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 September 30, 2010
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number 333-68630

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


Delaware (State or other jurisdiction of incorporation or organization)		95-4031807 (I.R.S. Employer Identification No.)
18101 Von Karman Avenue, Suite 1700 Irvine, California (Address of principal executive offices)		92612 (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


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 October 29, 2010: 100 shares (all shares held by an affiliate of the registrant).

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GLOSSARY					v
PART I – FINANCIAL INFORMATION					1
ITEM 1. FINANCIAL STATEMENTS					1
	CONSOLIDATED STATEMENTS OF INCOME				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 and Cash Equivalents			6
		Inventory			7
		New Accounting Guidance			7
			Accounting Guidance Adopted in 2010		7
				Consolidation—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities	7
				Fair Value Measurements and Disclosures	7
			Accounting Guidance Not Yet Adopted		7
				Revenue—Multiple-Deliverables	7
	Note 2. Fair Value Measurements				8
		Long-term Obligations			11
	Note 3. Derivative Instruments and Risk Management				11
		Notional Volumes of Derivative Instruments			12
		Fair Value of Derivative Instruments			14
		Income Statement Impact of Derivative Instruments			14
		Contingent Features/Credit Related Exposure			15
		Margin and Collateral Deposits			15
	Note 4. Accumulated Other Comprehensive Income				16
	Note 5. Discontinued Operations				17
	Note 6. Consolidated Statement of Changes in Equity				18
	Note 7. Variable Interest Entities				18
		Projects or Entities that are Consolidated			19
		Projects that are not Consolidated			20
	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. Income Taxes				22
		Unrecognized Tax Benefits			23
	Note 10. Commitments and Contingencies				23
		Contractual Obligations			23
			Project Financing		23

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				Laredo Ridge	23
				Cedro Hill	24
			Long-Term Debt		24
		Commitments			24
			Capital Improvements		24
			Turbine Commitments		25
			Fuel Supply and Transportation Contracts		25
			Letters of Credit		25
		Guarantees and Indemnities			25
			Environmental Indemnities Related to the Midwest Generation Plants		25
			Environmental Indemnity Related to the Homer City Facilities		26
			Indemnities Provided under Asset Sale and Sale-Leaseback Agreements		27
		Contingencies			27
			Midwest Generation New Source Review Lawsuit		27
				Recent Developments	27
				Background	28
			Homer City New Source Review Notice of Violation		29
				Recent Developments	29
				Background	29
			Environmental Remediation		29
			Environmental Developments		30
				Midwest Generation Environmental Compliance Plans and Costs	30
				Homer City Environmental Issues and Capital Resource Limitations	31
				Climate Change	31
				Transport Rule	31
				National Ambient Air Quality Standard for Sulfur Dioxide	32
				Hazardous Substances and Hazardous Waste Laws	32
	Note 11. Supplemental Cash Flows Information				33
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS					34
	MANAGEMENT'S OVERVIEW				35
	Introduction				35
	Highlights of Operating Results				36
	Environmental Developments				37
		Midwest Generation Environmental Compliance Plans and Costs			37
		US EPA Developments			38
	EME's Renewables Program				38
		Mitsubishi Lawsuit			39
	EME's Liquidity				39
	RESULTS OF OPERATIONS				40
	Results of Continuing Operations				40
		Overview			40
		Adjusted Operating Income from Consolidated Operations			42
			Midwest Generation Plants		42
			Homer City Facilities		44
			Non-GAAP Disclosures—Fossil-Fueled Facilities		45

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			Adjusted Operating Income	45
			Average Realized Energy Price	46
			Average Realized Fuel Costs	47
		Statistical Definitions		48
		Seasonal Disclosure—Fossil-Fueled Facilities		48
		Renewable Energy Projects		49
		Energy Trading		50
	Adjusted Operating Income from Unconsolidated Affiliates			50
		Doga		50
		March Point		50
		Seasonal Disclosure		50
	Interest Related Income (Expense)			51
	Income Taxes			51
Results of Discontinued Operations				51
New Accounting Guidance				51
Derivative Instruments				52
	Unrealized Gains and Losses			52
	Fair Value Disclosures			52
LIQUIDITY AND CAPITAL RESOURCES				53
Available Liquidity				53
	Overview			53
	Small Business Jobs Act of 2010			54
Capital Investment Plan				54
EME's Historical Consolidated Cash Flow				55
	Condensed Consolidated Statement of Cash Flows			55
		Consolidated Cash Flows from Operating Activities		55
		Consolidated Cash Flows from Financing Activities		55
		Consolidated Cash Flows from Investing Activities		56
Credit Ratings				56
	Overview			56
	Credit Rating of EMMT			56
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts			56
EME's Liquidity as a Holding Company				57
	EME's Credit Facility Financial Ratios			57
Dividend Restrictions in Major Financings				59
	Key Ratios of EME's Principal Subsidiaries Affecting Dividends			59
	EME's Senior Notes and Guaranty of Powerton-Joliet Leases			59
Contractual Obligations and Contingencies				60
	Fuel Supply and Transportation Contracts			60
	Midwest Generation New Source Review Lawsuit			60
	Homer City New Source Review Notice of Violation			60
Off-Balance Sheet Transactions				60
Environmental Matters and Regulations				61
MARKET RISK EXPOSURES				62

iii

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	Commodity Price Risk		62
		Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities	62
		Capacity Price Risk	64
		Basis Risk	64
		Coal and Transportation Price Risk	65
		Emission Allowances Price Risk	65
	Credit Risk		66
	Interest Rate Risk		67
	CRITICAL ACCOUNTING ESTIMATES AND POLICIES		67
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			67
ITEM 4T. CONTROLS AND PROCEDURES			67
	Disclosure Controls and Procedures		67
	Internal Control Over Financial Reporting		67
PART II – OTHER INFORMATION			68
ITEM 1. LEGAL PROCEEDINGS			68
	Midwest Generation New Source Review Lawsuit		68
		Recent Developments	68
	Homer City New Source Review Notice of Violation		68
		Recent Developments	68
	Mitsubishi Lawsuit		69
ITEM 1A. RISK FACTORS			69
ITEM 6. EXHIBITS			69
SIGNATURES			70

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GLOSSARY

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



AOI		adjusted operating income (loss)
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
Commonwealth Edison		Commonwealth Edison Company
CPS		Combined Pollutant Standard
EME		Edison Mission Energy
EMMT		Edison Mission Marketing & Trading, Inc.
FASB		Financial Accounting Standards Board
Fossil-fueled facilities		Midwest Generation fossil-fueled power plants and Homer City electric generating station
GAAP		United States generally accepted accounting principles
GHG		greenhouse gas
GWh		gigawatt-hours
Homer City		EME Homer City Generation L.P.
Illinois EPA		Illinois Environmental Protection Agency
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
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
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

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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF INCOME (in millions, unaudited)
			Three Months Ended September 30,						Nine Months Ended September 30,

			2010			2009			2010			2009

Operating Revenues			$	691		$	593		$	1,835		$	1,762
Operating Expenses
	Fuel			228			228			602			587
	Plant operations			135			131			523			426
	Plant operating leases			44			44			133			132
	Depreciation and amortization			62			62			181			174
	Administrative and general			43			48			133			144

		Total operating expenses		512			513			1,572			1,463

	Operating income			179			80			263			299

Other Income (Expense)
	Equity in income from unconsolidated affiliates			60			60			99			88
	Dividend income			1			1			18			11
	Interest income			—			—			2			6
	Interest expense			(64	)		(78	)		(198	)		(225	)

		Total other expense		(3	)		(17	)		(79	)		(120	)

	Income from continuing operations before income taxes			176			63			184			179
	Provision for income taxes			58			10			11			27

Income from Continuing Operations				118			53			173			152
Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 5)				(5	)		(1	)		4			(5	)

Net Income				113			52			177			147

Net (Income) Loss Attributable to Noncontrolling Interests				—			1			—			2

Net Income Attributable to EME Common Shareholders			$	113		$	53		$	177		$	149

Amounts Attributable to EME Common Shareholders
Income from continuing operations, net of tax			$	118		$	54		$	173		$	154
Income (loss) from discontinued operations, net of tax				(5	)		(1	)		4			(5	)

Net Income Attributable to EME Common Shareholders			$	113		$	53		$	177		$	149

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 September 30,						Nine Months Ended September 30,

			2010			2009			2010			2009

Net Income			$	113		$	52		$	177		$	147
Other comprehensive income (loss), net of tax
	Pension and postretirement benefits other than pensions:
		Amortization of net loss and prior service adjustment included in expense, net of tax		—			1			—			2
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $29 and $(4) for the three months and $41 and $44 for the nine months ended September 30, 2010 and 2009, respectively		43			(5	)		61			56
		Reclassification adjustments included in net income, net of income tax benefit of $5 and $52 for the three months and $54 and $75 for the nine months ended September 30, 2010 and 2009, respectively		(7	)		(72	)		(80	)		(104	)

Other comprehensive income (loss)				36			(76	)		(19	)		(46	)

Comprehensive Income (Loss)				149			(24	)		158			101

Comprehensive Loss Attributable to Noncontrolling Interests				—			1			—			2

Comprehensive Income (Loss) Attributable to EME Common Shareholders			$	149		$	(23	)	$	158		$	103

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)
			September 30, 2010		December 31, 2009

Assets
Current Assets
	Cash and cash equivalents		$	1,097	$	796
	Accounts receivable—trade			141		201
	Receivables from affiliates			8		93
	Inventory			221		196
	Derivative assets			105		197
	Restricted cash			15		69
	Margin and collateral deposits			89		120
	Prepaid expenses and other			63		190

		Total current assets		1,739		1,862

Investments in Unconsolidated Affiliates				578		361

Property, Plant and Equipment				6,884		6,279
	Less accumulated depreciation and amortization			1,690		1,474

		Net property, plant and equipment		5,194		4,805

Other Assets
	Deferred financing costs			53		43
	Long-term derivative assets			74		81
	Restricted deposits			42		40
	Rent payments in excess of levelized rent expense under plant operating leases			1,186		1,038
	Other long-term assets			216		403

		Total other assets		1,571		1,605

Total Assets			$	9,082	$	8,633

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)
			September 30, 2010		December 31, 2009

Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	79	$	97
	Payables to affiliates			19		14
	Accrued liabilities			182		247
	Derivative liabilities			6		5
	Interest payable			101		30
	Deferred taxes			131		119
	Current maturities of long-term obligations			43		37
	Construction loans			98		—

		Total current liabilities		659		549

Long-term obligations net of current maturities				4,087		3,929
Deferred taxes and tax credits				677		672
Deferred revenues				163		153
Long-term derivative liabilities				32		15
Other long-term liabilities				533		478

Total Liabilities				6,151		5,796

Commitments and Contingencies (Note 10)
Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of September 30, 2010 and December 31, 2009			64		64
	Additional paid-in capital			1,339		1,339
	Retained earnings			1,464		1,280
	Accumulated other comprehensive income			59		78

		Total EME common shareholder's equity		2,926		2,761

Noncontrolling Interests				5		76

Total Equity				2,931		2,837

Total Liabilities and Equity			$	9,082	$	8,633

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)
			Nine Months Ended September 30,
			2010			2009

Cash Flows From Operating Activities
	Net income		$	177		$	147
	(Income) loss from discontinued operations			(4	)		5

	Income from continuing operations, net			173			152
	Adjustments to reconcile income to net cash provided by (used in) operating activities:
		Equity in income from unconsolidated affiliates		(98	)		(86	)
		Distributions from unconsolidated affiliates		75			46
		Depreciation and amortization		190			180
		Deferred taxes and tax credits		35			314
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		31			(118	)
		Decrease (increase) in accounts receivables		147			(70	)
		Increase in inventory		(22	)		(28	)
		Decrease in prepaid expenses and other		—			39
		Decrease (increase) in restricted cash		53			(148	)
		Increase in rent payments in excess of levelized rent expense		(148	)		(161	)
		Decrease in accounts payable and other current liabilities		(129	)		(130	)
		Increase in interest payable		71			71
		Decrease (increase) in derivative assets and liabilities		86			(55	)
		Proceeds from U.S. Treasury grants		92			—
		Other operating—assets		8			12
		Other operating—liabilities		24			69

	Operating cash flow from continuing operations			588			87
	Operating cash flow from discontinued operations			4			(5	)

		Net cash provided by operating activities		592			82

Cash Flows From Financing Activities
	Borrowings on long-term debt			118			189
	Payments on long-term debt agreements			(26	)		(409	)
	Borrowings under construction loans			98			—
	Payments to affiliates related to stock-based awards			(2	)		(2	)
	Financing costs			(16	)		(14	)

		Net cash provided by (used in) financing activities from continuing operations		172			(236	)

Cash Flows From Investing Activities
	Capital expenditures			(469	)		(177	)
	Proceeds from return of capital and loan repayments and sale of assets			16			11
	Purchase of interest of acquired companies			(4	)		(7	)
	Maturities of short-term investments			1			2
	Decrease in restricted cash			—			3
	Investments in other assets			(7	)		(277	)

		Net cash used in investing activities from continuing operations		(463	)		(445	)

Net increase (decrease) in cash and cash equivalents				301			(599	)
Cash and cash equivalents at beginning of period				796			1,807

Cash and cash equivalents at end of period			$	1,097		$	1,208

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
SEPTEMBER 30, 2010
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

EME's significant accounting policies were described in "Note 1—Summary of Significant Accounting Policies" on page 114 of EME's annual report on Form 10-K for the year ended December 31, 2009. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2010 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 and nine months ended September 30, 2010 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.

Cash and Cash Equivalents

Cash and cash equivalents consisted of the following:

(in millions)	September 30, 2010		December 31, 2009


Cash	$	258	$	106
Money market funds		839		690

Total cash and cash equivalents	$	1,097	$	796

The carrying value of cash equivalents, which consists of money market funds, equals the fair value as all investments have maturities of less than three months. For further discussion of money market funds, see Note 2—Fair Value Measurements.

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Inventory

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

(in millions)	September 30, 2010		December 31, 2009


Coal, fuel oil and other raw materials	$	150	$	132
Spare parts, materials and supplies		71		64

Total	$	221	$	196

New Accounting Guidance

Accounting Guidance Adopted in 2010

Consolidation—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

The FASB issued an accounting standards update that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has the obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. EME adopted this guidance effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of certain wind assets totaling $253 million and the consolidation of coal assets totaling $99 million at January 1, 2010. Deconsolidation did not result in a gain or loss. The consolidation of EME's 50% partnership interest in American Bituminous Power Partners, L.P., referred to as the Ambit project, a coal-fired electrical plant project with a capacity of 80 MW, resulted in a cumulative effect adjustment that increased retained earnings by $10 million. For further discussion, see Note 7—Variable Interest Entities.

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. Requirements, effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 2—Fair Value Measurements.

Accounting Guidance Not Yet Adopted

Revenue—Multiple-Deliverables

In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and

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recognizing revenue based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. EME is currently assessing the effects this guidance may have on its consolidated financial statements.

Note 2. 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 for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize inputs to valuation models. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:

•: Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;
•: Level 2—Pricing inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument; and
•: Level 3—Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.

EME's assets and liabilities carried at fair value primarily consist of derivative contracts and money market funds. Derivative contracts are primarily commodity contracts for the purchase and sale of power and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices in active markets.

Derivative contracts, valued based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks, are classified as Level 2. EME obtains forward market prices from traded exchanges (Intercontinental Exchange Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.

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

In assessing nonperformance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The fair value of derivative assets nonperformance risk was $2 million at September 30, 2010.

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The following table sets forth EME's assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:

			As of September 30, 2010

(in millions)			Level 1			Level 2			Level 3			Netting and Collateral²			Total

Assets at Fair Value
	Money market funds¹		$	854		$	—		$	—		$	—		$	854

	Derivatives
		Electricity	$	—		$	192		$	135		$	(148	)	$	179
		Natural gas		3			—			—			(3	)		—
		Fuel oil		10			—			—			(10	)		—

		Total commodity contracts		13			192			135			(161	)		179

	Total derivatives		$	13		$	192		$	135		$	(161	)	$	179

Liabilities at Fair Value
	Derivatives
		Electricity	$	—		$	(37	)	$	(13	)	$	44		$	(6	)
		Natural gas		—			(3	)		—			—			(3	)
		Coal		—			(3	)		—			3			—

		Total commodity contracts		—			(43	)		(13	)		47			(9	)
		Interest rate contracts		—			(29	)		—			—			(29	)

	Total derivatives		$	—		$	(72	)	$	(13	)	$	47		$	(38	)

			As of December 31, 2009

Assets at Fair Value
	Money market funds¹		$	758		$	—		$	—		$	—		$	758

	Derivatives
		Electricity	$	—		$	235		$	179		$	(136	)	$	278
		Natural gas		2			—			—			(2	)		—
		Fuel oil		15			—			—			(15	)		—

		Total commodity contracts		17			235			179			(153	)		278

	Total derivatives		$	17		$	235		$	179		$	(153	)	$	278

Liabilities at Fair Value
	Derivatives
		Electricity	$	—		$	(85	)	$	(6	)	$	73		$	(18	)
		Natural gas		(3	)		(1	)		—			4			—

		Total commodity contracts		(3	)		(86	)		(6	)		77			(18	)
		Interest rate contracts		—			(2	)		—			—			(2	)

	Total derivatives		$	(3	)	$	(88	)	$	(6	)	$	77		$	(20	)

¹: At September 30, 2010 and December 31, 2009, included in cash and cash equivalents and restricted cash, and at December 31, 2009, also included in prepaid expenses and other on EME's consolidated balance sheets.
²: Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

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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 September 30,								Nine Months Ended September 30,

		2010			2009					2010			2009
(in millions)		Deriva- tives			Deriva- tives			Money Market Funds		Deriva- tives			Deriva- tives			Money Market Funds

Fair value at beginning of periods		$	166		$	240		$	1	$	173		$	213		$	3
Total realized/unrealized gains (losses)
	Included in earnings¹		24			30			—		51			127			—
	Included in accumulated other comprehensive income (loss)		1			—			—		5			—			—
Purchases and settlements, net			(73	)		(55	)		—		(116	)		(113	)		(2	)
Transfers in or out of Level 3			4			1			—		9			(11	)		—

Fair value at September 30		$	122		$	216		$	1	$	122		$	216		$	1

Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at September 30¹		$	(3	)	$	38		$	—	$	1		$	75		$	—

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

EME determines the fair value of transfers in and transfers out of each level at the end of each reporting period. Transfers in and out of Levels 1 and 2 were not significant during the third quarters and nine months ended September 30, 2010 and 2009.

Long-term Obligations

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

	As of September 30, 2010				As of December 31, 2009

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

Long-term obligations, including current portion	$	4,130	$	3,180	$	3,966	$	3,150

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

The carrying amount of trade receivables, payables and construction loans approximates fair value and, therefore, is not included in the table above.

Note 3. Derivative Instruments and Risk Management

EME uses derivative instruments to reduce EME's exposure to market risks that arise from fluctuations in prices of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. To the extent that EME does not use

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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 in the consolidated statements of income. For transactions that qualify for accounting hedge treatment, the fair value is recognized, to the extent effective, on EME's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted transaction occurs.

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

Notional Volumes of Derivative Instruments

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

September 30, 2010

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

Electricity	Forwards/Futures	Sales	GWh		26,322	¹		15,995	³		33,485
Electricity	Forwards/Futures	Purchases	GWh		408	¹		16,529	³		35,741
Electricity	Capacity	Sales	MW-Day (in thousands)		195	²		—			150	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		12	²		—			461	²
Electricity	Congestion	Sales	GWh		—			136	⁴		10,977	⁴
Electricity	Congestion	Purchases	GWh		—			1,016	⁴		210,974	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			0.6			37.3
Natural gas	Forwards/Futures	Purchases	bcf		—			—			36.4
Fuel oil	Forwards/Futures	Sales	barrels		—			150,000			319,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			495,000			329,000
Coal	Forwards/Futures	Sales	tons		—			—			1,794,750
Coal	Forwards/Futures	Purchases	tons		—			—			1,748,250

(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	$	145	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

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December 31, 2009

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

Electricity	Forwards/Futures	Sales	GWh		24,355	¹		26,838	³		23,306
Electricity	Forwards/Futures	Purchases	GWh		106	¹		25,971	³		23,404
Electricity	Capacity	Sales	MW-Day (in thousands)		254	²		1	²		597	²
Electricity	Capacity	Purchases	MW-Day		11	²		2	²		736	²
			(in thousands)
Electricity	Congestion	Sales	GWh		—			136	⁴		10,212	⁴
Electricity	Congestion	Purchases	GWh		—			1,576	⁴		181,930	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			3.3			30.8
Natural gas	Forwards/Futures	Purchases	bcf		—			—			30.6
Fuel oil	Forwards/Futures	Sales	barrels		—			250,000			120,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			625,000			120,000

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	160	June 2016

¹: EME's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the fossil-fueled facilities which meet the normal sales and purchase 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 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:

September 30, 2010

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

Non-trading activities
	Cash flow hedges	$	151		$	33		$	184		$	4		$	36		$	40		$	144
	Economic hedges		108			7			115			101			7			108			7
Trading activities			246			137			383			209			70			279			104

			505			177			682			314			113			427			255
Netting and collateral received¹			(400	)		(103	)		(503	)		(308	)		(81	)		(389	)		(114	)

Total		$	105		$	74		$	179		$	6		$	32		$	38		$	141

December 31, 2009
Non-trading activities
	Cash flow hedges	$	240		$	17		$	257		$	69		$	6		$	75		$	182
	Economic hedges		202			8			210			180			—			180			30
Trading activities			234			111			345			182			41			223			122

			676			136			812			431			47			478			334
Netting and collateral received¹			(479	)		(55	)		(534	)		(426	)		(32	)		(458	)		(76	)

Total		$	197		$	81		$	278		$	5		$	15		$	20		$	258

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

Income Statement Impact of Derivative Instruments

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

	Cash Flow Hedge Activity¹ Nine Months Ended September 30,

	Cash Flow Hedge Activity¹ Nine Months Ended September 30,						Income Statement Location
(in millions)	2010			2009			Income Statement Location

Accumulated other comprehensive income derivative gain at January 1	$	175		$	398
Effective portion of changes in fair value		102			100
Reclassification from accumulated other comprehensive income to net income		(134	)		(179	)	Operating revenues

Accumulated other comprehensive income derivative gain at September 30	$	143		$	319

¹: Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at September 30, 2010 and 2009 were $86 million and $192 million, respectively.

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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 a net gain of $4 million and $11 million during the third quarters of 2010 and 2009, respectively, and $5 million and $16 million during the nine months ended September 30, 2010 and 2009, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues on the consolidated statements of income.

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

		Three Months Ended September 30,					Nine Months Ended September 30,

	Income Statement Location	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	Income Statement Location	2010		2009			2010		2009

Economic hedges	Operating revenues	$	7	$	19		$	—	$	35
	Fuel costs		2		(2	)		—		12
Trading activities	Operating revenues		28		16			108		43

Contingent Features/Credit Related Exposure

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at September 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.

Margin and Collateral Deposits

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

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following table summarizes margin and collateral deposits provided to and received from counterparties:

(in millions)		September 30, 2010		December 31, 2009


Collateral provided to counterparties
	Offset against derivative liabilities	$	4	$	49
	Reflected in margin and collateral deposits		89		120
Collateral received from counterparties
	Offset against derivative assets		118		124

Note 4. Accumulated Other Comprehensive Income

Accumulated other comprehensive income consisted of the following:

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


Balance at December 31, 2009		$	105		$	(27	)	$	78
	Current period change		(19	)		—			(19	)

Balance at September 30, 2010		$	86		$	(27	)	$	59

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

Included in accumulated other comprehensive income at September 30, 2010 was $104 million, net of tax, in unrealized gains on commodity-based cash flow hedges; and an $18 million, net of tax, unrealized loss related to interest rate hedges. The maximum period over which a cash flow hedge is designated is through March 31, 2026.

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 $89 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. The maximum period over which a commodity cash flow hedge is designated is through May 31, 2014.

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Note 5. Discontinued Operations

Summarized financial information for discontinued operations is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)	2010			2009			2010		2009

Income (loss) before income taxes	$	(4	)	$	(1	)	$	11	$	(7	)
Provision (benefit) for income taxes		1			—			7		(2	)

Income (loss) from operations of discontinued foreign subsidiaries	$	(5	)	$	(1	)	$	4	$	(5	)

During the nine months ended September 30, 2010, EME made payments of $41 million for a tax indemnity related to EME's previous sale of an international project. EME recorded year-to-date discontinued operations income before taxes of $11 million due primarily to expiration of a contract indemnity during the first nine months of 2010 and changes in foreign exchange rates.

Discontinued operations includes $2 million, net adjustments to unrecognized tax benefits. For further detail, see Note 9—Income Taxes.

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Note 6. Consolidated Statement of Changes in Equity

Consolidated statement of changes in equity at the beginning and the end of the nine months ended September 30, 2009 and 2010:

				EME Shareholder's Equity

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

Balance at December 31, 2008	$	2,764		$	64	$	1,335		$	1,085		$	200		$	80
Net income (loss)		147								149						(2	)
Other comprehensive loss		(46	)										(46	)
Payments to Edison International for stock purchases related to stock-based compensation		(2	)							(2	)
Other stock transactions, net		3					3

Balance at September 30, 2009	$	2,866		$	64	$	1,338		$	1,232		$	154		$	78

Balance at December 31, 2009	$	2,837		$	64	$	1,339		$	1,280		$	78		$	76
Impact of deconsolidation of variable interest entities (Note 7)		(71	)													(71	)
Cumulative effect of a change in accounting principle, net of tax¹		10								10
Net income		177								177
Other comprehensive loss		(19	)										(19	)
Payments to Edison International for stock purchases related to stock-based compensation		(3	)							(3	)
Other stock transactions, net		5					5
Purchase of noncontrolling interests²		(5	)				(5	)

Balance at September 30, 2010	$	2,931		$	64	$	1,339		$	1,464		$	59		$	5

¹: For the nine months ended September 30, 2010, reflects the impact of adopting accounting guidance related to variable interest entities.
²: During the second quarter of 2010, EME purchased a noncontrolling interest in Laredo Ridge, which is now 100% owned by EME. The purchase of the noncontrolling interest was accounted for as an equity transaction between controlling and noncontrolling interest holders.

Note 7. Variable Interest Entities

Effective January 1, 2010, EME adopted the FASB's new guidance regarding variable interest entities. A variable interest entity is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The new guidance replaces the predominantly quantitative model for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with a qualitative approach. Under this new qualitative model, the primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable

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interest entity that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of variable interest entities in which EME has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.

Projects or Entities that are Consolidated

At September 30, 2010 and December 31, 2009, EME had majority interests in 15 wind projects with a total generating capacity of 700 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. As of December 31, 2009, all of these projects were consolidated by EME. Upon the application of the new guidance effective January 1, 2010, EME deconsolidated two of these projects. See further discussion in "—Projects that are not Consolidated." In determining that EME was the primary beneficiary of the 13 projects consolidated at September 30, 2010, the key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities.

The following table presents summarized financial information of the wind projects that had minority interests held by others and were consolidated by EME:

(in millions)		September 30, 2010		December 31, 2009


Current assets		$	22	$	73
Net property, plant and equipment¹			669		944
Other long-term assets			2		2

	Total assets¹	$	693	$	1,019

Current liabilities		$	15	$	17
Long-term obligations net of current maturities			17		20
Deferred revenues			57		58
Other long-term liabilities			19		21

	Total liabilities	$	108	$	116

Noncontrolling interests		$	4	$	76

¹: Amounts included assets of $253 million ($247 million of net property, plant and equipment) that were deconsolidated on January 1, 2010.

Assets serving as collateral for the debt obligations had a carrying value of $75 million and $81 million at September 30, 2010 and December 31, 2009, respectively, and primarily consist of property, plant and equipment.

EME has a 50% partnership interest in the Ambit project. EME has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has the obligation to absorb losses and right to receive benefits from the project. Therefore, under the new guidance, EME is the primary beneficiary. As the primary beneficiary, EME consolidated Ambit project assets totaling $99 million on January 1, 2010.

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The following table presents the summarized financial information of the Ambit project consolidated by EME:

(in millions)		September 30, 2010


Current assets		$	15
Net property, plant and equipment			80
Other long-term assets			4

	Total assets	$	99

Current liabilities		$	12
Long-term obligations net of current maturities			64
Deferred revenues			14
Other long-term liabilities			2

	Total liabilities	$	92

Substantially all of the assets above are pledged as collateral for the partnership's debt obligations.

The consolidated statements of income and cash flows for the nine months ended September 30, 2010 were not significantly impacted by the consolidation of the Ambit project.

Projects that are not Consolidated

EME accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. As of September 30, 2010 and December 31, 2009, EME had five significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. The following table presents summarized financial information of these five significant projects:

	Nine Months Ended September 30,

(in millions)	2010			2009

Revenues	$	600		$	549
Expenses		(440	)		(390	)

Net income	$	160		$	159

A subsidiary of EME operates the 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.

As noted previously in "—Projects or Entities that are Consolidated," EME deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The primary purpose of these projects is to operate renewable wind energy facilities. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EME is not the primary beneficiary of these projects. Accordingly, effective January 1, 2010, EME accounts for its interests in these projects under the equity method.

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

	As of September 30, 2010

(in millions)	Investment		Maximum Exposure

Natural gas-fired projects	$	360	$	360
Wind projects		218		218

EME's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EME's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's investment, but would not require EME to contribute additional capital. At September 30, 2010, entities which EME has accounted for under the equity method had indebtedness of $141 million, of which $53 million is proportionate to EME's ownership interest in these projects.

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

Contributions to EME's pension plans were $19 million for the nine months ended September 30, 2010 and are estimated at $3 million for the last three months of 2010.

The following are components of pension expense:

	Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)	2010			2009			2010			2009

Service cost	$	4		$	3		$	12		$	10
Interest cost		3			3			10			9
Expected return on plan assets		(2	)		(1	)		(7	)		(5	)
Amortization of net loss		1			1			2			3

Total expense	$	6		$	6		$	17		$	17

Postretirement Benefits Other Than Pensions

Contributions to EME's postretirement benefits other than pensions were $1 million for the nine months ended September 30, 2010 and are estimated at $1 million for the last three months of 2010.

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The following are components of postretirement benefits expense:

	Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)	2010		2009		2010			2009

Service cost	$	1	$	1	$	2		$	2
Interest cost		1		2		4			5
Amortization of prior service credit		—		—		(1	)		(1	)
Amortization of net loss		—		—		—			1

Total expense	$	2	$	3	$	5		$	7

Note 9. Income Taxes

The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholders:

	Nine Months Ended September 30,

(in millions)	2010			2009

Provision for income tax at federal statutory rate of 35%	$	65		$	63
State tax—net of federal benefit (excludes state tax settlement)		5			13
Production tax credits		(45	)		(40	)
Federal settlement of tax disputes		—			(6	)
Resolution of 1986-2002 state tax issues		(16	)		—
Other		2			(3	)

Income tax expense from continuing operations	$	11		$	27

EME recorded a tax benefit of $16 million in 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for the tax years 1986 through 2002.

During the nine months ended September 30, 2009, Edison International and the Internal Revenue Service completed a settlement of federal tax disputes and affirmative claims for open tax years 1986 through 2002. EME recorded an income tax benefit of $6 million due to the settlement and related estimated impact of interest and state income taxes.

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Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)		Nine Months Ended September 30, 2010


Balance at January 1		$	115
Tax positions taken during the current year
	Increases		—
	Decreases		—
Tax positions taken during a prior year
	Increases		78
	Decreases		(72	)
Decreases for settlements during the period			(8	)

Balance at September 30		$	113

As of September 30, 2010, if recognized, $110 million of unrecognized tax benefits would impact the effective tax rate.

The Internal Revenue Service examination phase of Edison International's federal income tax returns for tax years 2003 through 2006 is anticipated to be completed by the end of 2010. During the third quarter, Edison International received a proposed adjustment increasing the taxable gain on the 2004 sale of EME's international assets, which, if sustained, would result in federal and state tax payments of approximately $152 million, including interest. The Internal Revenue Service examination team is considering whether to assess penalties in addition to this proposed tax adjustment. Edison International does not agree with the proposed adjustment and expects to file an appeal with the Internal Revenue Service after the examination phase is completed. In addition, the Internal Revenue Service examination team, during the third quarter, has informed Edison International that it has completed its review of certain other tax positions and will not be proposing adjustments.

Note 10. Commitments and Contingencies

Contractual Obligations

Project Financing

Laredo Ridge

In July 2010, EME completed through its subsidiary, Laredo Ridge Wind, LLC, a non-recourse financing of its interests in the Laredo Ridge wind project. The financing included: a $75 million construction loan required to be converted to a 15-year amortizing term loan by August 31, 2011, subject to meeting specified conditions; a $53 million bridge loan, secured by the expected U.S. Treasury grant, immediately due to be fully repaid upon receipt of the U.S. Treasury grant and no later than December 31, 2011; a $9 million letter of credit facility; and a $3 million working capital facility.

Interest under the construction loan and the term loan will accrue at LIBOR plus 2.75% initially, with the rate increasing 0.125% after the third, sixth, ninth and twelfth years. Pursuant to the financing agreement, Laredo Ridge entered into a forward starting interest rate swap agreement at 3.46% to hedge the majority of the variable interest rate debt effective March 31, 2011, the same date EME

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estimates that the construction loan will convert to the term loan. Interest under the bridge loan will accrue at LIBOR plus 2.50%.

As of September 30, 2010, there was $20 million outstanding under the construction loan at a weighted average interest rate of 3.01% classified as a construction loan and $50 million outstanding under the bridge loan at a weighted average interest rate of 2.76% classified as long-term obligations, both on EME's consolidated balance sheet, and $3 million of outstanding letters of credit.

Cedro Hill

In March 2010, EME completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that is required to be converted to a 15-year amortizing term loan by May 31, 2011, subject to meeting specified conditions, a $21 million letter of credit facility and a $4 million working capital facility.

Interest under the construction loan and the term loan will accrue at LIBOR plus 3% initially, with the rate increasing 0.125% after the third, sixth, ninth and eleventh years and 0.25% after the thirteenth year. Pursuant to the financing agreement, Cedro Hill Wind entered into a forward starting interest rate swap agreement at 4.29% to hedge the majority of the variable interest rate debt effective December 31, 2010, the same date EME estimates that the construction loan will convert to the term loan.

As of September 30, 2010, there was $78 million outstanding under the construction loan at a weighted average interest rate of 3.26% classified as a construction loan on EME's consolidated balance sheet and $11.5 million of outstanding letters of credit.

Long-Term Debt

EME consolidated the Ambit project on January 1, 2010. At September 30, 2010, this project had $71 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The average interest rate for the nine months ended September 30, 2010 was 0.27%. Annual maturities of this debt at September 30, 2010 for the next five years are summarized as follows: $8 million in 2010, $8 million in 2011, $9 million in 2012, $10 million in 2013, and $10 million in 2014.

The Ambit project is required to maintain funded reserve accounts primarily for debt servicing and maintenance costs. The required reserve account balance at September 30, 2010 was $24 million and was under funded by $15 million. The underfunded reserve does not create an event of default under the loan, but does restrict distributions from the Ambit project.

Commitments

Capital Improvements

At September 30, 2010, EME's subsidiaries had firm commitments to spend approximately $199 million during the remainder of 2010 and $79 million in 2011 on capital and construction expenditures. These expenditures primarily relate to the construction of wind projects. EME intends to fund these expenditures through project-level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations.

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Turbine Commitments

EME has entered into various turbine supply agreements with vendors to support its wind development efforts. As of September 30, 2010, EME had commitments, excluding turbines subject to the legal dispute described below, to purchase 46 wind turbines (69 MW) and had 2 wind turbines (6 MW) in storage to be used for future wind projects. EME has payment commitments related to wind turbines of $82 million due in 2011.

Excluded from the turbine commitments referred to above are commitments under a turbine supply agreement between Mitsubishi Power Systems Americas, Inc. and EME, which was subject to a legal dispute as of September 30, 2010. On October 8, 2010, EME and the Mitsubishi entities entered into a settlement agreement with respect to the dispute. As a result of the settlement agreement, EME's $68 million deposit previously paid under the original contract will be applied to the purchase price for 23 wind turbines (55 MW). Within the next three years, EME may elect to deploy 60 additional wind turbines (144 MW). EME may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. EME further agreed to payments of up to $40 million for settlement of remaining disputes on turbines purchased.

Fuel Supply and Transportation Contracts

At September 30, 2010, Midwest Generation and Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are estimated to aggregate $883 million, summarized as follows: $136 million for the remainder of 2010, $461 million in 2011, $253 million in 2012, and $33 million in 2013.

At September 30, 2010, Midwest Generation and Homer City each had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. The minimum commitments under these contracts are estimated to aggregate $300 million, summarized as follows: $75 million for the remainder of 2010, and $225 million in 2011.

Letters of Credit

At September 30, 2010, letters of credit under EME's credit facility aggregated $101 million and were scheduled to expire as follows: $6 million in 2010 and $95 million in 2011. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $32 million and were scheduled to expire as follows: $2 million in 2010 and $30 million in 2011.

Guarantees and Indemnities

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

Environmental Indemnities Related to the Midwest Generation Plants

In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after

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December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. 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." The sale-leaseback participants have requested similar indemnification. 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 2011. There were approximately 220 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at September 30, 2010. Midwest Generation had recorded a $57 million liability at September 30, 2010 for previous, pending and future claims.

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

Environmental Indemnity Related to the Homer City Facilities

In connection with the acquisition of the Homer City facilities, 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 facilities, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by Homer City and associated indemnity claims, see "—Contingencies—Homer City New Source Review Notice of Violation." EME has not recorded a liability related to this indemnity.

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Indemnities Provided under Asset Sale and Sale-Leaseback Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At September 30, 2010, EME had recorded a liability of $42 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 asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined.

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

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

Contingencies

Midwest Generation New Source Review Lawsuit

Recent Developments

In March 2010, the Federal District Court for the Northern District of Illinois dismissed nine of the ten counts related to PSD requirements in the complaint filed by the US EPA and the State of Illinois against Midwest Generation, holding that, as a subsequent owner, Midwest Generation could not be held liable under the PSD provisions for modifications allegedly made by Commonwealth Edison, the prior owner of the Midwest Generation plants. The Court also dismissed the tenth count to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The decision did not address (i) other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA, or (ii) the complaint in intervention filed by a group of Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.

In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset

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purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.

In June 2010, the US EPA, the State of Illinois, and several environmental groups filed amended complaints in the New Source Review litigation. The amended complaints are similar to the prior complaints, but seek to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. Midwest Generation and EME have filed a motion to dismiss the amended complaints, and a status hearing has been scheduled for February 2011.

Background

In August 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the PSD requirements and of the New Source Performance Standards of the 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. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the U.S. Department of Justice, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.

In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. 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 those required under the CPS. By order dated January 19, 2010, the Court allowed a group of Chicago-based environmental action groups to intervene in the case.

The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.

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 EME at such time. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

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Homer City New Source Review Notice of Violation

Recent Developments

In May 2010, Homer City received an NOV from the US EPA. The new NOV alleges claims similar to those in the 2008 NOV, but it adds nonattainment New Source Review requirements to the alleged PSD violations. It also adds two prior owners of the Homer City facilities as parties.

In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the Pennsylvania Department of Environmental Protection (PADEP), stating their intent to file a citizen suit based on the same or similar theories advanced by the US EPA in the NOV. The Notice of Intent to Sue also named the sale-leaseback owner participants of the Homer City facilities, Homer City's general partner and limited partner, and two prior owners of the Homer City facilities.

Background

In June 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the PSD requirements of the CAA. The US EPA also alleges that Homer City has failed to file timely and complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the U.S. Department of Justice files suit, litigation could take many years to resolve the issues alleged in the NOV. EME cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

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

Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, sought indemnification and defense from Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.

Environmental Remediation

Because EME does not own or operate any assets, other than the stock of its subsidiaries, it does not have any direct environmental obligations or liabilities. However, legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the environment impose numerous restrictions and requirements with respect to the operation of EME's existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by EME's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations. The facilities of EME's subsidiaries which are most affected by environmental regulation are located in Illinois and Pennsylvania.

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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 $4 million at September 30, 2010 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 can be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future remediation costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During the third quarter of 2010, Midwest Generation continued its permitting and planning activities for NO_x and SO₂ controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois EPA allowing the installation of selective non-catalytic reduction (SNCR) technology on multiple units to meet the NO_x portion of the CPS, and is engaged with the Illinois EPA with respect to permitting the installation of equipment to meet required reductions for SO₂.

Work continued on the possible use of flue gas desulfurization (FGD) technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO₂ portion of the CPS. Testing of this technology demonstrated significant reductions in SO₂ emissions when using the type of coal used by Midwest Generation. Use of this technology in combination with the type of coal employed by Midwest Generation is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.

Based on the work to date, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO₂ emissions, and associated upgrading of particulate removal systems, would be approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years.

Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available.

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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.

Homer City Environmental Issues and Capital Resource Limitations

Homer City operates selective catalytic reduction equipment on all three units to reduce NO_x emissions, operates FGD equipment on Unit 3 to reduce SO₂ emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations for future operations. For further information, see "—Transport Rule" and "—Homer City New Source Review Notice of Violation." 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. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual obligation to provide funding to Homer City.

Climate Change

In June 2010, the US EPA finalized the PSD and Title V GHG tailoring rule. The effective date of the final rule is August 2, 2010. The emissions thresholds for carbon dioxide equivalents in the final rule are as follows:




January - June 2011		75,000 tons per year for new and modified sources already subject to PSD for pollutants other than GHGs
July 2011 - June 2013		100,000 tons per year for new sources, and 75,000 tons per year for modified sources

Numerous legal challenges to the GHG tailoring rule have been filed. As written, the rule applies to all sources meeting the thresholds that are built or modified after January 1, 2011. If controls are required to be installed at the facilities of EME's subsidiaries in the future in order to reduce GHG emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

Transport Rule

In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to reduce power plant emissions of NO_x and SO₂ substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule, which had been remanded to the US EPA in 2008 for revision.

The US EPA has proposed three possible approaches to emissions allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state, an emissions

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limit would be set for each power plant, and limited emissions averaging would be permitted among affected units.

Under the Transport Rule, each covered state would initially be subject to a federal implementation plan designed to reduce pollution that significantly contributed to nonattainment of, or interferes with the maintenance of, NAAQS in other states. States would be able to choose to develop state implementation plans to replace the federal implementation plans.

The Transport Rule is scheduled to be finalized in 2011. The Clean Air Interstate Rule will remain in place until that time. EME believes that the US EPA's preferred approach to emissions allowance trading would provide allowance allocations which are adequate for the Midwest Generation plants based on projected emissions using the Illinois CPS allowable emission rates. If adopted as proposed, the Transport Rule may require the installation of additional environmental equipment to reduce SO₂ emissions at Units 1 and 2 of the Homer City facilities.

National Ambient Air Quality Standard for Sulfur Dioxide

In June 2010, the US EPA finalized the primary NAAQS for SO₂ by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is in line with EME's expectations and is being taken into account in EME's environmental compliance strategy. Revisions to state implementation plans to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014. The US EPA anticipates that the deadline for attainment with the SO₂ NAAQS will be August 2017 (five years after the US EPA intends to finalize initial determinations as to the areas of the country that are and are not in attainment with the primary SO₂ NAAQS).

Hazardous Substances and Hazardous Waste Laws

In June 2010, the US EPA published proposed regulations relating to coal combustion wastes. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these wastes as special wastes subject to regulation under Subtitle C of the Resource Conservation and Recovery Act (the section for hazardous wastes), could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these wastes under Subtitle D of the Resource Conservation and Recovery Act (the section for nonhazardous wastes), is substantially similar to the requirements of existing regulations. Comments on the proposed regulations are due November 19, 2010.

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Note 11. Supplemental Cash Flows Information

		Nine Months Ended September 30,

(in millions)		2010			2009

Cash paid (received)
	Interest (net of amount capitalized¹)	$	145		$	154
	Income taxes		(100	)		(124	)
	Cash payments under plant operating leases		280			293
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			—

¹: Interest capitalized for the nine months ended September 30, 2010 and 2009 was $38 million and $11 million, respectively.

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

This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect EME's current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by EME that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this quarterly report on Form 10-Q, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact EME or its subsidiaries, include but are not limited to:

•: 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;
•: 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;
•: the cost and availability of fuel and fuel 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;

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•: 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;
•: EME's ability to borrow funds and access capital markets on reasonable terms;
•: 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;
•: operating risks, including equipment failure, availability, heat rate, output, costs of repairs and retrofits, and availability and cost of spare parts;
•: creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: general political, economic and business conditions; and
•: EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and payment agreements with EME's respective affiliates.

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in "Item 1A. Risk Factors" on page 32 of EME's annual report on Form 10-K for the year ended December 31, 2009. Readers are urged to read this entire quarterly report on Form 10-Q and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2009, and as compared to the third quarter of 2009 and nine months ended September 30, 2009. 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, 2009.

MANAGEMENT'S OVERVIEW

Introduction

EME is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power

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production facilities. EME also conducts hedging and energy trading activities in power markets through its EMMT subsidiary.

This overview is presented in four sections:

•: Highlights of operating results,
•: Environmental developments,
•: EME's renewables program, and
•: EME's liquidity.

The overview is presented as an update to the overview presented in EME's 2009 annual report on Form 10-K. For additional information on these topics, refer to "Management's Overview" on page 48 of EME's annual report on Form 10-K for the year ended December 31, 2009.

Highlights of Operating Results

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

		Three Months Ended September 30,									Nine Months Ended September 30,

(in millions)		2010			2009			Change			2010		2009			Change

Net income attributable to EME common shareholders		$	113		$	53		$	60		$	177	$	149		$	28

Non-Core Items
	Income (loss) from discontinued operations		(5	)		(1	)		(4	)		4		(5	)		9
	Settlement of tax disputes		(4	)		—			(4	)		16		6			10

	Total non-core items		(9	)		(1	)		(8	)		20		1			19

Core Earnings		$	122		$	54		$	68		$	157	$	148		$	9

EME's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies.

Core earnings are defined as earnings attributable to EME shareholders excluding income from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings such as settlement of prior year tax liabilities, change in tax law and other activities that are no longer continuing, and non-recurring regulatory or legal proceedings.

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EME's third quarter 2010 core earnings were higher than third quarter 2009 core earnings primarily due to the following:

•: $77 million increased pre-tax income from Midwest Generation and Homer City mostly from higher average realized energy prices, higher capacity revenues and a gain from the sale of bankruptcy claims against Lehman Brothers Commodity Services, Inc. and Lehman Brothers Holdings Inc., collectively referred to as Lehman. Energy and fuel related unrealized losses during the third quarter of 2010 were $13 million compared to unrealized gains of $6 million during the same period last year.

EME's core earnings for the nine months ended September 30, 2010 were higher than core earnings for the nine months ended September 30, 2009 primarily due to the following pre-tax items:

•: $65 million increased energy trading revenues due to congestion and basis trading.
•: $23 million decreased interest expense, net of interest income, primarily due to the increase in the capitalization of interest on projects under construction.
•: $17 million increased income from distributions received from the March Point and Doga projects.
•: $13 million decreased corporate expenses due primarily to lower renewable energy development expenses.

The increases were partially offset by the following pre-tax items:

•: $109 million decreased income from Midwest Generation and Homer City primarily as a result of higher plant maintenance costs during the first half of 2010. In addition, operating revenues were lower due to lower realized energy prices and unrealized losses in 2010 compared to unrealized gains in 2009, partially offset by higher capacity revenues and the sale of the bankruptcy claims discussed above. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Energy and fuel related unrealized losses during the nine months ended September 30, 2010 were $30 million compared to unrealized gains of $45 million during the same period last year. Results for the nine months ended September 30, 2010 included the benefit of power hedge contracts entered into during earlier periods at higher prices than current energy prices. For additional information about market conditions, see "Market Risk Exposures."

Consolidated non-core items for EME included:

•: An earnings benefit of $16 million recorded in the nine months ended September 30, 2010 related to the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002 as part of the federal settlement of tax disputes and revision to interest on federal disputed tax items.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

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Illinois EPA with respect to permitting the installation of equipment to meet required reductions for SO₂.

US EPA Developments

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

EME's Renewables Program

EME has five projects totaling 630 MW under construction. In the third quarter, the Community Wind North project, which EME refers to as the CWN project, was moved into construction. The CWN project, a 30 MW wind project in Minnesota, utilizes 28 MW of turbines previously in storage and one turbine on order. In addition to the projects in construction mentioned above, EME anticipates that construction will begin in 2011 on the Pinnacle project, a 55 MW wind project in West Virginia.

EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,700 MW at September 30, 2010. EME has entered into various turbine supply agreements with vendors to support its wind development efforts. Adjusted for the turbines which EME may elect to deploy related to the Mitsubishi agreement described below, EME has commitments to purchase 46 wind turbines (69 MW) to be used for future wind projects. During the second quarter of 2010, EME deferred the delivery and $82 million in payments for 69 MW of turbines to January 2011.

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If EME is unable to develop new projects on acceptable terms and conditions, EME may terminate the turbine order for these 69 MW, which would result in a material charge related to deposits previously made with the vendor.

The pace of additional growth in EME's renewables program will be subject to the availability of projects that meet EME's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or financing of the environmental retrofits, growth of the renewables program may depend upon the availability of third-party capital.

Mitsubishi Lawsuit

On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EME against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EME committed to purchase on amended terms 23 wind turbines (55 MW), agreed to certain price adjustments on the turbines purchased under the original contract, may elect to deploy 60 additional wind turbines (144 MW) that were part of the original contract, and 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. For additional information regarding the settlement, see "Legal Proceedings" in Part II of this quarterly report.

EME's Liquidity

At September 30, 2010, EME had cash and cash equivalents of $596 million to meet liquidity needs as well as $463 million of capacity under its credit facility. Expenditures for NO_x and SO₂ controls through 2012 (estimated at $315 million), are anticipated to be funded through operating cash flow and available credit facilities. EME has not yet committed to the completion of environmental compliance activities for all the Midwest Generation plants. Depending upon the facilities selected to be retrofit and the timing of funding requirements beyond the near term, EME may utilize operating cash flow or seek debt financing to fund capital expenditures.

Capital expenditures to complete renewable-related projects through 2011 are projected to be $511 million at September 30, 2010. EME anticipates that renewable project capital investment will be funded using construction financing, U.S. Treasury grants and existing EME liquidity. The following table summarizes the projected funding sources:

(in millions)


Secured project financings
	Big Sky¹	$	138
	Cedro Hill¹		57
	Laredo Ridge¹		59
Anticipated U.S. Treasury grants²			340

		$	594

¹: Remaining available balance at September 30, 2010.
²: Anticipated U.S. Treasury grants are based on estimated costs at completion of construction for renewable projects scheduled to be completed in 2011. The anticipated grants have been reduced by a bridge loan on the Laredo Ridge project that is due when the related grants funds are received. Funding sources in excess of the forecast capital expenditures are planned to be used for general corporate purposes.

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RESULTS OF OPERATIONS

Results of Continuing Operations

Overview

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

The following section and table provide a summary of results of EME's operating projects and corporate expenses for the third quarters of 2010 and 2009 and nine months ended September 30, 2010 and 2009, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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

	Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)	2010			2009			2010			2009

Midwest Generation plants	$	150		$	69		$	198		$	257
Homer City facilities		48			52			85			135
Renewable energy projects		8			—			37			37
Energy trading		27			13			105			40
Big 4 projects		33			27			49			44
Sunrise		27			30			30			31
Doga		—			—			15			8
March Point		—			4			17			7
Westside projects		—			(1	)		1			2
Other projects		—			2			6			8
Other operating income (expense)		—			—			1			—

		293			196			544			569
Corporate administrative and general		(36	)		(40	)		(106	)		(119	)
Corporate depreciation and amortization		(5	)		(4	)		(13	)		(10	)

AOI¹	$	252		$	152		$	425		$	440

¹: AOI is equal to operating income under GAAP, plus equity in earnings 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 income:

		Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)		2010		2009		2010		2009

AOI		$	252	$	152	$	425	$	440
Less:
	Equity in earnings of unconsolidated affiliates		60		60		99		88
	Dividend income from projects		1		1		18		11
	Production tax credits		12		10		45		40
	Net loss attributable to noncontrolling interest		—		1		—		2

Operating Income		$	179	$	80	$	263	$	299

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Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

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

			Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)			2010		2009		2010		2009

Operating Revenues			$	444	$	372	$	1,104	$	1,096
Operating Expenses
	Fuel¹			151		164		390		397
	Plant operations			93		89		361		291
	Plant operating leases			19		18		56		56
	Depreciation and amortization			28		27		84		81
	Administrative and general			3		5		15		15

	Total operating expenses			294		303		906		840

Operating Income				150		69		198		256

Other Income				—		—		—		1

AOI			$	150	$	69	$	198	$	257

Statistics²
	Generation (in GWh)
		Energy contracts		8,449		8,272		22,091		20,389
		Load requirements services contract		—		—		—		1,333

	Total			8,449		8,272		22,091		21,722

	Aggregate plant performance
		Equivalent availability		91.7%		90.1%		79.4%		83.8%
		Capacity factor		70.0%		68.6%		61.7%		60.7%
		Load factor		76.4%		76.1%		77.8%		72.4%
		Forced outage rate		5.4%		5.3%		6.9%		6.0%
	Average realized price/MWh
		Energy contracts	$	42.09	$	38.74	$	40.99	$	42.11
		Load requirements services contract	$	—	$	—	$	—	$	62.52
	Capacity revenues only (in millions)		$	79	$	49	$	184	$	130
	Average realized fuel costs/MWh		$	18.08	$	19.57	$	17.41	$	18.82

¹: Included in fuel costs were $5 million and $19 million during the third quarters of 2010 and 2009, respectively, and $10 million and $52 million during the nine months ended September 30, 2010 and 2009, 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 to Midwest Generation were $0.4 million and $1 million during the nine months ended September 30, 2010 and 2009, respectively. Transfers of SO₂ emission allowances from Midwest Generation were $5 million during the first nine months of 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 "Non-GAAP Disclosures—Fossil-Fueled Facilities" and "Statistical Definitions."

AOI from the Midwest Generation plants increased $81 million for the third quarter ended September 30, 2010, compared to the corresponding period of 2009. The third quarter increase in AOI was primarily attributable to an increase in realized energy prices, a gain from the sale of the

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bankruptcy claims against Lehman, and higher capacity revenues, partially offset by unrealized losses in 2010 compared to unrealized gains in 2009. Average realized fuel costs were lower due to lower emission allowance costs.

During the third quarter of 2010, EME sold its claims against Lehman and recorded a gain of $24 million. The claims originated from power contracts that were terminated in 2008 due to the bankruptcy of Lehman. During 2008, EME dedesignated the contracts as cash flow hedges due to nonperformance risks and recorded unrealized losses of $24 million.

AOI from the Midwest Generation plants decreased $59 million for the nine months ended September 30, 2010, compared to the corresponding period of 2009. The 2010 decrease in AOI was primarily attributable to an increase in plant maintenance costs during the first half of 2010, lower realized energy prices and unrealized losses in 2010 compared to unrealized gains in 2009, partially offset by higher capacity revenues, a gain from the sale of the bankruptcy claims discussed above, and lower emission allowance costs. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Average realized fuel costs were lower in the nine months ended September 30, 2010 as compared to the same period in 2009 due to lower emission allowance costs partially offset by higher costs related to activated carbon, which is used to reduce mercury emissions.

Included in operating revenues were unrealized gains (losses) of $(16) million and $2 million for the third quarters of 2010 and 2009, respectively, and $(12) million and $22 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily due to economic hedge contracts that are accounted for on a mark-to-market basis.

Included in fuel costs were unrealized gains (losses) of $2 million and $(2) million for the third quarters of 2010 and 2009, respectively, and $(5) million and $12 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized gains (losses) were due to oil futures contracts which were accounted for as economic hedges related to a fuel adjustment mechanism of a rail transportation contract.

For more information regarding forward market prices and unrealized gains (losses), see "Market Risk Exposures—Commodity Price Risk" and "Results of Operations—Derivative Instruments," respectively.

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Homer City Facilities

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

		Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)		2010		2009		2010		2009

Operating Revenues		$	173	$	170	$	477	$	496
Operating Expenses
	Fuel¹		74		65		201		192
	Plant operations		20		22		96		78
	Plant operating leases		25		26		77		76
	Depreciation and amortization		5		4		14		12
	Administrative and general		1		1		4		3

	Total operating expenses		125		118		392		361

Operating Income			48		52		85		135

AOI		$	48	$	52	$	85	$	135

Statistics²
	Generation (in GWh)		2,984		2,994		8,227		8,677
	Equivalent availability		81.7%		92.7%		75.5%		86.8%
	Capacity factor		71.7%		71.8%		66.5%		70.1%
	Load factor		87.7%		77.5%		88.1%		80.8%
	Forced outage rate		15.8%		3.8%		13.5%		7.6%
	Average realized energy price/MWh	$	48.04	$	44.83	$	49.01	$	49.06
	Capacity revenues only (in millions)	$	28	$	30	$	86	$	60
	Average fuel costs/MWh	$	24.92	$	21.46	$	24.48	$	22.05

¹: Included in fuel costs were $1 million and $5 million during the third quarters of 2010 and 2009, and $6 million and $13 million during the nine months ended September 30, 2010 and 2009, 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 $5 million during the nine months ended September 30, 2010. Transfers of NO_x emission allowances from Homer City were $0.4 million and $1 million during the nine months ended September 30, 2010 and 2009, 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 "Non-GAAP Disclosures—Fossil-Fueled Facilities" and "Statistical Definitions."

AOI from the Homer City facilities decreased $4 million for the third quarter ended September 30, 2010, compared to the corresponding period of 2009. The third quarter decrease in AOI was primarily attributable to lower unrealized gains and higher coal costs, partially offset by higher average realized energy prices. Forced outages were higher in the third quarter of 2010 due to opacity-related deratings and unscheduled outages. Higher average fuel costs compared to 2009 were attributable to higher coal costs, partially offset by lower emission allowance costs.

AOI from the Homer City facilities decreased $50 million for the nine months ended September 30, 2010, compared to the corresponding period of 2009. The 2010 decrease in AOI was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009, an increase in plant operations costs related to scheduled plant outages, and lower realized energy revenues, partially offset by higher capacity revenues. The Homer City facilities experienced increased forced outages in 2010 compared to 2009 due to opacity-related deratings and unscheduled outages. Plant maintenance and

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overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Higher average fuel costs compared to 2009 were attributable to higher coal costs.

Included in operating revenues were unrealized gains (losses) from hedge activities of $1 million and $6 million for the third quarters of 2010 and 2009, respectively, and $(13) million and $11 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at the PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains (losses), see "Market Risk Exposures—Commodity Price Risk" and "Results of Operations—Derivative Instruments."

Non-GAAP Disclosures—Fossil-Fueled Facilities

Adjusted Operating Income

AOI is equal to operating income (loss) plus other income (expense) for the fossil-fueled facilities. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is meaningful for investors as the components of other income (expense) are integral to the operating results of the fossil-fueled facilities.

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Average Realized Energy Price

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

Midwest Generation Plants		Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)		2010			2009			2010			2009

Operating revenues		$	444		$	372		$	1,104		$	1,096
Less:
	Load requirements services contract		—			—			—			(83	)
	Unrealized (gains) losses		16			(2	)		12			(22	)
	Capacity and other revenues¹		(104	)		(49	)		(210	)		(132	)

Realized revenues		$	356		$	321		$	906		$	859

Generation—energy contracts (in GWh)			8,449			8,272			22,091			20,389
Average realized energy price/MWh		$	42.09		$	38.74		$	40.99		$	42.11

Homer City Facilities		Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)		2010			2009			2010			2009

Operating revenues		$	173		$	170		$	477		$	496
Less:
	Unrealized (gains) losses		(1	)		(6	)		13			(11	)
	Capacity and other revenues		(29	)		(29	)		(87	)		(59	)

Realized revenues		$	143		$	135		$	403		$	426

Generation (in GWh)			2,984			2,994			8,227			8,677
Average realized energy price/MWh		$	48.04		$	44.83		$	49.01		$	49.06

¹: A gain from the sale of the bankruptcy claims against Lehman is included in the three and nine months ended September 30, 2010.

The average realized energy price is presented as an aid in understanding the operating results of the fossil-fueled facilities. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is 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

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compared to real-time market prices. A reconciliation of the operating revenues of the fossil-fueled facilities to consolidated operating revenues presented in the preceding tables is set forth below:

		Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)		2010		2009		2010		2009

Operating revenues
	Midwest Generation plants	$	444	$	372	$	1,104	$	1,096
	Homer City facilities		173		170		477		496
	Renewable energy projects		29		26		93		101
	Other revenues		45		25		161		69

Consolidated operating revenues as reported		$	691	$	593	$	1,835	$	1,762

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 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 September 30,					Nine Months Ended September 30,

Midwest Generation Plants (in millions)		Three Months Ended September 30,					Nine Months Ended September 30,
Midwest Generation Plants (in millions)		2010		2009			2010			2009

Fuel costs		$	151	$	164		$	390		$	397
Add back:
	Unrealized gains (losses)		2		(2	)		(5	)		12

Realized fuel costs		$	153	$	162		$	385		$	409

Total generation (in GWh)			8,449		8,272			22,091			21,722
Average realized fuel costs/MWh		$	18.08	$	19.57		$	17.41		$	18.82

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 Midwest Generation plants fuel costs to consolidated fuel costs presented in the preceding table is set forth below:

		Three Months Ended September 30,					Nine Months Ended September 30,

(in millions)		2010		2009			2010		2009

Fuel costs
	Midwest Generation plants	$	151	$	164		$	390	$	397
	Homer City facilities		74		65			201		192
	Other		3		(1	)		11		(2	)

Consolidated fuel costs as reported		$	228	$	228		$	602	$	587

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Statistical Definitions

•: Load requirements services contract generation at the Midwest Generation plants represents a load requirements services contract with Commonwealth Edison, awarded as part of an Illinois auction. The contract commenced on January 1, 2007 and expired in May 2009. In 2010, load requirements services contracts at the Homer City facilities are included in energy generation.
•: The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.
•: The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
•: The load factor 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 North American Reliability Corporation (NERC). Examples include floods, tornado damage and transmission outages.
•: The average realized price for load requirements services contracts at the Midwest Generation plants reflects the contract price for sales to Commonwealth Edison under load requirements services contract that includes energy, capacity and ancillary services. It is determined by dividing (i) operating revenues related to the contracts by (ii) generation.

Seasonal Disclosure—Fossil-Fueled Facilities

Due to fluctuations in electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the fossil-fueled facilities 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, AOI from the fossil-fueled facilities 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 Fossil-Fueled Facilities."

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Renewable Energy Projects

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

			Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)			2010		2009		2010		2009

Operating Revenues			$	29	$	26	$	93	$	101
Production Tax Credits				12		10		45		40

				41		36		138		141

Operating Expenses
	Plant operations			11		12		35		38
	Depreciation and amortization			21		24		64		65
	Administrative and general			1		1		2		3

	Total operating expenses			33		37		101		106

Net Loss Attributable to Noncontrolling Interest				—		1		—		2

AOI¹			$	8	$	—	$	37	$	37

Statistics²
	Generation (in GWh)³			764		635		2,599		2,173
	Aggregate plant performance³
		Equivalent availability		91.3%		92.8%		91.2%		87.3%
		Capacity factor		27.7%		24.3%		31.8%		30.1%

¹: AOI is equal to operating income (loss) plus equity in earnings (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. The following table reconciles AOI as shown above to operating income (loss) under GAAP:

		Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)		2010			2009			2010			2009

AOI		$	8		$	—		$	37		$	37
Less:
	Production tax credits		12			10			45			40
	Net loss attributable to noncontrolling interest		—			1			—			2

Operating Loss		$	(4	)	$	(11	)	$	(8	)	$	(5	)

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 643 GWh and 2,156 GWh for the three months and nine months ended September 30, 2010, respectively.

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AOI from renewable energy projects increased $8 million for the third quarter ended September 30, 2010, compared to the corresponding periods of 2009. The third quarter increase in AOI was primarily attributable to higher generation resulting from an increase in projects in operation. AOI in the third quarter and nine months ended September 30, 2009 included $1 million and $17 million, respectively, of liquidated damages from availability guarantees provided by a wind turbine supplier, which compensated EME for lower generation (none recorded in 2010). During the nine months ended September 30, 2010, EME received $92 million in U.S. Treasury grants, which was recorded as deferred revenue and is recognized as revenue over the life of the project.

Energy Trading

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, 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.

AOI from energy trading activities increased $14 million and $65 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increases in AOI from energy trading activities were attributable to increased revenues in congestion and basis trading.

Adjusted Operating Income from Unconsolidated Affiliates

Doga

AOI from the Doga project increased $7 million for the nine months ended September 30, 2010, compared to the corresponding period of 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project since the Doga project is accounted for on the cost method.

March Point

AOI from the March Point project decreased $4 million and increased $10 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 year-to-date increase was primarily due to equity distributions received from the project. EME subsequently sold its ownership interest in the March Point project to its partner at book value.

Seasonal Disclosure

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.

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Interest Related Income (Expense)

		Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)		2010			2009			2010			2009

Interest income		$	—		$	—		$	2		$	6

Interest expense
	EME debt	$	(56	)	$	(68	)	$	(174	)	$	(204	)
	Non-recourse debt		(8	)		(10	)		(24	)		(21	)

		$	(64	)	$	(78	)	$	(198	)	$	(225	)

The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities, partially offset by higher wind project financing. Capitalized interest for projects under construction increased $14 million and $27 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009.

Income Taxes

EME's income taxes from continuing operations for the nine months ended September 30, 2010 included a $16 million income tax benefit resulting from the California Franchise Tax Board's acceptance and application of the federal settlement of tax disputes finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002. In addition, income taxes for the nine months ended September 30, 2010 and 2009, included tax benefits of production tax credits of $45 million and $40 million, respectively.

For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Income Taxes."

Results of Discontinued Operations

Income from discontinued operations, net of tax, decreased $4 million and increased $9 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009. The third quarter decrease was due to higher foreign exchange rates. The year-to-date increase was due to lower foreign exchange rates, adjustments to unrecognized tax benefits, and a reduction in EME's estimated liability due primarily to expiration of a contract indemnity during the first quarter of 2010. EME increased its estimated liability for a tax indemnity by $6 million in the nine months ended September 30, 2009.

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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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 results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:

		Three Months Ended September 30,						Nine Months Ended September 30,

(in millions)		2010			2009			2010			2009

Midwest Generation plants
	Non-qualifying hedges	$	(12	)	$	(4	)	$	(18	)	$	30
	Ineffective portion of cash flow hedges		(2	)		4			1			4
Homer City facilities
	Non-qualifying hedges		—			—			—			—
	Ineffective portion of cash flow hedges		1			6			(13	)		11

Total unrealized gains (losses)		$	(13	)	$	6		$	(30	)	$	45

At September 30, 2010, cumulative unrealized gains of $12 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($4 million for the remainder of 2010, $7 million for 2011, and $1 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 2. Fair Value Measurements" and "—Note 3. Derivative Instruments and Risk Management," respectively, and refer to "Fair Value of Derivative Instruments" in Item 7 on page 69 of EME's annual report on Form 10-K for the year ended December 31, 2009.

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

Overview

At September 30, 2010, EME and its subsidiaries had consolidated cash and cash equivalents of $1.1 billion and a total of $960 million of available borrowing capacity under their credit facilities. EME's consolidated debt at September 30, 2010 was $4.2 billion, of which $141 million was current. In addition, EME's subsidiaries had $3.0 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 24 years.

The following table summarizes the status of the EME and Midwest Generation credit facilities at September 30, 2010:

(in millions)	EME			Midwest Generation


Commitment	$	600		$	500
Less: Commitment from Lehman Commercial Paper Inc.		(36	)		—

		564			500
Outstanding letters of credit		(101	)		(3	)

Amount available	$	463		$	497

As a result of credit ratings actions in 2010, the margins applicable to Midwest Generation's $500 million working capital facility increased 27.5 basis points. Borrowings made under this credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%.

Expenditures for NO_x and SO₂ controls through 2012 (estimated at $315 million), are anticipated to be funded through operating cash flow and available credit facilities. EME has not yet committed to the completion of environmental compliance activities for all the Midwest Generation plants. Depending upon the facilities selected to be retrofit and the timing of funding requirements beyond the near term, EME may utilize operating cash flow or seek debt financing to fund capital expenditures.

(in millions)


Secured project financings
	Big Sky¹	$	138
	Cedro Hill¹		57
	Laredo Ridge¹		59
Anticipated U.S. Treasury grants²			340

		$	594

¹: Remaining available balance at September 30, 2010.
²: Anticipated U.S. Treasury grants are based on estimated costs at completion of construction for renewable projects scheduled to be completed in 2011. The anticipated grants have been reduced by a bridge loan on the Laredo Ridge project that is due when the related grants funds are received. Funding sources in excess of the forecast capital expenditures are planned to be used for general corporate purposes.

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EME may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Small Business Jobs Act of 2010

In September 2010, the Small Business Jobs Act of 2010 extended the 50% bonus depreciation provision for an additional year to include property purchased and placed into service by December 31, 2010. EME expects that certain capital expenditures incurred during 2010 will qualify for the accelerated bonus depreciation, which would provide additional cash flow benefits, primarily in 2011, estimated to be in the range of approximately $70 million to $100 million.

Capital Investment Plan

At September 30, 2010, forecasted capital expenditures through 2012 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		October through December 2010		2011		2012


Midwest Generation Plants
	Plant capital expenditures	$	18	$	38	$	22
	Environmental expenditures¹		32		151		132
Homer City Facilities
	Plant capital expenditures		4		18		25
	Environmental expenditures²		—		—		—
Renewable Projects
	Capital and construction expenditures³		217		212		—
	Turbine commitments⁴		—		82		—
Other capital expenditures			6		18		19

Total		$	277	$	519	$	198

¹: Environmental expenditures include primarily expenditures related to selective non-catalytic reduction (SNCR) equipment and $174 million for expenditures during the remainder of 2010 to 2012 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. For additional discussion, see "Management's Overview—Environmental Developments," and refer to "Environmental Matters and Regulations" in Item 1 on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2009.
²: Excludes amounts that may become required under environmental regulations for future operations. For further information, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies—Contingencies—Environmental Developments—Transport Rule" and "—Contingencies—Homer City New Source Review Notice of Violation."
³: Amounts include an unconsolidated project in which construction expenditures will be substantially funded by EME. Amounts also include projects under construction where project financing has been secured. The available balance under secured financing arrangements was $254 million as of September 30, 2010. For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies—Contractual Obligations—Project Financing," and refer to "Project-Level Financing" in Item 7 on page 74 of EME's annual report on Form 10-K for the year ended December 31, 2009.

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⁴: Amounts exclude balance of project costs for the 75 MW available for new projects, which EME estimates to be an additional $50 million to $90 million based on typical project costs. Turbine commitment figures include the impact of the October 8, 2010 Mitsubishi settlement agreement. For additional discussion, see "Legal Proceedings" in Part II of this quarterly report.

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

Midwest Generation is subject to various commitments with respect to environmental compliance. Expenditures, in addition to those included on the preceding table, are anticipated and could be material; however, the amounts and timing have not been determined. For more information on the current status of environmental improvements in Illinois, see "Management's Overview—Environmental Developments." For further discussion of environmental regulations, refer to "Environmental Matters and Regulations" in Item 1 on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2009.

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

	Nine Months Ended September 30,

(in millions)	2010			2009

Operating cash flow from continuing operations	$	588		$	87
Operating cash flow from discontinued operations		4			(5	)

Net cash provided by operating activities		592			82
Net cash provided by (used in) financing activities		172			(236	)
Net cash used in investing activities		(463	)		(445	)

Net increase (decrease) in cash and cash equivalents	$	301		$	(599	)

Consolidated Cash Flows from Operating Activities

Cash provided by operating activities from continuing operations increased $501 million in the first nine months of 2010, compared to the first nine months of 2009. The 2010 increase was primarily attributable to changes in income tax liabilities and derivative-related activities.

Consolidated Cash Flows from Financing Activities

Cash provided by financing activities from continuing operations increased $408 million in the first nine months of 2010, compared to the first nine months of 2009. In 2010, financing activities included project-level wind financing. Financing activities in 2009 included wind project financings and the repayment of $188 million and $200 million under EME's corporate credit facility and Midwest Generation's working capital facility, respectively. For further project financing details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies—Contractual Obligations—Project Financing."

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Consolidated Cash Flows from Investing Activities

Cash used in investing activities from continuing operations increased $18 million in the first nine months of 2010, compared to the first nine months of 2009. The 2010 increase was primarily due to capital expenditures for the construction of wind projects. In 2009, investments in other assets include wind turbine deposits.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of September 30, 2010 are 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.

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. For discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."

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 facilities through EMMT, refer to "Credit Rating of EMMT" in Item 7 on page 78 of EME's annual report on Form 10-K for the year ended December 31, 2009.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

Future cash collateral requirements may be higher than the margin and collateral requirements were at September 30, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of September 30, 2010 could increase by approximately $129 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with

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the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings."

Hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. EMMT has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at September 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

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

EME's Liquidity as a Holding Company

At September 30, 2010, EME had cash and cash equivalents of $596 million to meet liquidity needs as well as $463 million of capacity under its credit facility. EME's cash and cash equivalents included $281 million held directly by EME, as well as cash and cash equivalents related to EMMT of $315 million (which can be loaned or distributed to EME, subject to applicable corporate and other laws). Because EME, as a holding company, does not directly own any revenue-producing generation facilities, EME relies on cash distributions and tax payments from its projects to pay debt service, tax payments, contractual obligations and general and administrative expenses. Distributions to EME from projects are generally only available after all current debt service obligations at the project level have been paid and are further restricted by contractual restrictions on distributions included in the documentation evidencing the project-level debt obligations. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. For further discussion, see "—Dividend Restrictions in Major Financings."

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.

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

			12 Months Ended

(in millions)			September 30, 2010			December 31, 2009

Funds Flow Available for Interest
	Distributions
		Midwest Generation	$	165		$	200
		Homer City		59			75
		Big 4 Projects		71			62
		U.S. Treasury grants		92			—
		Renewables¹		162			208
		Other projects		77			47
	Tax payments received from subsidiaries			23			68
	Realized trading income			116			36
	Tax allocation receipts (payments)			84			139
	Operating expenses			(146	)		(151	)
	Other items, net			(43	)		(14	)

			$	660		$	670

Net Interest Expense
	EME corporate debt		$	230		$	261
	Addback: Capitalized interest			45			19
	Powerton-Joliet intercompany notes			112			112
	EME interest income			—			(2	)

			$	387		$	390

Ratio				1.71			1.72
Covenant threshold (not less than)				1.20			1.20

¹: The 2009 amount includes Viento Funding II, Inc. proceeds of $167 million for the wind financing, net of financing costs, distributed to EME in 2009.

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

(in millions)			September 30, 2010			December 31, 2009


Corporate Debt
	Indebtedness for money borrowed		$	3,700		$	3,700
	Powerton-Joliet termination value			919			1,046
	Letters of credit			104			104

			$	4,723		$	4,850

Corporate Capital
	Common shareholder's equity		$	2,926		$	2,761
	Less:
		Non-cash cumulative changes in accounting		(9	)		1
		Accumulated other comprehensive income		(59	)		(78	)
	Adjustments:
		After-tax losses incurred on termination of Collins lease		587			587
		Dividend to Mission Energy Holding Company for repayment of 13.5% notes		899			899

				4,344			4,170

	Corporate debt			4,723			4,850

			$	9,067		$	9,020

Corporate-debt-to-capital ratio				0.52			0.54
Covenant threshold (not more than)				0.75			0.75

Dividend Restrictions in Major Financings

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 September 30, 2010 or for the 12 months ended September 30, 2010:

Subsidiary	Financial Ratio	Covenant	Actual


Midwest Generation (Midwest Generation plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.15 to 1
Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.81 to 1

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" in Item 7 on page 82 of EME's annual report on Form 10-K for the year ended December 31, 2009.

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

EME is restricted under applicable agreements from the sale or disposition 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

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computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At September 30, 2010, the maximum permissible sale or disposition of EME assets is determined as follows:

(in millions)


Consolidated Net Tangible Assets
	Total consolidated assets		$	9,082
	Less:
		Consolidated current liabilities		659
		Intangible assets		85

			$	8,338

10% Threshold			$	834

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

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

Contractual Obligations and Contingencies

Fuel Supply and Transportation Contracts

For a discussion of fuel supply contracts and coal transportation agreements, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies—Commitments—Fuel Supply and Transportation 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 10. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."

Homer City New Source Review Notice of Violation

For a discussion of the Homer City New Source Review Notice of Violation, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation."

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 86 of EME's annual report on Form 10-K for the year ended December 31, 2009.

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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 20 of EME's annual report on Form 10-K for the year ended December 31, 2009. 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. Commitments and Contingencies—Contingencies—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 90 of EME's annual report on Form 10-K for the year ended December 31, 2009.

Commodity Price Risk

Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities

Energy and capacity from the fossil-fueled facilities 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 or the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City facilities. These trading hubs have been the most liquid locations for hedging purposes.

The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first nine months of 2010 and 2009:

		24-Hour Average Historical Market Prices¹

		2010		2009

Midwest Generation plants
	Northern Illinois Hub	$	35.02	$	28.62
Homer City facilities
	PJM West Hub	$	46.65	$	38.65
	Homer City Busbar		39.80		35.16

¹: Energy prices were calculated at the respective delivery points 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 September 30, 2010:

		24-Hour Forward Energy Prices¹

		Northern Illinois Hub		PJM West Hub

2010
	October	$	23.93	$	36.81
	November		25.76		36.36
	December		28.84		39.70
2011 calendar "strip"²		$	29.86	$	41.06
2012 calendar "strip"²		$	31.89	$	43.10

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.

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Forward prices for the 2011 calendar strip indicated on the preceding table have decreased from December 31, 2009 prices of $34.73 and $49.43 for the Northern Illinois Hub and the PJM West Hub, respectively.

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 fossil-fueled facilities into these markets may vary materially from the forward market prices set forth in the preceding table.

EMMT engages in hedging activities for the fossil-fueled facilities to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) as of September 30, 2010 for electricity expected to be generated during the remainder of 2010 and in 2011 and 2012:

		2010				2011				2012

		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		5,341	$	41.94		13,318	$	37.66		2,746	$	37.29
Homer City facilities^2, ³
	PJM West Hub		1,536		65.21		3,475		51.05		1,182		51.81

Total			6,877				16,793				3,928

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 2010, 2011 and 2012 include hedging activities entered into by EMMT for the Homer City facilities 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 25 to 84 MW for periods ranging from October 1, 2010 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

In addition, as of September 30, 2010, EMMT had entered into 0.6 bcf of natural gas futures contracts (equivalent to approximately 102 GWh of energy contracts using a ratio of 6 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks during 2010 at an equivalent average energy price of approximately $38.40/MWh.

The decline in 2010 market prices will impact realized energy and hedge prices in 2011 and 2012 and could have a material impact on 2011 and 2012 results.

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Through October 25, 2010, offsetting positions were entered into to reduce the hedge position of EME's merchant operations. The reduction in the hedge position was:

•: Midwest Generation: 2,448 MWh (in thousands) with an average price of $37.12/MWh, and
•: Homer City: 2,244 MWh (in thousands) with an average price of $47.30/MWh.

Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at September 30, 2010:

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

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

October 1, 2010 to May 31, 2011 Midwest Generation			5,477		(548	)		4,929		4,929	$	174.29		—			—	$	174.29
	Homer City		1,884		(261	)		1,623		1,813		174.29		(190	)	$	53.95		188.38
June 1, 2011 to May 31, 2012 Midwest Generation			5,477		(495	)		4,982		4,582		110.00		400			85.00		107.99
	Homer City		1,884		(113	)		1,771		1,771		110.00		—			—		110.00
June 1, 2012 to May 31, 2013 Midwest Generation			5,477		(773	)		4,704		4,704		16.46		—			—		16.46
	Homer City		1,884		(232	)		1,652		1,736		133.37		(84	)		16.46		139.31
June 1, 2013 to May 31, 2014 Midwest Generation			5,477		(827	)		4,650		4,650		27.73		—			—		27.73
	Homer City		1,884		(104	)		1,780		1,780		226.15		—			—		221.03	⁴

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 25 to 84 MW of capacity for periods ranging from October 1, 2010 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.
³: Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.
⁴: Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 MW-day.

The RPM auction capacity prices for the delivery periods 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 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, which is uncertain.

Basis Risk

During the nine months ended September 30, 2010, transmission congestion in PJM has resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 10% and 1%, respectively, compared to 15% and less than 1%, respectively, during the nine months ended September 30, 2009. During the nine

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months ended September 30, 2010 and 2009, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 15% and 9%, respectively.

Coal and Transportation Price Risk

The Midwest Generation plants and Homer City facilities 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 September 30, 2010 for the remainder of 2010 and the following three years:

	Amount of Coal Under Contract in Millions of Equivalent Tons¹


	October through December 2010		2011		2012		2013

Midwest Generation plants		5.4		15.6		9.8		—
Homer City facilities		1.4		4.4		1.9		0.5

¹: The amount of coal under contract in 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 facilities.

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 facilities, increased during 2010 from 2009 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 $69.50 per ton at October 1, 2010, compared to a price of $52.50 per ton at December 31, 2009, 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 increased during 2010 from 2009 year-end prices. The market price of PRB coal increased to a price of $14.75 per ton at October 1, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the Energy Information Administration.

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

Emission Allowances Price Risk

EME purchases (or sells) emission allowances for the fossil-fueled facilities based on the amounts required for actual generation in excess of (or less than) the amounts allocated to these facilities under applicable programs. In the event that actual emission allowances 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 $49 per ton during the nine months ended September 30, 2010 from $65 per ton in 2009. The average purchase price of annual NO_x allowances decreased to $936 per ton during the nine months ended

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September 30, 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_x allowances was $10.50 per ton and $335 per ton, respectively, at September 30, 2010.

For a discussion of environmental regulations related to emissions, refer to "Environmental Matters and Regulations" in Item 1 on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2009.

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 September 30, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

		September 30, 2010

(in millions)		Exposure²		Collateral			Net Exposure

Credit Rating¹
	A or higher	$	176	$	(18	)	$	158
	A-		21		—			21
	BBB+		5		—			5
	BBB		24		—			24
	BBB-		27		7			34
	Below investment grade		99		(97	)		2

Total		$	352	$	(108	)	$	244

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

The credit risk exposure set forth in the above table is comprised of $128 million of net accounts receivable and payables and $224 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted an $89 million cash margin in the aggregate with PJM, New York Independent System Operator (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 fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 68% of EME's consolidated operating revenues for the nine months ended September 30, 2010. Moody's rates PJM's debt Aa3. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are

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shared by all other members using a predetermined formula. At September 30, 2010, EME's account receivable due from PJM was $52 million.

The terms of EME's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines, and payments for delays in delivery and for failure to meet performance obligations and warranty agreements. EME's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to 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 10. Commitments and Contingencies—Contractual Obligations—Project Financing." The fair market values of fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated construction loans and long-term obligations (including current portion) was $3.3 billion at September 30, 2010, compared to the carrying value of $4.2 billion.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of EME's critical accounting policies, refer to "Critical Accounting Policies and Estimates" in Item 7 on page 99 of EME's annual report on Form 10-K for the year ended December 31, 2009.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Fair Value of Derivative Instruments" on page 69 and "Market Risk Exposures" on page 90 in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2009. For an update to that disclosure, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Derivative Instruments—Fair Value Disclosures" and "—Market Risk Exposures."

ITEM 4T. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

There were no changes in EME's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For a discussion of EME's legal proceedings, refer to "Item 3. Legal Proceedings" on page 42 of EME's annual report on Form 10-K for the year ended December 31, 2009. 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, 2009, except as follows:

Midwest Generation New Source Review Lawsuit

Recent Developments

In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.

Homer City New Source Review Notice of Violation

Recent Developments

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Mitsubishi Lawsuit

EME and Mitsubishi Power Systems Americas, Inc. are parties to a wind turbine generator supply agreement executed in March 2007 with respect to the purchase of 166 wind turbines and related services and warranties. Mitsubishi has delivered 83 wind turbines under the agreement. As a result of a dispute between the parties, EME filed a complaint on March 19, 2010, and an amended complaint on April 1, 2010, in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd with respect to the agreement. The Mitsubishi entities filed counterclaims, including claims for the unpaid purchase price for the remaining turbines.

On October 8, 2010, EME and the Mitsubishi entities entered into a settlement agreement with respect to the dispute. As a result of the settlement agreement, EME's $68 million deposit previously paid under the original contract will be applied to the purchase price for 23 wind turbines (55 MW). Within the next three years, EME may elect to deploy 60 additional wind turbines (144 MW). EME may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. EME further agreed to payments up to $40 million for settlement of remaining disputes on turbines purchased.

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 32 of EME's annual report on Form 10-K for the year ended December 31, 2009. The risks described in EME's annual report on Form 10-K and in this report are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.

ITEM 6. EXHIBITS

Exhibit No.			Description


	31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
	31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
	32		Statement Pursuant to 18 U.S.C. Section 1350.
	101		Financial statements from the quarterly report on Form 10-Q of Edison Mission Energy for the quarter ended September 30, 2010, filed on October 29, 2010, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

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SIGNATURES

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


		EDISON MISSION ENERGY
		By:		/s/ John P. Finneran, Jr. John P. Finneran, Jr. Senior Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)
		Date:		October 29, 2010