Edgar Filing: EDISON MISSION ENERGY

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

Form 10-Q


(Mark one)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2011
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number 333-68630

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


Delaware (State or other jurisdiction of incorporation or organization)		95-4031807 (I.R.S. Employer Identification No.)
3 MacArthur Place, Suite 100 Santa Ana, California (Address of principal executive offices)		92707 (Zip Code)

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

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.


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 2, 2011: 100 shares (all shares held by an affiliate of the registrant).

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TABLE OF CONTENTS


GLOSSARY					v
PART I – FINANCIAL INFORMATION					1
ITEM 1. FINANCIAL STATEMENTS					1
	CONSOLIDATED STATEMENTS OF OPERATIONS				1
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)				2
	CONSOLIDATED BALANCE SHEETS				3
	CONSOLIDATED STATEMENTS OF CASH FLOWS				5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS				6
	Note 1. Summary of Significant Accounting Policies				6
		Basis of Presentation			6
		Cash Equivalents			6
		Inventory			6
		New Accounting Guidance			7
			Accounting Guidance Adopted in 2011		7
				Revenue—Multiple-Deliverables	7
				Fair Value Measurements and Disclosures	7
	Note 2. Consolidated Statement of Changes in Equity				7
	Note 3. Variable Interest Entities				8
		Projects or Entities that are Consolidated			8
		Projects that are not Consolidated			9
	Note 4. Fair Value Measurements				10
		Valuation Techniques used to Determine Fair Value			12
			Level 1		12
			Level 2		12
			Level 3		13
		Long-term Debt			13
	Note 5. Debt and Credit Agreements				13
		Project Financings			13
			Viento Funding II Wind Financing Amendment		13
		Other Letters of Credit Facilities			14
		Standby Letters of Credit			14
	Note 6. Derivative Instruments and Hedging Activities				14
		Notional Volumes of Derivative Instruments			15
		Fair Value of Derivative Instruments			17
		Income Statement Impact of Derivative Instruments			18
		Contingent Features			18
		Margin and Collateral Deposits			19
	Note 7. Income Taxes				20
		Effective Tax Rate			20
		Accounting for Uncertainty in Income Taxes			20
			Unrecognized Tax Benefits		20
		Accrued Interest and Penalties			21

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	Note 8. Compensation and Benefit Plans				21
		Pension Plans and Postretirement Benefits Other Than Pensions			21
			Pension Plans		21
			Postretirement Benefits Other Than Pensions		21
	Note 9. Commitments and Contingencies				22
		Commitments			22
			Fuel Supply Contracts		22
			Turbine Commitments		22
			Capital Expenditures		22
		Guarantees and Indemnities			22
			Environmental Indemnities Related to the Midwest Generation Plants		22
			Environmental Indemnity Related to the Homer City Plant		23
			Indemnities Provided under Asset Sale and Sale-Leaseback Agreements		23
		Contingencies			24
			Environmental Remediation		24
			Midwest Generation New Source Review Lawsuit		25
			Homer City New Source Review Lawsuit		25
	Note 10. Environmental Developments				26
	Note 11. Accumulated Other Comprehensive Income (Loss)				27
	Note 12. Supplemental Cash Flows Information				27
	Note 13. Discontinued Operations				28
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS					29
	MANAGEMENT'S OVERVIEW				31
	Highlights of Operating Results				31
	Midwest Generation Environmental Compliance Plans and Costs				32
	Homer City Outage				32
	US EPA Developments				33
	EME's Liquidity				33
	RESULTS OF OPERATIONS				35
	Results of Continuing Operations				35
		Overview			35
		Adjusted Operating Income from Consolidated Operations			36
			Midwest Generation Plants		36
			Homer City		38
			Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions		39
				Average Realized Energy Price	39
				Average Realized Fuel Costs	40
				Statistical Definitions	41
			Seasonality—Coal Plants		41
			Renewable Energy Projects		42
			Energy Trading		42
		Adjusted Operating Income from Unconsolidated Affiliates			43
		Interest Income (Expense)			43
		Income Taxes			43

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Results of Discontinued Operations			43
New Accounting Guidance			43
LIQUIDITY AND CAPITAL RESOURCES			44
Available Liquidity			44
	Bonus Depreciation Impact on EME		45
Capital Investment Plan			45
	Environmental Capital Expenditures		45
	Non-Environmental Capital Expenditures		46
	Future Projects		46
EME's Historical Consolidated Cash Flow			47
	Condensed Consolidated Statement of Cash Flows		47
		Consolidated Cash Flows from Operating Activities	47
		Consolidated Cash Flows from Financing Activities	47
		Consolidated Cash Flows from Investing Activities	47
Credit Ratings			48
	Overview		48
	Credit Rating of EMMT		48
Margin, Collateral Deposits and Other Credit Support for Energy Contracts			48
EME's Liquidity as a Holding Company			49
	EME's Credit Facility Financial Ratios		49
Dividend Restrictions in Major Financings			50
	Key Ratios of EME's Principal Subsidiaries Affecting Dividends		50
	EME's Senior Notes and Guaranty of Powerton-Joliet Leases		51
Contractual Obligations and Contingencies			51
	Fuel Supply Contracts		51
	Midwest Generation New Source Review Lawsuit		51
	Homer City New Source Review Lawsuit		51
Off-Balance Sheet Transactions			52
Environmental Matters and Regulations			52
MARKET RISK EXPOSURES			53
Derivative Instruments			53
	Unrealized Gains and Losses		53
	Fair Value Disclosures		53
Commodity Price Risk			53
	Energy Price Risk Affecting Sales from the Coal Plants		53
	Capacity Price Risk		55
	Basis Risk		56
	Coal and Transportation Price Risk		56
	Emission Allowances Price Risk		57
Credit Risk			57
Interest Rate Risk			58
CRITICAL ACCOUNTING ESTIMATES AND POLICIES			58

iii

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		58
ITEM 4. CONTROLS AND PROCEDURES		58
	Disclosure Controls and Procedures	58
	Internal Control Over Financial Reporting	59
PART II – OTHER INFORMATION		60
ITEM 1. LEGAL PROCEEDINGS		60
	Midwest Generation New Source Review Lawsuit	60
ITEM 1A. RISK FACTORS		60
ITEM 6. EXHIBITS		60
SIGNATURES		61

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GLOSSARY

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



2010 Tax Relief Act		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AOI		adjusted operating income (loss)
BACT		best available control technology
bcf		billion cubic feet
Big 4		Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu		British thermal units
CAA		Clean Air Act
coal plants		Midwest Generation coal plants and Homer City electric generating station
Commonwealth Edison		Commonwealth Edison Company
CPS		Combined Pollutant Standard
EME		Edison Mission Energy
EMMT		Edison Mission Marketing & Trading, Inc.
GAAP		United States generally accepted accounting principles
GWh		gigawatt-hours
HAP(s)		hazardous air pollutant(s)
Homer City		EME Homer City Generation L.P.
LIBOR		London Interbank Offered Rate
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations
Midwest Generation		Midwest Generation, LLC
MMBtu		million British thermal units
Moody's		Moody's Investors Service, Inc.
MW		megawatts
MWh		megawatt-hours
NO_X		nitrogen oxide
NYISO		New York Independent System Operator
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
RPM		Reliability Pricing Model
S&P		Standard & Poor's Ratings Services
SO₂		sulfur dioxide
US EPA		United States Environmental Protection Agency
U.S. Treasury grants		Cash grants, under the American Recovery and Reinvestment Act of 2009

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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, unaudited)
			Three Months Ended March 31,
			2011			2010

Operating Revenues			$	550		$	651
Operating Expenses
	Fuel			182			213
	Plant operations			192			158
	Plant operating leases			44			44
	Depreciation and amortization			72			59
	Administrative and general			43			47

		Total operating expenses		533			521

	Operating income			17			130

Other Income (Expense)
	Equity in income (loss) from unconsolidated affiliates			(5	)		17
	Dividend income			1			16
	Interest income			1			1
	Interest expense, net of capitalized interest			(80	)		(68	)
	Other income (expense), net			3			2

		Total other income (expense)		(80	)		(32	)

	Income (loss) from continuing operations before income taxes			(63	)		98
	Provision (benefit) for income taxes			(45	)		23

Income (Loss) from Continuing Operations				(18	)		75
Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 13)				(2	)		6

Net Income (Loss)				(20	)		81

Net (Income) Loss Attributable to Noncontrolling Interests				—			—

Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder			$	(20	)	$	81

Amounts Attributable to Edison Mission Energy Common Shareholder
Income (loss) from continuing operations, net of tax			$	(18	)	$	75
Income (loss) from discontinued operations, net of tax				(2	)		6

Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder			$	(20	)	$	81

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,
			2011			2010

Net Income (Loss)			$	(20	)	$	81
Other comprehensive income (loss), net of tax
	Pension and postretirement benefits other than pensions
		Amortization of net loss included in expenses, net of tax		1			—
	Unrealized gains (losses) on derivatives qualified as cash flow hedges
		Unrealized holding gains arising during period, net of income tax expense of $4 and $62 for the three months ended March 31, 2011 and 2010, respectively		6			95
		Reclassification adjustments included in net income (loss), net of income tax benefit of $6 and $14 for the three months ended March 31, 2011 and 2010, respectively		(10	)		(20	)

Other comprehensive income (loss)				(3	)		75

Comprehensive Income (Loss)				(23	)		156

Comprehensive (Income) Loss Attributable to Noncontrolling Interests				—			—

Comprehensive Income (Loss) Attributable to Edison Mission Energy Common Shareholder			$	(23	)	$	156

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, 2011		December 31, 2010

Assets
Current Assets
	Cash and cash equivalents		$	1,183	$	1,075
	Accounts receivable—trade			106		170
	Receivables from affiliates			236		192
	Inventory			258		236
	Derivative assets			38		46
	Restricted cash			10		2
	Margin and collateral deposits			46		59
	Prepaid expenses and other			75		79

		Total current assets		1,952		1,859

Investments in Unconsolidated Affiliates				542		557

Property, Plant and Equipment, less accumulated depreciation of $1,833 and $1,759 at respective dates				5,360		5,332

Other Assets
	Deferred financing costs			54		54
	Long-term derivative assets			66		70
	Restricted deposits			38		44
	Rent payments in excess of levelized rent expense under plant operating leases			1,219		1,187
	Other long-term assets			226		218

		Total other assets		1,603		1,573

Total Assets			$	9,457	$	9,321

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

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EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS (in millions, except share and per share amounts, unaudited)
			March 31, 2011			December 31, 2010

Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	105		$	90
	Payables to affiliates			17			18
	Accrued liabilities			139			201
	Derivative liabilities			7			6
	Interest payable			103			31
	Deferred taxes			33			34
	Current maturities of long-term debt			53			48
	Short-term debt			53			96

		Total current liabilities		510			524

Long-term debt net of current maturities				4,492			4,342
Deferred taxes and tax credits				820			836
Deferred revenues				159			160
Long-term derivative liabilities				15			19
Other long-term liabilities				663			619

Total Liabilities				6,659			6,500

Commitments and Contingencies (Notes 5, 6, 9 and 10)
Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of March 31, 2011 and December 31, 2010			64			64
	Additional paid-in capital			1,338			1,336
	Retained earnings			1,426			1,448
	Accumulated other comprehensive loss			(34	)		(31	)

		Total Edison Mission Energy common shareholder's equity		2,794			2,817

Noncontrolling Interests				4			4

Total Equity				2,798			2,821

Total Liabilities and Equity			$	9,457		$	9,321

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

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EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions, unaudited)
			Three Months Ended March 31,
			2011			2010

Cash Flows From Operating Activities
	Net income (loss)		$	(20	)	$	81
	(Income) loss from discontinued operations			2			(6	)

	Income (loss) from continuing operations, net			(18	)		75
	Adjustments to reconcile income (loss) to net cash provided by operating activities:
		Equity in (income) loss from unconsolidated affiliates		5			(17	)
		Distributions from unconsolidated affiliates		5			21
		Depreciation and amortization		81			63
		Deferred taxes and tax credits		(15	)		29
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		13			(4	)
		Decrease in accounts receivables		20			76
		Increase in inventory		(22	)		(2	)
		(Increase) decrease in prepaid expenses and other		(2	)		1
		Decrease in restricted cash		—			3
		Increase in rent payments in excess of levelized rent expense		(32	)		(45	)
		Decrease in accounts payable and other current liabilities		(13	)		(84	)
		Increase in interest payable		72			71
		Decrease in derivative assets and liabilities		4			118
		Decrease in other operating—assets		—			5
		Increase in other operating—liabilities		16			2

	Operating cash flow from continuing operations			114			312
	Operating cash flow from discontinued operations			(2	)		6

		Net cash provided by operating activities		112			318

Cash Flows From Financing Activities
	Borrowings on long-term debt			88			47
	Payments on long-term debt agreements			(8	)		(3	)
	Borrowings on short-term debt			32			—
	Payments to affiliates related to stock-based awards			(2	)		(1	)
	Financing costs			(6	)		(9	)

		Net cash provided by financing activities from continuing operations		104			34

Cash Flows From Investing Activities
	Capital expenditures			(111	)		(83	)
	Proceeds from return of capital and loan repayments and sale of assets			9			16
	Investments in and loans to unconsolidated affiliates			(4	)		—
	Maturities of short-term investments			—			1
	Increase in restricted deposits			(1	)		—
	Investments in other assets			(1	)		(49	)

		Net cash used in investing activities from continuing operations		(108	)		(115	)

Effect of consolidation of variable interest entity on cash				—			5
Effect on cash from deconsolidation of variable interest entities				—			(4	)

Net increase in cash and cash equivalents				108			238
Cash and cash equivalents at beginning of period				1,075			796

Cash and cash equivalents at end of period			$	1,183		$	1,034

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, 2011
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

Edison Mission Energy's (EME's) significant accounting policies were described in "Note 1—Summary of Significant Accounting Policies" on page 94 of EME's annual report on Form 10-K for the year ended December 31, 2010. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011 as discussed below in "—New Accounting Guidance." 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, 2011 are not necessarily indicative of the operating results for the full year. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

Certain prior year reclassifications have been made to conform to the current year financial statement presentation pertaining to immaterial items.

The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Cash Equivalents

Cash equivalents included money market funds totaling $967 million and $813 million at March 31, 2011 and December 31, 2010, respectively. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months.

Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory consisted of the following:

(in millions)	March 31, 2011		December 31, 2010


Coal, fuel oil and other raw materials	$	184	$	163
Spare parts, materials and supplies		74		73

Total inventory	$	258	$	236

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New Accounting Guidance

Accounting Guidance Adopted in 2011

Revenue—Multiple-Deliverables

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

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. EME adopted this guidance effective January 1, 2011.

Note 2. Consolidated Statement of Changes in Equity

The following table provides the changes in equity for the three months ended March 31, 2011:

				EME Shareholder's Equity

(in millions)	Total Equity			Common Stock		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interest

Balance at December 31, 2010	$	2,821		$	64	$	1,336	$	1,448		$	(31	)	$	4
Net loss		(20	)		—		—		(20	)		—			—
Other comprehensive loss		(3	)		—		—		—			(3	)		—
Payments to Edison International for stock purchases related to stock- based compensation		(2	)		—		—		(2	)		—			—
Other stock transactions, net		2			—		2		—			—			—

Balance at March 31, 2011	$	2,798		$	64	$	1,338	$	1,426		$	(34	)	$	4

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The following table provides the changes in equity for the three months ended March 31, 2010:

				EME Shareholder's Equity

(in millions)	Total Equity			Common Stock		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)		Non- controlling Interest

Balance at December 31, 2009	$	2,837		$	64	$	1,339	$	1,280		$	78	$	76
Impact of deconsolidation of variable interest entities		(71	)		—		—		—			—		(71	)
Cumulative effect of a change in accounting principle, net of tax¹		10			—		—		10			—		—
Net income		81			—		—		81			—		—
Other comprehensive income		75			—		—		—			75		—
Payments to Edison International for stock purchases related to stock- based compensation		(1	)		—		—		(1	)		—		—
Other stock transactions, net		1			—		1		—			—		—

Balance at March 31, 2010	$	2,932		$	64	$	1,340	$	1,370		$	153	$	5

¹: For the quarter ended March 31, 2010, reflects the impact of adopting accounting guidance related to variable interest entities.

Note 3. Variable Interest Entities

Projects or Entities that are Consolidated

At March 31, 2011 and December 31, 2010, EME consolidated 13 wind projects with a total generating capacity of 500 MW that have minority interests held by others. EME also had a 50% partnership interest in the American Bituminous Power Partners, L.P. project, commonly referred to as the Ambit project. In determining that EME was the primary beneficiary, the key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.

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

(in millions)		March 31, 2011		December 31, 2010


Current assets		$	36	$	26
Net property, plant and equipment			726		739
Other long-term assets			5		6

	Total assets	$	767	$	771

Current liabilities		$	23	$	25
Long-term debt net of current maturities			70		71
Deferred revenues			72		71
Other long-term liabilities			21		21

	Total liabilities	$	186	$	188

Noncontrolling interests		$	4	$	4

Assets serving as collateral for the debt obligations had a carrying value of $167 million and $163 million at March 31, 2011 and December 31, 2010, respectively, and primarily consist of property, plant and equipment.

Projects that are not Consolidated

EME accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. At March 31, 2011 and December 31, 2010, EME had five significant variable interests in natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EME operates three of the four Big 4 projects and EME's partner provides the fuel management services. In addition, the executive director of these projects is provided by EME's partner. Commercial and operating activities are jointly controlled by a management committee of each variable interest entity. Accordingly, EME continues to account for its variable interests under the equity method.

At March 31, 2011 and December 31, 2010, EME accounts for its interests in two renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects, under the equity method. The commercial and operating activities of these entities are directed by a management committee composed of representatives of each partner. Thus, EME is not the primary beneficiary of these projects. In addition, EME accounts for its interests in a wind project under construction, Community Wind North, under the equity method.

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

	March 31, 2011

(in millions)	Investment		Maximum Exposure

Natural gas-fired projects	$	315	$	315
Renewable energy projects		227		227

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EME's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EME's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for recourse to EME. Accordingly, a default under such project financings could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's investment, but would not require EME to contribute additional capital. At March 31, 2011, entities which EME has accounted for under the equity method had indebtedness of $115 million, of which $41 million is proportionate to EME's ownership interest in these two projects.

Note 4. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or a liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. The fair value of derivative assets' nonperformance risk was not material as of March 31, 2011 and December 31, 2010.

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

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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:

			March 31, 2011

(in millions)			Level 1		Level 2		Level 3		Netting and Collateral¹			Total

Assets at Fair Value
	Money market funds²		$	967	$	—	$	—	$	—		$	967

	Derivative contracts
		Electricity	$	—	$	67	$	91	$	(54	)	$	104
		Fuel oil		7		—		—		(7	)		—

		Total commodity contracts		7		67		91		(61	)		104

	Total assets		$	974	$	67	$	91	$	(61	)	$	1,071

Liabilities at Fair Value
	Derivative contracts
		Electricity	$	—	$	13	$	8	$	(14	)	$	7
		Natural gas		—		1		—		—			1

		Total commodity contracts		—		14		8		(14	)		8
		Interest rate contracts		—		14		—		—			14

	Total liabilities		$	—	$	28	$	8	$	(14	)	$	22

			December 31, 2010

Assets at Fair Value
	Money market funds²		$	813	$	—	$	—	$	—		$	813

	Derivative contracts
		Electricity	$	—	$	70	$	107	$	(61	)	$	116
		Natural gas		1		—		—		(1	)		—
		Fuel oil		8		—		—		(8	)		—

		Total commodity contracts		9		70		107		(70	)		116

	Total assets		$	822	$	70	$	107	$	(70	)	$	929

Liabilities at Fair Value
	Derivative contracts
		Electricity	$	—	$	12	$	16	$	(21	)	$	7
		Natural gas		—		2		—		—			2
		Coal		—		1		—		(1	)		—

		Total commodity contracts		—		15		16		(22	)		9
		Interest rate contracts		—		16		—		—			16

	Total liabilities		$	—	$	31	$	16	$	(22	)	$	25

¹: Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.
²: Money market funds are included in cash and cash equivalents on EME's consolidated balance sheets.

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

		Three Months Ended March 31,

(in millions)		2011			2010

Fair value, net assets at beginning of period		$	91		$	173
Total realized/unrealized gains (losses)
	Included in earnings¹		—			45
	Included in accumulated other comprehensive income (loss)		1			6
Purchases			5			4
Settlements			(12	)		(28	)
Transfers in or out of Level 3			(2	)		(1	)

Fair value, net assets at end of period		$	83		$	199

Change during the period in unrealized gains (losses) related to assets and liabilities, net held at end of period¹		$	(6	)	$	46

¹: Reported in operating revenues on EME's consolidated statements of operations.

EME determines the fair value of transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during the first quarters of 2011 and 2010.

Valuation Techniques used to Determine Fair Value

Level 1

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

Level 2

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

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

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Level 3

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

For derivative contracts that trade infrequently (illiquid financial transmission rights and congestion revenue rights), changes in fair value are based on the hypothetical sale of illiquid positions. Objective criteria are reviewed, including system congestion and other underlying drivers and fair value is adjusted when it is concluded that a change in objective criteria would result in a new valuation that better reflects fair value. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of EME's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models that may require EME to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.

Long-term Debt

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

	March 31, 2011				December 31, 2010

(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt, including current portion	$	4,544	$	3,843	$	4,390	$	3,670

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

The carrying amount of trade receivables, payables and short-term debt approximates fair value.

Note 5. Debt and Credit Agreements

Project Financings

Viento Funding II Wind Financing Amendment

In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255.2 million, which included a

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$227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5.2 million seven-year working capital facility. At March 31, 2011, $227 million was outstanding under this loan. The amount of outstanding letters of credit was $13 million. Interest under the term loan accrues at London Interbank Offered Rate (LIBOR) plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary. Viento Funding II, Inc. entered into interest rate swap agreements at 3.415% to hedge the majority of the variable interest rate under the term loan. Two-thirds of the notional amount as of December 31, 2010 (approximately $92 million) under the swap agreements entered in connection with the 2009 financing were left unchanged at 3.175%. For further details regarding the interest rate swap agreements, see Note 6—Derivative Instruments and Hedging Activities. In conjunction with the foregoing, EME wrote off $3 million of deferring financing costs and incurred a loss of $2 million from termination of interest rate swaps, included as part of interest expense on the consolidated statement of operations.

Other Letters of Credit Facilities

As of March 31, 2011, a subsidiary of EME had a $10 million letter of credit facility with $2 million outstanding letters of credit.

Standby Letters of Credit

At March 31, 2011, standby letters of credit under EME's credit facility aggregated $80 million and were scheduled to expire as follows: $53 million in 2011 and $27 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $41 million, $3 million of which was under the Midwest Generation, LLC (Midwest Generation) credit facility, and were scheduled to expire as follows: $7 million in 2011, $16 million in 2012, $10 million in 2017, and $8 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.

Note 6. Derivative Instruments and Hedging Activities

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

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

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

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

Notional Volumes of Derivative Instruments

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

March 31, 2011

				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities

Electricity	Forwards/Futures	Sales	GWh		16,899	¹		20,400	³		33,336
Electricity	Forwards/Futures	Purchases	GWh		306	¹		21,079	³		35,455
Electricity	Capacity	Sales	MW-Day (in thousands)		186	²		—			123	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		21	²		—			379	²
Electricity	Congestion	Sales	GWh		—			136	⁴		9,244	⁴
Electricity	Congestion	Purchases	GWh		—			863	⁴		146,786	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			—			27.4
Natural gas	Forwards/Futures	Purchases	bcf		—			—			28.6
Fuel oil	Forwards/Futures	Sales	barrels		—			—			35,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			240,000			35,000
Coal	Forwards/Futures	Sales	tons		—			—			2,731,000
Coal	Forwards/Futures	Purchases	tons		—			—			2,638,000

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	92	June 2016
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt	Cash flow		113	December 2020
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		122	December 2025
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		68	March 2026

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December 31, 2010

				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities

Electricity	Forwards/Futures	Sales	GWh		16,799	¹		22,456	³		34,630
Electricity	Forwards/Futures	Purchases	GWh		408	¹		22,931	³		37,669
Electricity	Capacity	Sales	MW-Day (in thousands)		190	²		—			136	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		8	²		—			419	²
Electricity	Congestion	Sales	GWh		—			136	⁴		12,020	⁴
Electricity	Congestion	Purchases	GWh		—			1,143	⁴		187,689	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			—			30.6
Natural gas	Forwards/Futures	Purchases	bcf		—			—			34.3
Fuel oil	Forwards/Futures	Sales	barrels		—			250,000			10,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			490,000			10,000
Coal	Forwards/Futures	Sales	tons		—			—			2,630,500
Coal	Forwards/Futures	Purchases	tons		—			—			2,645,500

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	138	June 2016
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		122	December 2025
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		68	March 2026

¹: EME's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the coal plants which meet the normal purchases and sales exception and are accounted for on the accrual method.
²: EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Reliability Pricing Model (RPM) auction is not accounted for as a derivative.
³: EME also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.
⁴: Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

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Fair Value of Derivative Instruments

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

March 31, 2011

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

Non-trading activities
	Cash flow hedges	$	44		$	6		$	50		$	9		$	23		$	32		$	18
	Economic hedges		59			6			65			56			1			57			8
Trading activities			139			96			235			106			26			132			103

			242			108			350			171			50			221			129
Netting and collateral received¹			(204	)		(42	)		(246	)		(164	)		(35	)		(199	)		(47	)

Total		$	38		$	66		$	104		$	7		$	15		$	22		$	82

December 31, 2010

Non-trading activities
	Cash flow hedges	$	54		$	2		$	56		$	10		$	25		$	35		$	21
	Economic hedges		77			2			79			71			—			71			8
Trading activities			184			103			287			148			29			177			110

			315			107			422			229			54			283			139
Netting and collateral received¹			(269	)		(37	)		(306	)		(223	)		(35	)		(258	)		(48	)

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

¹: Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally enforceable master netting agreement exists with a derivative counterparty.

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Income Statement Impact of Derivative Instruments

The following table provides the activity of accumulated other comprehensive income, containing information about the changes in the fair value of cash flow hedges, to the extent effective, and reclassification from accumulated other comprehensive income into results of operations:

	Cash Flow Hedge Activity¹ Three Months Ended March 31,

	Cash Flow Hedge Activity¹ Three Months Ended March 31,						Income Statement Location
(in millions)	2011			2010			Income Statement Location

Accumulated other comprehensive income derivative gain at January 1	$	27		$	175
Effective portion of changes in fair value		10			157
Reclassification from accumulated other comprehensive income to net income		(16	)		(34	)	Operating revenues

Accumulated other comprehensive income derivative gain at March 31	$	21		$	298

¹: Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at March 31, 2011 and 2010 were $12 million and $180 million, respectively.

For additional information related to accumulated other comprehensive income, see Note 11—Accumulated Other Comprehensive Income (Loss).

The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains of $2 million and $9 million during the first quarters of 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.

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

		Three Months Ended March 31,

	Income Statement Location	Three Months Ended March 31,
(in millions)	Income Statement Location	2011		2010

Economic hedges	Operating revenues	$	6	$	(4	)
	Fuel costs		6		1
Trading activities	Operating revenues		16		47

Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features was in an asset position at March 31, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each

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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. Edison Mission Marketing & Trading, Inc. (EMMT) has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.

Margin and Collateral Deposits

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

(in millions)		March 31, 2011		December 31, 2010


Collateral provided to counterparties
	Offset against derivative liabilities	$	1	$	4
	Reflected in margin and collateral deposits		46		59
Collateral received from counterparties
	Offset against derivative assets		48		52

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Note 7. Income Taxes

Effective Tax Rate

The table below provides a reconciliation of income tax expense (benefit) computed at the federal statutory income tax rate to the income tax provision (benefit):

		Three Months Ended March 31,

(in millions)		2011			2010

Income (loss) from continuing operations before income taxes		$	(63	)	$	98

Provision (benefit) for income taxes at federal statutory rate of 35%		$	(23	)	$	34
Increase (decrease) in income tax from:
	State tax-net of federal provision (benefit) (excludes state tax settlement)		(5	)		4
	Production tax credits, net		(18	)		(14	)
	Qualified production deduction		(1	)		1
	Other		2			(2	)

Total provision (benefit) for income taxes from continuing operations		$	(45	)	$	23

Effective tax rate			72%			23%

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.

Unrecognized Tax Benefits

There was no change in unrecognized tax benefits from December 31, 2010. As of March 31, 2011 and December 31, 2010, if recognized, $148 million of the unrecognized tax benefits would impact the effective tax rate.

Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 remain subject to audit. The Internal Revenue Service examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for one item related to EME. The EME-related proposed adjustment increases the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $187 million, including interest and penalties (the Internal Revenue Service has asserted a 40% penalty for understatement of tax liability related to this matter). Edison International disagrees with the proposed adjustments and filed a protest with the Internal Revenue Service in the first quarter of 2011.

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Accrued Interest and Penalties

The total amount of accrued interest and penalties related to EME's income tax liabilities was $34 million and $32 million as of March 31, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $1 million and $3 million for the three months ended March 31, 2011 and 2010, respectively.

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

Contributions to EME's pension plans were $3 million during the quarter ended March 31, 2011, and EME estimates $17 million in contributions for the remainder of 2011.

The following were components of pension expense:

	Three Months Ended March 31,

(in millions)	2011			2010

Service cost	$	4		$	4
Interest cost		4			3
Expected return on plan assets		(3	)		(2	)
Amortization of net loss		1			1

Total expense	$	6		$	6

Postretirement Benefits Other Than Pensions

Contributions to EME's postretirement benefits other than pensions were $1 million during the quarter ended March 31, 2011, and EME estimates $1 million in contributions for the remainder of 2011.

The following were components of postretirement benefits expense:

	Three Months Ended March 31,

(in millions)	2011		2010

Service cost	$	1	$	1
Interest cost		2		1

Total expense	$	3	$	2

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Note 9. Commitments and Contingencies

Commitments

Fuel Supply Contracts

At March 31, 2011, Midwest Generation and EME Homer City Generation L.P. (Homer City) had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. These commitments are estimated to aggregate $677 million, summarized as follows: $373 million for the remainder of 2011, $255 million in 2012 and $49 million in 2013.

Turbine Commitments

At March 31, 2011, EME had commitments to purchase wind turbines of $90 million due in 2011. EME's failure to schedule turbine delivery by June 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $21 million charge against earnings. EME has identified a project in which to place these turbines. However, there is no assurance that development will be completed and the turbines will be used for this project.

On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EME against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EME may elect to deploy up to 60 additional wind turbines (aggregating 144 MW) that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. In April 2011, the 55 MW Pinnacle wind project in West Virginia, which will deploy the 23 wind turbines purchased from Mitsubishi, commenced construction.

Capital Expenditures

At March 31, 2011, EME's subsidiaries had firm commitments to spend approximately $153 million during the remainder of 2011 on capital and construction expenditures. These expenditures primarily relate to selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants, the construction of wind projects and non-environmental improvements at the coal plants. EME intends to fund these expenditures through project level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations.

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 included performance guarantees and indemnifications.

Environmental Indemnities Related to the Midwest Generation Plants

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

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

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 228 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2011. Midwest Generation had recorded a liability of $56 million at March 31, 2011 related to this contract indemnity.

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

Environmental Indemnity Related to the Homer City Plant

In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review Lawsuit." EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale and Sale-Leaseback Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by

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valid claims from the sellers or purchasers, as the case may be. At March 31, 2011, EME had recorded a liability of $44 million related to these matters.

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

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

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

Contingencies

Environmental Remediation

Legislative and regulatory activities by federal, state and local authorities in the United States relating to energy and the environment impose numerous restrictions and requirements with respect to the operation of EME subsidiaries' existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by EME's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations.

With respect to potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $7 million at March 31, 2011 for estimated environmental investigation and remediation costs for the Midwest Generation plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that require remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified.

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Midwest Generation New Source Review Lawsuit

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

In March 2010, nine of the ten counts related to PSD requirements in the complaint were dismissed, and the tenth count was also dismissed to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. Following those dismissals, the government plaintiffs filed an amended complaint, with claims that attempted to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. In March 2011, the court again dismissed the nine PSD claims previously dismissed in 2010, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013.

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

Homer City New Source Review Lawsuit

In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleges violations of the PSD and Title V provisions of the CAA and its implementing regulations, including requirements contained in the Pennsylvania State Implementation Plan, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint calls for an injunction ordering Homer City to install controls

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sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey have intervened in the lawsuit.

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

In April 2011, Homer City filed motions to dismiss both complaints. An adverse decision could involve penalties, remedial actions and damages that could have a material adverse impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows.

Note 10. Environmental Developments

In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of hazardous air pollutants (HAPs) from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur Powder River Basin (PRB) coal, to meet emissions limits for criteria pollutants, such as nitrogen oxide (NO_x) and sulfur dioxide (SO₂) as well as for HAPs, such as mercury, acid gas and non-mercury metals. With respect to the Homer City plant, the proposed standards, like the pending Clear Air Transport Rule, will require additional reductions in and controls for SO₂ emissions.

In March 2011, the US EPA issued draft standards under the federal Clean Water Act which would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. EME is still evaluating the proposed standards but believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable without incurring material additional capital expenditures or operating costs for both the Midwest Generation plants and the Homer City plant. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and EME is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants, but are not expected to be material for the Homer City plant, which already has cooling towers.

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Note 11. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consisted of the following:

(in millions)		Unrealized Gains (Losses) on Cash Flow Hedges			Unrecognized Losses and Prior Service Adjustments, Net¹			Accumulated Other Comprehensive Loss


Balance at December 31, 2010		$	16		$	(47	)	$	(31	)
	Current period change		(4	)		1			(3	)

Balance at March 31, 2011		$	12		$	(46	)	$	(34	)

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

Included in accumulated other comprehensive loss at March 31, 2011 was $21 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $9 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is May 31, 2014.

Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $21 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

Note 12. Supplemental Cash Flows Information

		Three Months Ended March 31,

(in millions)		2011			2010

Cash paid (received)
	Interest (net of amount capitalized)¹	$	(4	)	$	3
	Income taxes		9			3
	Cash payments under plant operating leases		76			89
Non-cash activities from consolidation of variable interest entity
	Assets	$	—		$	94
	Liabilities		—			99
Non-cash activities from deconsolidation of variable interest entities
	Assets	$	—		$	249
	Liabilities		—			253
Non-cash activities from accrued capital expenditures		$	38		$	43

¹: Interest paid for the three months ended March 31, 2011 was $6 million. Interest capitalized for the three months ended March 31, 2011 and 2010 was $10 million and $11 million, respectively.

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Note 13. Discontinued Operations

Summarized financial information for discontinued operations is as follows:

	Three Months Ended March 31,

(in millions)	2011			2010

Income (loss) before income taxes	$	(2	)	$	11
Provision for income taxes		—			5

Income (loss) from operations of discontinued foreign subsidiaries	$	(2	)	$	6

The 2011 loss was due primarily to changes in foreign exchange rates. The 2010 income was primarily attributable to the expiration of a contract indemnity.

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

This quarterly report on Form 10-Q 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 from those currently expected, or that otherwise could impact EME or its subsidiaries, include but are not limited to:

•: EME's ability to borrow funds and access the capital markets on reasonable terms;
•: environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect EME's cost and manner of doing business;
•: supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;
•: the cost and availability of fuel, sorbents, and other commodities used for power generation and emission controls, and of related transportation services;
•: the cost and availability of emission credits or allowances;
•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other aspects of the complex and volatile markets in which EME and its subsidiaries participate;
•: the availability and creditworthiness of counterparties, and the resulting effects on liquidity in the power and fuel markets in which EME and its subsidiaries operate and/or the ability of counterparties to pay amounts owed to EME in excess of collateral provided in support of their obligations;
•: governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including the market structure rules applicable to each market and price mitigation strategies adopted by independent system operators and regional transmission organizations;
•: market volatility and other market conditions that could increase EME's obligations to post collateral beyond the amounts currently expected, and the potential effect of such conditions on the ability of EME and its subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;

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•: actions taken by Edison International and EME's directors, each of whom is appointed by Edison International, in the interests of Edison International and its shareholders, which could include causing EME, subject to contractual obligations and applicable law, to distribute cash or assets or otherwise take actions that may alter the portion of Edison International's portfolio of assets held and developed by EME;
•: project development and acquisition risks, including those related to project site identification, financing, construction, permitting, and governmental approvals;
•: weather conditions, natural disasters and other unforeseen events;
•: the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities, and technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;
•: operating risks, including equipment failure, availability, heat rate, output, costs of repairs and retrofits, and availability and cost of spare parts;
•: creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: general political, economic and business conditions;
•: EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and payment agreements with EME's respective affiliates; and
•: EME's ability to attract and retain skilled people.

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 29 of EME's annual report on Form 10-K for the year ended December 31, 2010. Readers are urged to read this entire quarterly report on Form 10-Q and the annual report on Form 10-K for the year ended December 31, 2010, including the information incorporated by reference, and to 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, 2010, and as compared to the first quarter ended March 31, 2010. 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, 2010.

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MANAGEMENT'S OVERVIEW

EME's competitive power generation business primarily consists of the generation and sale into the PJM market on a merchant basis of energy and capacity from its approximately 7,000 megawatts of coal-fired power plants. The profitability of these operations is expected to be significantly lower in 2011 as a result of lower realized energy prices driven by the expiration of hedge contracts, higher fuel costs and unplanned outages at the Homer City plant during the first quarter. In addition, the profitability of EME's Midwest Generation plants is expected to be adversely affected in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract). For discussion of energy and fuel price risks, see "Market Risk Exposures—Commodity Price Risk" and refer to "Item 1A. Risk Factors—Market Risks" on page 33 of EME's annual report on Form 10-K for the year ended December 31, 2010. As a result, EME may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.

Highlights of Operating Results

Net income (loss) attributable to EME common shareholder is composed of the following components:

		Three Months Ended March 31,

(in millions)		2011			2010		Change

Net income (loss) attributable to EME common shareholder		$	(20	)	$	81	$	(101	)

Non-Core Items
	Income (loss) from discontinued operations		(2	)		6		(8	)

Core Earnings (Losses)		$	(18	)	$	75	$	(93	)

EME's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with analysts and investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as net income (loss) attributable to EME's shareholder excluding income (loss) from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, sale of assets, early debt extinguishment costs, other activities that are no longer continuing, asset impairments, and certain tax, regulatory or legal proceedings.

EME's first quarter 2011 core earnings were lower than first quarter 2010 core earnings primarily due to the following pre-tax items:

•: $32 million decrease in Midwest Generation adjusted operating income due to lower generation, lower average realized energy prices and higher operating expenses partially offset by higher capacity revenue.
•: $53 million decrease in Homer City adjusted operating income due primarily to lower generation resulting from the Unit 1 and 2 unplanned outages. Unit 1 returned to service in early April, and Unit 2 is expected to return to service during the second quarter of 2011.

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•: $32 million decrease in energy trading revenues due to lower congestion revenue and power trading revenue.
•: $32 million lower income from distributions received from the March Point and Doga projects during the first quarter of 2010, with no comparable amounts in 2011.

Midwest Generation Environmental Compliance Plans and Costs

During the first quarter of 2011, Midwest Generation continued its permitting and planning activities for NO_x and SO₂ controls to meet the requirements of the CPS. In February 2011, the Illinois Environmental Protection Agency issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or other sodium-based sorbents at the Powerton Station's Units 5 and 6.

Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO₂ emissions remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to temporarily or permanently shut down units, instead of installing controls, to be in compliance with the CPS.

Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others.

In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of HAPs from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NO_x and SO₂ as well as for HAPs, such as mercury, acid gas and non-mercury metals.

Homer City Outage

On February 10, 2011, a steam pipe ruptured at Unit 1 of the Homer City plant, taking the unit off line. Homer City took Unit 2 off line, which has the same design and operating conditions, to further evaluate the equipment due to the risk of a similar failure. On April 5, 2011, Unit 1 returned to service after making needed repairs, including replacing all pipes similar to the ruptured pipe. Unit 2 is undergoing similar repairs and is expected to return to service in the second quarter of 2011.

The unplanned outages at Units 1 and 2 and the continuation of low power prices have impacted Homer City's liquidity. As a result, in order to have sufficient working capital available for operating expenses and to pay the equity portion of Homer City's rent payment that was due April 1, 2011 to the owner-lessors, Homer City had to defer certain fuel deliveries, arrange for accelerated payments by EMMT for future energy deliveries under an intercompany arrangement in place between EMMT and

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Homer City, and draw $12 million from the $20 million equity rent reserve established under its sale-leaseback transaction documents. Homer City must restore the equity rent reserve account and continue to make equity rent payments in order to be entitled to make future distributions. The advance payments made and currently anticipated in April are expected to total approximately $30 million. It is currently anticipated that all such amounts will be applied against amounts invoiced by EMMT under an intercompany arrangement within the next six months, but the actual rate at which such advance payments will be applied will depend upon prevailing power prices and other factors. To further stabilize Homer City's liquidity, effective April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, effective April 1, 2011, these revenues will now be recorded as part of Homer City's revenues in lieu of their prior classification as EMMT trading revenues. EMMT realized trading revenues of $28 million under this arrangement in 2010.

The actions described above also resulted in Homer City being in compliance with the covenant requirements under the sale-leaseback documents at March 31, 2011. Under these documents, the rent payments are comprised of two components, a senior rent portion and an equity rent portion. The senior rent is used exclusively for debt service to the holders of the senior secured bonds issued in connection with the sale-leaseback transaction, while the equity rent is paid to the owner-lessors. In order to pay the equity portion of the rent, among other requirements, Homer City is required to meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances).

For additional information, see "Liquidity and Capital Resources—Dividend Restrictions in Major Financings" and refer to "Liquidity Risks" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010.

US EPA Developments

For information regarding recent developments in environmental regulations, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

EME's Liquidity

At March 31, 2011, EME, as a holding company, had cash and cash equivalents of $391 million to meet liquidity needs as well as $484 million of capacity under its credit facility. EME's subsidiary, EMMT, also had cash and cash equivalents of $228 million at March 31, 2011, which can be loaned or distributed to EME subject to applicable laws. In addition, at March 31, 2011, Midwest Generation had cash and cash equivalents of $363 million to meet liquidity needs.

Midwest Generation has not yet committed to the completion of environmental compliance activities for all of its plants. Additional expenditures for NO_x and SO₂ controls through 2013 are estimated at $567 million based on an assumption that Midwest Generation would retrofit all units over the compliance period, which extends to 2018. Depending upon the facilities selected to be retrofitted, the cost of such retrofitting, and the timing of funding requirements beyond the near term, Midwest Generation may utilize operating cash flow, draw on its credit facilities, when available, or seek debt financing to fund capital expenditures.

Capital expenditures to complete renewable energy projects for the remainder of 2011 are projected to be $216 million at March 31, 2011. EME anticipates that capital investment for renewable energy projects under construction will be funded using a combination of construction and term financings,

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U.S. Treasury grants and cash on hand. In addition, U.S. Treasury grants of $367 million are anticipated based on estimated eligible construction costs for renewable projects completed or scheduled to be completed in 2011. To the extent that the renewable projects supporting these investments and capitalized assets are not successful, EME would incur a material charge.

Edison International's utilization of net operating losses and production tax credits from EME in its consolidated return impacts EME's liquidity. The bonus depreciation extension enacted in the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act is expected to result in delays in EME's receipt of future tax-allocation payments. For more information, see "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement," "Liquidity and Capital Resources—Available Liquidity—Bonus Depreciation Impact on EME" and refer to "Item 1A. Risk Factors—Liquidity Risks" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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RESULTS OF OPERATIONS

Results of Continuing Operations

Overview

EME operates in one line of business, independent power production. The following section and table provide a summary of results of EME's operating projects and corporate expenses for the first quarters of 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

The following table shows the adjusted operating income (loss) (AOI) of EME's projects:

	Three Months Ended March 31,

(in millions)	2011			2010

Midwest Generation plants	$	55		$	87
Homer City plant¹		(16	)		37
Renewable energy projects		21			10
Energy trading¹		15			47
Big 4 projects		2			4
Sunrise		(7	)		(4	)
Doga		—			15
March Point²		—			17
Westside projects		—			1
Other projects		4			3
Other operating income (expense)		—			2

		74			219
Corporate administrative and general		(34	)		(36	)
Corporate depreciation and amortization		(6	)		(4	)

AOI³	$	34		$	179

¹: Effective April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.
²: Sold in 2010.
³: AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.

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

		Three Months Ended March 31,

(in millions)		2011			2010

AOI		$	34		$	179
Less:
	Equity in income (loss) of unconsolidated affiliates		(5	)		17
	Dividend income from projects		1			16
	Production tax credits		18			14
	Other income, net		3			2

Operating Income		$	17		$	130

Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

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

			Three Months Ended March 31,

(in millions)			2011		2010

Operating Revenues			$	351	$	379
Operating Expenses
	Fuel¹			126		141
	Plant operations			118		99
	Plant operating leases			19		19
	Depreciation and amortization			29		28
	Administrative and general			6		5

	Total operating expenses			298		292

Operating Income				53		87

Other Income				2		—

AOI			$	55	$	87

Statistics²
	Generation (in GWh)			7,470		8,212
	Aggregate plant performance
		Equivalent availability		87.0%		85.9%
		Capacity factor		67.0%		69.6%
		Load factor		77.0%		81.1%
		Forced outage rate		5.1%		6.7%
	Average realized price/MWh		$	36.65	$	39.52
	Capacity revenues only (in millions)		$	77	$	47
	Average realized fuel costs/MWh		$	16.73	$	16.63

¹: Included in fuel costs were $2 million and $4 million during the quarters ended March 31, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NO_x emission allowances

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to Midwest Generation were $0.4 million during each of the first quarters of 2011 and 2010. Transfers of SO₂ emission allowances from Midwest Generation were none and $4 million during the first quarters of 2011 and 2010, respectively. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

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

AOI from the Midwest Generation plants decreased $32 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues and higher plant operations costs, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation primarily related to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS.

Included in operating revenues were unrealized gains of none and $7 million for the first quarters of 2011 and 2010, respectively. Unrealized gains in 2010 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at the Midwest Generation plants was attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system).

Included in fuel costs were unrealized losses of $1 million and $5 million during the first quarters of 2011 and 2010, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.

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Homer City

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

		Three Months Ended March 31,

(in millions)		2011			2010

Operating Revenues		$	115		$	175
Operating Expenses
	Fuel¹		52			70
	Plant operations		47			37
	Plant operating leases		25			25
	Depreciation and amortization		5			5
	Administrative and general		2			1

	Total operating expenses		131			138

Operating Income (Loss)			(16	)		37

AOI		$	(16	)	$	37

Statistics²
	Generation (in GWh)		1,943			2,954
	Equivalent availability		59.2%			80.2%
	Capacity factor		47.8%			72.4%
	Load factor		80.7%			90.3%
	Forced outage rate		27.1%			10.4%
	Average realized energy price/MWh	$	45.31		$	50.17
	Capacity revenues only (in millions)	$	24		$	29
	Average fuel costs/MWh	$	26.96		$	23.57

¹: Included in fuel costs were $0.3 million and $4 million during the quarters ended March 31, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO₂ emission allowances to Homer City were none and $4 million during the first quarters of 2011 and 2010, respectively. Transfers of NO_x emission allowances from Homer City were $0.4 million during each of the first quarters of 2011 and 2010. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."
²: For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions."

AOI from the Homer City plant decreased $53 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues, driven by lower generation, and higher plant maintenance costs from unplanned outages at Units 1 and 2, partially offset by lower fuel costs. The decline in fuel costs was primarily due to lower generation, partially offset by higher coal costs.

Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(2) million for the first quarters of 2011 and 2010, respectively. Unrealized gains (losses) were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City

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busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).

Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions

Average Realized Energy Price

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

		Three Months Ended March 31,

Midwest Generation Plants (in millions)		Three Months Ended March 31,
Midwest Generation Plants (in millions)		2011			2010

Operating revenues		$	351		$	379
Less:
	Unrealized gains		—			(7	)
	Capacity and other revenues		(77	)		(48	)

Realized revenues		$	274		$	324

Generation (in GWh)			7,470			8,212
Average realized energy price/MWh		$	36.65		$	39.52

		Three Months Ended March 31,

Homer City Plant (in millions)		Three Months Ended March 31,
Homer City Plant (in millions)		2011			2010

Operating revenues		$	115		$	175
Less:
	Unrealized (gains) losses		(2	)		2
	Capacity and other revenues		(25	)		(29	)

Realized revenues		$	88		$	148

Generation (in GWh)			1,943			2,954
Average realized energy price/MWh		$	45.31		$	50.17

The average realized energy price is presented as an aid in understanding the operating results of the coal plants. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to

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real-time market prices. A reconciliation of the operating revenues of the coal plants and renewable energy projects to consolidated operating revenues presented in the preceding table is set forth below:

		Three Months Ended March 31,

(in millions)		2011		2010

Operating revenues
	Midwest Generation plants	$	351	$	379
	Homer City plant		115		175
	Renewable energy projects		52		30
	Other revenues		32		67

Consolidated operating revenues as reported		$	550	$	651

Average Realized Fuel Costs

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

		Three Months Ended March 31,

Midwest Generation Plants (in millions)		Three Months Ended March 31,
Midwest Generation Plants (in millions)		2011			2010

Fuel costs		$	126		$	141
Less:
	Unrealized losses		(1	)		(5	)

Realized fuel costs		$	125		$	136

Generation (in GWh)			7,470			8,212
Average realized fuel costs/MWh		$	16.73		$	16.63

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

		Three Months Ended March 31,

(in millions)		2011		2010

Fuel costs
	Midwest Generation plants	$	126	$	141
	Homer City plant		52		70
	Other		4		2

Consolidated fuel costs as reported		$	182	$	213

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Statistical Definitions

•: Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance. The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
•: The capacity factor indicates how much power a unit generated compared to the maximum amount of power that could be generated according to its rating. It is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
•: The load factor indicates how much power a unit generated compared to the maximum amount of power that a unit was available to generate electricity. It is determined by dividing capacity factor by the equivalent availability factor.
•: The forced outage rate refers to forced outages and deratings excluding events outside of management's control as defined by NERC. Examples include floods, tornado damage and transmission outages.

Seasonality—Coal Plants

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

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Renewable Energy Projects

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

			Three Months Ended March 31,

(in millions)			2011		2010

Operating Revenues			$	52	$	30
Production Tax Credits				18		14

				70		44

Operating Expenses
	Plant operations			18		12
	Depreciation and amortization			31		21
	Administrative and general			1		1

	Total operating expenses			50		34
Equity in income (loss) from unconsolidated affiliates				—		(1	)
Other Income				1		1

AOI¹			$	21	$	10

Statistics²
	Generation (in GWh)³			1,385		843
	Aggregate plant performance³
		Equivalent availability		93.6%		90.8%
		Capacity factor		37.9%		33.1%

¹: AOI is equal to operating income (loss) plus equity in income (losses) of unconsolidated affiliates, production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects.
²: The statistics section summarizes key performance measures related to wind projects, which represents substantially all of the renewable energy projects.
³: Includes renewable energy projects that are unconsolidated at EME. Generation excluding unconsolidated projects was 183 GWh and 152 GWh in the first quarter of 2011 and 2010, respectively.

AOI from renewable energy projects increased $11 million in the first quarter of 2011, compared to the first quarter of 2010. The 2011 increase was primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions.

Energy Trading

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

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AOI from energy trading activities decreased $32 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease was primarily attributable to lower revenues from congestion and power trading, compared to higher revenue in the first quarter of 2010.

Adjusted Operating Income from Unconsolidated Affiliates

March Point. During the first quarter of 2010, AOI from the March Point project was $17 million due to equity distributions received from the project. EME subsequently sold its ownership interest in the March Point project to its partner at book value in February 2010.

Doga. During the first quarter of 2010, EME received a distribution from the Doga project. EME expects to receive a distribution from the Doga project during the second half of 2011. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.

Seasonality. EME's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.

Interest Income (Expense)

		Three Months Ended March 31,

(in millions)		2011			2010

Interest income		$	1		$	1

Interest expense, net of capitalized interest
	EME debt	$	(62	)	$	(60	)
	Non-recourse debt		(18	)		(8	)

		$	(80	)	$	(68	)

EME's interest expense increased primarily due to higher debt balances for wind project financing, higher interest expense related to a loan amendment and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $10 million for the first quarter of 2011, compared to $11 million for the first quarter of 2010.

Income Taxes

Income taxes for the three months ended March 31, 2011 and 2010 included tax benefits of production tax credits of $18 million and $14 million, respectively. For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes."

Results of Discontinued Operations

Income from discontinued operations, net of tax, decreased $8 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease was primarily due to the expiration of a contract indemnity during the first quarter of 2010 related to EME's previous sale of international projects.

New Accounting Guidance

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

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at March 31, 2011:

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


EME as a holding company		$	391	$	484	$	875
EME subsidiaries without contractual dividend restrictions			228		—		228

EME corporate cash and cash equivalents			619		484		1,103
EME subsidiaries with contractual dividend restrictions
	Midwest Generation¹		363		497		860
	Homer City		147		—		147
	Other EME subsidiaries		54		—		54

Total		$	1,183	$	981	$	2,164

¹: Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure requirements.

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

The following table summarizes the status of the EME and Midwest Generation credit facilities at March 31, 2011, which mature in June 2012:

(in millions)	EME			Midwest Generation


Commitments	$	564		$	500
Outstanding borrowings		—			—
Outstanding letters of credit		(80	)		(3	)

Amount available	$	484		$	497

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

For additional discussion of liquidity and the impact of Homer City's outages, see "Management's Overview."

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Bonus Depreciation Impact on EME

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

Capital Investment Plan

At March 31, 2011, forecasted capital expenditures through 2013 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		April through December 2011		2012		2013


Midwest Generation Plants
	Plant capital expenditures	$	23	$	21	$	28
	Environmental expenditures		82		172		317
Homer City Plant
	Plant capital expenditures		13		26		16
	Environmental expenditures		—		—		—
Renewable Energy Projects
	Capital and construction expenditures		126		—		—
	Turbine commitments		90		—		—
Other capital expenditures			11		14		14

Total		$	345	$	233	$	375

Environmental Capital Expenditures

Midwest Generation plants' environmental expenditures include $64 million for remaining expenditures in 2011 related to selective non-catalytic reduction (SNCR) equipment and $503 million for expenditures for the remainder of 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO₂ emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project. For additional discussion, see "Management's Overview—Midwest Generation Compliance Plans and Costs."

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The capital investment plan set forth in the previous table does not include environmental capital expenditures for Homer City. However, depending on upcoming and future regulatory developments, Homer City may be required to undertake capital projects to install additional pollution control equipment, which will be dependent on lessor decisions and on obtaining available funding for these expenditures. Homer City projects that if SO₂ reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO₂ and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures, and Homer City may need third-party capital to fund such activities in order to continue operating, the availability of which cannot be assured. EME has no legal obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made. For a discussion of environmental regulations, refer to "Item 1. Environmental Matters and Regulations" on page 19 and "Regulatory and Environmental Risks" on page 31 of EME's annual report on Form 10-K for the year ended December 31, 2010.

Non-Environmental Capital Expenditures

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

Renewable energy projects' capital and construction expenditures include a project of an unconsolidated entity in which construction expenditures will be substantially funded by EME. In addition, U.S. Treasury grants of $367 million are anticipated based on estimated eligible construction costs for renewable projects completed in 2010 and scheduled to be completed in 2011.

Future Projects

The capital investment plan set forth in the previous table does not include capital expenditures for future projects. At March 31, 2011, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,700 MW. The development pipeline represents potential wind projects with respect to which EME either owns the project rights or has exclusive acquisition rights. At March 31, 2011, EME had two wind projects totaling 160 MW under construction. In April 2011, the 55 MW Pinnacle wind project in West Virginia commenced construction. EME anticipates that these wind projects will achieve commercial operation in 2011. The pace of additional growth in EME's renewable program will be subject to the availability of third-party equity capital. At March 31, 2011, EME had capitalized costs and made turbine deposits totaling $45 million related to renewable energy development efforts. To the extent that the renewable energy projects are not successful, EME would record a charge to write down the carrying amount of these assets.

During the first quarter, EME entered into a memorandum of understanding with AES Southland Holdings, LLC to purchase certain equipment at AES's Huntington Beach facility and lease back such equipment until decommissioned. The transaction, if consummated, would result in retirement of the equipment in late 2012 in connection with the startup of EME's proposed Walnut Creek natural gas-fired peaker plant, thereby exempting the proposed Walnut Creek plant from 90% of the regulatory requirement for emission reduction credits needed to start construction. In April 2011, EME entered

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into turbine supply and construction agreements with limited contractual obligations until such time as the remaining development activities, including final permitting, are completed. EME intends to obtain project debt financing for this 479 MW project, which has a long-term power sales agreement with Southern California Edison Company. Completion of development is subject to a number of conditions, none of which are assured.

EME's Historical Consolidated Cash Flow

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

Condensed Consolidated Statement of Cash Flows

	Three Months Ended March 31,

(in millions)	2011			2010

Operating cash flow from continuing operations	$	114		$	312
Operating cash flow from discontinued operations		(2	)		6

Net cash provided by operating activities		112			318
Net cash provided by (used in) financing activities		104			34
Net cash used in investing activities		(108	)		(115	)

Effect of consolidation of variable interest entity on cash		—			5
Effect on cash from deconsolidation of variable interest entities		—			(4	)

Net increase in cash and cash equivalents	$	108		$	238

Consolidated Cash Flows from Operating Activities

The first quarter 2011 decrease as compared to the first quarter of 2010 in cash provided by operating activities from continuing operations was primarily attributable to lower net income and the settlement of derivative contracts in 2010.

Consolidated Cash Flows from Financing Activities

The first quarter 2011 increase as compared to the first quarter of 2010 in cash provided by financing activities from continuing operations was primarily attributable to additional borrowing in Viento Funding II refinance and advances under the Laredo and Big Sky financing agreements.

Consolidated Cash Flows from Investing Activities

Cash used in investing activities for the first quarters of 2011 and 2010 primarily consisted of capital expenditures. In addition, cash used in investing activities for the first quarter of 2010 included turbine deposits (investment in other assets) related to wind projects.

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Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of March 31, 2011 were as follows:

	Moody's Rating	S&P Rating	Fitch Rating


EME¹	B3	B-	B-
Midwest Generation²	Ba2	B+	BB
EMMT	Not Rated	B-	Not Rated

¹: Senior unsecured rating.
²: First priority senior secured rating.

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

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

Credit Rating of EMMT

For a discussion of the effect of EMMT's credit rating on EME's ability to sell forward the output of the Homer City plant through EMMT, refer to "Credit Rating of EMMT" in Item 7 on page 60 of EME's annual report on Form 10-K for the year ended December 31, 2010.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. For further details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2011, if wholesale energy prices change or if EMMT enters into additional transactions. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit

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facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings."

EME's Liquidity as a Holding Company

EME's Credit Facility Financial Ratios

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility. The following details of EME's interest coverage ratio and a maximum corporate-debt-to-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements. At March 31, 2011, EME and its subsidiaries were in compliance with the terms of their debt covenants.

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

			12 Months Ended

(in millions)			March 31, 2011			December 31, 2010

Funds Flow Available for Interest
	Distributions
		Midwest Generation	$	120		$	125
		Homer City		74			74
		Big 4 projects		70			77
		U.S. Treasury grants		92			92
		Renewable energy projects		287			223
		Other projects		30			63
	Tax payments received from subsidiaries			136			136
	Realized trading income			105			120
	Tax-allocation receipts (payments)¹			82			90
	Operating expenses			(136	)		(139	)
	Other items, net			(30	)		(56	)

			$	830		$	805

Net Interest Expense
	EME corporate debt		$	225		$	223
	Addback: Capitalized interest			53			54
	Powerton-Joliet intercompany notes			111			112

			$	389		$	389

Ratio				2.13			2.07
Covenant threshold (not less than)				1.20			1.20

¹: Excludes production tax credits for Viento Funding II, Inc. and certain state tax payments which are classified in other items, net.

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

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

(in millions)			March 31, 2011			December 31, 2010


Corporate Debt
	Indebtedness for money borrowed		$	3,700		$	3,700
	Powerton-Joliet termination value			870			933
	Letters of credit			82			83

			$	4,652		$	4,716

Corporate Capital
	Common shareholder's equity		$	2,794		$	2,842
	Less:
		Non-cash cumulative changes in accounting		(9	)		(9	)
		Accumulated other comprehensive income		34			31
	Adjustments:
		After-tax losses incurred on termination of Collins lease		587			587
		Dividend to Mission Energy Holding Company for repayment of 13.5% notes		899			899

				4,305			4,350

	Corporate debt			4,652			4,716

			$	8,957		$	9,066

Corporate-debt-to-capital ratio				0.52			0.52
Covenant threshold (not more than)				0.75			0.75

Dividend Restrictions in Major Financings

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, 2011 or for the 12 months ended March 31, 2011:

Subsidiary	Financial Ratio	Covenant	Actual


Midwest Generation (Midwest Generation plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.14 to 1
Homer City (Homer City plant)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	1.87 to 1

To pay dividends, Homer City must meet the senior rent service coverage ratio. In addition, Homer City is restricted from paying dividends until the Homer City equity reserve account is replenished. For additional information, see "Management's Overview—Homer City Outage."

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 64 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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

EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At March 31, 2011, the maximum permissible sale or disposition of EME assets is calculated as follows:

(in millions)


Consolidated Net Tangible Assets
	Total consolidated assets		$	9,457
	Less:
		Consolidated current liabilities		(510	)
		Intangible assets		(77	)

			$	8,870

10% Threshold			$	887

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

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

Contractual Obligations and Contingencies

Fuel Supply Contracts

For a discussion of fuel supply contracts, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Commitments—Fuel Supply Contracts."

Midwest Generation New Source Review Lawsuit

For a discussion of the Midwest Generation New Source Review Lawsuit, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."

Homer City New Source Review Lawsuit

For a discussion of the Homer City New Source Review Lawsuit, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Homer City New Source Review Lawsuit."

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Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 on page 68 of EME's annual report on Form 10-K for the year ended December 31, 2010. 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 "Environmental Matters and Regulations" in Item 1 on page 19 of EME's annual report on Form 10-K for the year ended December 31, 2010. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as set forth in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

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MARKET RISK EXPOSURES

For a detailed discussion of EME's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "Market Risk Exposures" in Item 7 on page 71 of EME's annual report on Form 10-K for the year ended December 31, 2010.

Derivative Instruments

Unrealized Gains and Losses

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

		Three Months Ended March 31,

(in millions)		2011			2010

Midwest Generation plants
	Non-qualifying hedges	$	(1	)	$	(2	)
	Ineffective portion of cash flow hedges		—			4
Homer City plant
	Non-qualifying hedges		1			—
	Ineffective portion of cash flow hedges		1			(2	)

Total unrealized gains		$	1		$	—

At March 31, 2011, cumulative unrealized gains of $5 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($(1) million for the remainder of 2011 and $6 million for 2012).

Fair Value Disclosures

In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EME's derivative instruments, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "—Note 6. Derivative Instruments and Hedging Activities," respectively.

Commodity Price Risk

Energy Price Risk Affecting Sales from the Coal Plants

Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub, and to a lesser extent, the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant.

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The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first quarters of 2011 and 2010:

		24-Hour Average Historical Market Prices¹

		2011		2010

Midwest Generation plants
	Northern Illinois Hub	$	34.09	$	34.53
Homer City plant
	PJM West Hub	$	45.77	$	44.53
	Homer City Busbar		41.47		39.33

¹: Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM West Hub using historical hourly real-time prices as published by PJM or provided on the PJM web-site.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at March 31, 2011:

		24-Hour Forward Energy Prices¹

		Northern Illinois Hub		PJM West Hub

2011
	April	$	29.53	$	40.01
	May		28.15		39.74
	June		30.92		43.44
	July		35.17		48.86
	August		37.29		50.28
	September		28.63		42.66
	October		25.17		40.65
	November		28.56		41.65
	December		30.14		45.92
2012 calendar "strip"²		$	31.30	$	46.20

¹: Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub and PJM West Hub delivery points.
²: Market price for energy purchases for the entire calendar year.

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

EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services

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contracts and forward contracts accounted for on the accrual basis) at March 31, 2011 for electricity expected to be generated during the remainder of 2011 and in 2012 and 2013:

		2011				2012				2013

		MWh (in thousands)		Average price/ MWh¹		MWh (in thousands)		Average price/ MWh¹		MWh (in thousands)		Average price/ MWh¹

Midwest Generation plants
	Northern Illinois and AEP/Dayton Hubs		7,664	$	37.78		5,350	$	35.25		1,020	$	39.11
Homer City plant^2,3
	PJM West Hub		1,195		58.86		1,370		51.68		204		51.85

Total			8,859				6,720				1,224

¹: The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.
²: Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. Years 2011 and 2012 include hedging activities entered into by EMMT for the Homer City plant that are not designated under the intercompany agreements with Homer City due to limitations under the sale leaseback transaction documents.
³: The average price/MWh includes 182 to 191 MW of capacity for periods ranging from April 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at March 31, 2011:

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

		Installed Capacity MW		Unsold Capacity¹ MW			Capacity Sold² MW		MW		Price per MW-day		MW			Average Price per MW-day		Aggregate Average Price per MW-day

April 1, 2011 to May 31, 2011
	Midwest Generation		5,477		(548	)		4,929		4,929	$	174.29		—			—	$	174.29
	Homer City		1,884		(261	)		1,623		1,813		174.29		(190	)	$	53.95		188.38
June 1, 2011 to May 31, 2012
	Midwest Generation		5,477		(495	)		4,982		4,582		110.00		400			85.00		107.99
	Homer City		1,884		(163	)		1,721		1,771		110.00		(50	)		30.00		112.32
June 1, 2012 to May 31, 2013
	Midwest Generation		5,477		(773	)		4,704		4,704		16.46		—			—		16.46
	Homer City		1,884		(232	)		1,652		1,736		133.37		(84	)		16.46		139.31
June 1, 2013 to May 31, 2014
	Midwest Generation		5,477		(827	)		4,650		4,650		27.73		—			—		27.73
	Homer City		1,884		(104	)		1,780		1,780		226.15		—			—		221.03	⁴

¹: Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.
²: Excludes 182 to 191 MW of capacity for periods ranging from April 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

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³: Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.
⁴: Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

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

Basis Risk

During the three months ended March 31, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 12%, respectively, due to transmission congestion in PJM. During the three months ended March 31, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub and Northern Illinois Hub by an average of 10% and 1%, respectively, compared to 11% and 1%, respectively, during the three months ended March 31, 2010, due to transmission congestion in PJM.

Coal and Transportation Price Risk

The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at March 31, 2011 for the remainder of 2011 and the following two years:

	Amount of Coal Under Contract in Millions of Equivalent Tons¹

	April through December 2011		2012		2013

Midwest Generation plants		12.4		9.8		—
Homer City plant		3.5		1.9		0.8

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

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City plant, increased during 2011 from 2010 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to a price of $76.15 per ton at April 1, 2011, compared to a price of $70 per ton at December 31, 2010, as reported by the Energy Information Administration.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $13.25 per ton and $14.75 per ton during the first quarter of 2011. The market price of PRB coal decreased to a price of $13.25 per ton at April 1, 2011, compared to a price of $13.60 per ton at December 31, 2010, as reported by the Energy Information Administration.

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EME has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through December 31, 2011. EME is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.

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 (CAIR), coal plants are required to hold seasonal and annual NO_x allowances.

In the event that actual emissions required are greater than allowances held, EME is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO₂ allowances decreased to $10 per ton during the first quarter of 2011 from $50 per ton in 2010. The average purchase price of annual NO_x allowances decreased to $335 per ton during the first quarter of 2011 from $936 per ton in 2010. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_x allowances was $5 per ton and $227.50 per ton, respectively, at March 31, 2011.

Credit Risk

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, 2011, the balance sheet exposure as described above, by the credit ratings of EME's counterparties, was as follows:

		March 31, 2010

(in millions)		Exposure²		Collateral			Net Exposure

Credit Rating¹
	A or higher	$	93	$	—		$	93
	A-		2		—			2
	BBB+		11		—			11
	BBB		5		—			5
	BBB-		11		—			11
	Below investment grade		48		(47	)		1

Total		$	170	$	(47	)	$	123

¹: EME assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
²: Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable.

The credit risk exposure set forth in the above table is composed of $80 million of net accounts receivable and payables and $90 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments

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in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $46 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 68% of EME's consolidated operating revenues for the three months ended March 31, 2011. At March 31, 2011, EME's account receivable due from PJM was $55 million.

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

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of EME's critical accounting policies, refer to "Critical Accounting Estimates and Policies" in Item 7 on page 80 of EME's annual report on Form 10-K for the year ended December 31, 2010.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 71 in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2010. 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 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

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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 "Contingencies" on page 148 of EME's annual report on Form 10-K for the year ended December 31, 2010. 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, 2010, except as follows:

Midwest Generation New Source Review Lawsuit

In March 2011, the U.S. District Court for the Northern District of Illinois dismissed nine of the ten PSD claims asserted against Midwest Generation and EME by the State of Illinois and the Department of Justice, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The Court also dismissed all claims asserted against Commonwealth Edison Company and EME. The Court denied a motion to dismiss a claim by intervenor citizens groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the Court that the statute of limitations should be equitably tolled. The Court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013.

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 29 of EME's annual report on Form 10-K for the year ended December 31, 2010. The risks described in EME's annual report on Form 10-K and in this report are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.

ITEM 6. EXHIBITS

Exhibit No.			Description


	31.1		Certification of the President pursuant to Section 302 of the Sarbanes-Oxley Act.
	31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
	32		Statement Pursuant to 18 U.S.C. Section 1350.
	101		Financial statements from the quarterly report on Form 10-Q of Edison Mission Energy for the quarter ended March 31, 2011, filed on May 2, 2011, formatted in XBRL: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		EDISON MISSION ENERGY
		By:		/s/ Maria Rigatti Maria Rigatti Senior Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)
		Date:		May 2, 2011