounted for approximately 38% of EME's consolidated operating revenues for the three months ended March 31, 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 March 31, 2009, EME's account receivable due from PJM was $25 million.

For
the three months ended March 31, 2009, a second customer, Constellation Energy Commodities Group, Inc., accounted for 27% 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 March 31, 2009, EME's account receivable due from Constellation was $32 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. 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 $3.5 billion at March 31, 2009, compared to the carrying value of $4.6 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. 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.

Description31.1

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.


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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 ENERGYBy:

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

May 8, 2009


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