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 June 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 August 5, 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 (LOSS)				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			15
		Contingent Features/Credit Related Exposure			15
		Margin and Collateral Deposits			16
	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
	Note 10. Commitments and Contingencies				22
		Contractual Obligations			22
			Project Financing		22
			Long-Term Debt		23

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		Commitments			23
			Capital Improvements		23
			Turbine Commitments		23
			Fuel Supply and Transportation Contracts		24
			Letters of Credit		24
		Guarantees and Indemnities			24
			Environmental Indemnities Related to the Midwest Generation Plants		24
			Environmental Indemnity Related to the Homer City Facilities		25
			Indemnities Provided under Asset Sale and Sale-Leaseback Agreements		25
		Contingencies			26
			Midwest Generation New Source Review Lawsuit		26
				Recent Developments	26
				Background	26
			Homer City New Source Review Notice of Violation		27
				Recent Developments	27
				Background	27
			Environmental Remediation		28
			Environmental Developments		29
				Midwest Generation Environmental Compliance Plans and Costs	29
				Homer City Environmental Issues and Capital Resource Limitations	29
				Climate Change	30
				Transport Rule	30
				National Ambient Air Quality Standard for Sulfur Dioxide	30
				Hazardous Substances and Hazardous Waste Laws	31
	Note 11. Supplemental Cash Flows Information				31
	Note 12. Subsequent Event				31
		Laredo Ridge			31
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS					32
	MANAGEMENT'S OVERVIEW				33
	Introduction				33
	Highlights of Operating Results				34
	Environmental Developments				35
		Midwest Generation Environmental Compliance Plans and Costs			35
		US EPA Developments			36
	EME's Renewable Program				37
		Mitsubishi Lawsuit			37
	EME's Liquidity				37
	RESULTS OF OPERATIONS				38
	Results of Continuing Operations				38
		Overview			38
		Adjusted Operating Income from Consolidated Operations			40
			Midwest Generation Plants		40
			Homer City Facilities		42
			Non-GAAP Disclosures—Fossil-Fueled Facilities		43
				Adjusted Operating Income	43

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			Average Realized Energy Price	43
			Average Realized Fuel Costs	44
		Statistical Definitions		45
		Seasonal Disclosure—Fossil-Fueled Facilities		45
		Renewable Energy Projects		46
		Energy Trading		47
	Adjusted Operating Income from Unconsolidated Affiliates			47
		Doga		47
		March Point		47
		Seasonal Disclosure		47
	Interest Related Income (Expense)			48
	Income Taxes			48
Results of Discontinued Operations				48
New Accounting Guidance				48
Derivative Instruments				48
	Unrealized Gains and Losses			48
	Fair Value Disclosures			49
LIQUIDITY AND CAPITAL RESOURCES				50
Available Liquidity				50
Capital Investment Plan				51
	Estimated Expenditures for Existing Projects			51
	Estimated Expenditures for Future Projects			52
EME's Historical Consolidated Cash Flow				52
	Condensed Consolidated Statement of Cash Flows			52
		Consolidated Cash Flows from Operating Activities		52
		Consolidated Cash Flows from Financing Activities		52
		Consolidated Cash Flows from Investing Activities		53
Credit Ratings				53
	Overview			53
	Credit Rating of EMMT			53
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts			53
EME's Liquidity as a Holding Company				54
	EME's Credit Facility Financial Ratios			54
		Corporate-Debt-to-Capital Ratio		56
Dividend Restrictions in Major Financings				56
	Key Ratios of EME's Principal Subsidiaries Affecting Dividends			56
	EME's Senior Notes and Guaranty of Powerton-Joliet Leases			57
Contractual Obligations and Contingencies				57
	Fuel Supply and Transportation Contracts			57
	Midwest Generation New Source Review Lawsuit			57
	Homer City New Source Review Notice of Violation			57
Off-Balance Sheet Transactions				58
Environmental Matters and Regulations				58
MARKET RISK EXPOSURES				59

iii

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	Commodity Price Risk		59
		Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities	59
		Capacity Price Risk	61
		Basis Risk	61
		Coal and Transportation Price Risk	62
		Emission Allowances Price Risk	62
	Credit Risk		63
	Interest Rate Risk		64
	CRITICAL ACCOUNTING ESTIMATES AND POLICIES		64
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			64
ITEM 4T. CONTROLS AND PROCEDURES			64
	Disclosure Controls and Procedures		64
	Internal Control Over Financial Reporting		64
PART II – OTHER INFORMATION			65
ITEM 1. LEGAL PROCEEDINGS			65
	Midwest Generation New Source Review Lawsuit		65
		Recent Developments	65
	Homer City New Source Review Notice of Violation		65
		Recent Developments	65
	Mitsubishi Lawsuit		66
ITEM 1A. RISK FACTORS			66
ITEM 6. EXHIBITS			66
SIGNATURES			67

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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)
BACT		best available control technology
bcf		billion cubic feet
Big 4		Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu		British thermal units
CAA		Clean Air Act
Commonwealth Edison		Commonwealth Edison Company
CPS		Combined Pollutant Standard
EME		Edison Mission Energy
Homer City		EME Homer City Generation L.P.
EMMT		Edison Mission Marketing & Trading, Inc.
FASB		Financial Accounting Standards Board
FGD		flue gas desulfurization
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
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
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
RPM		Reliability Pricing Model
S&P		Standard & Poor's Ratings Services
SNCR		selective non-catalytic reduction
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 (LOSS) (in millions, unaudited)
			Three Months Ended June 30,						Six Months Ended June 30,
			2010			2009			2010			2009

Operating Revenues			$	493		$	557		$	1,144		$	1,169
Operating Expenses
	Fuel			161			172			374			359
	Plant operations			229			146			388			296
	Plant operating leases			45			44			89			88
	Depreciation and amortization			60			56			119			112
	Administrative and general			44			51			90			95

		Total operating expenses		539			469			1,060			950

	Operating income (loss)			(46	)		88			84			219

Other Income (Expense)
	Equity in income from unconsolidated affiliates			20			21			39			28
	Dividend income			1			9			17			10
	Interest income			1			3			2			6
	Interest expense			(66	)		(73	)		(134	)		(147	)

		Total other expense		(44	)		(40	)		(76	)		(103	)

	Income (loss) from continuing operations before income taxes			(90	)		48			8			116
	Provision (benefit) for income taxes			(70	)		2			(47	)		17

Income (Loss) from Continuing Operations				(20	)		46			55			99
Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 5)				3			(7	)		9			(4	)

Net Income (Loss)				(17	)		39			64			95

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

Net Income (Loss) Attributable to EME Common Shareholders			$	(17	)	$	40		$	64		$	96

Amounts Attributable to EME Common Shareholders
Income (loss) from continuing operations, net of tax			$	(20	)	$	47		$	55		$	100
Income (loss) from discontinued operations, net of tax				3			(7	)		9			(4	)

Net Income (Loss) Attributable to EME Common Shareholders			$	(17	)	$	40		$	64		$	96

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

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EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in millions, unaudited)
			Three Months Ended June 30,						Six Months Ended June 30,
			2010			2009			2010			2009

Net Income (Loss)			$	(17	)	$	39		$	64		$	95
Other comprehensive income (loss), net of tax
	Pension and postretirement benefits other than pensions:
		Amortization of net loss and prior service adjustment included in expense, net of tax		—			1			—			1
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(50) and $(50) for the three months and $12 and $48 for the six months ended June 30, 2010 and 2009, respectively		(77	)		(90	)		18			61
		Reclassification adjustments included in net income, net of income tax expense (benefit) of $(35) and $9 for the three months and $(49) and $(23) for the six months ended June 30, 2010 and 2009, respectively		(53	)		17			(73	)		(32	)

Other comprehensive income (loss)				(130	)		(72	)		(55	)		30

Comprehensive Income (Loss)				(147	)		(33	)		9			125

Comprehensive Loss Attributable to Noncontrolling Interests				—			1			—			1

Comprehensive Income (Loss) Attributable to EME Common Shareholders			$	(147	)	$	(32	)	$	9		$	126

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

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EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS (in millions, unaudited)
			June 30, 2010		December 31, 2009

Assets
Current Assets
	Cash and cash equivalents		$	707	$	796
	Accounts receivable—trade			151		201
	Receivables from affiliates			92		93
	Inventory			234		196
	Derivative assets			146		197
	Restricted cash			25		69
	Margin and collateral deposits			108		120
	Prepaid expenses and other			50		190

		Total current assets		1,513		1,862

Investments in Unconsolidated Affiliates				508		361

Property, Plant and Equipment				6,670		6,279
	Less accumulated depreciation and amortization			1,629		1,474

		Net property, plant and equipment		5,041		4,805

Other Assets
	Deferred financing costs			50		43
	Long-term derivative assets			79		81
	Restricted deposits			42		40
	Rent payments in excess of levelized rent expense under plant operating leases			1,149		1,038
	Other long-term assets			259		403

		Total other assets		1,579		1,605

Total Assets			$	8,641	$	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)
			June 30, 2010		December 31, 2009

Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	100	$	97
	Payables to affiliates			5		14
	Accrued liabilities			162		247
	Derivative liabilities			—		5
	Interest payable			30		30
	Deferred taxes			91		119
	Current maturities of long-term obligations			42		37
	Construction loan			65		—

		Total current liabilities		495		549

Long-term obligations net of current maturities				3,979		3,929
Deferred taxes and tax credits				714		672
Deferred revenues				163		153
Long-term derivative liabilities				23		15
Other long-term liabilities				486		478

Total Liabilities				5,860		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 June 30, 2010 and December 31, 2009			64		64
	Additional paid-in capital			1,337		1,339
	Retained earnings			1,352		1,280
	Accumulated other comprehensive income			23		78

		Total EME common shareholder's equity		2,776		2,761

Noncontrolling Interests				5		76

Total Equity				2,781		2,837

Total Liabilities and Equity			$	8,641	$	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)
			Six Months Ended June 30,
			2010			2009

Cash Flows From Operating Activities
	Net income		$	64		$	95
	(Income) loss from discontinued operations			(9	)		4

	Income from continuing operations, net			55			99
	Adjustments to reconcile income to net cash provided by (used in) operating activities:
		Equity in income from unconsolidated affiliates		(37	)		(26	)
		Distributions from unconsolidated affiliates		39			21
		Depreciation and amortization		125			115
		Deferred taxes and tax credits		53			209
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		12			(12	)
		Decrease (increase) in accounts receivables		53			(127	)
		Increase in inventory		(34	)		(31	)
		Decrease in prepaid expenses and other		7			36
		Decrease (increase) in restricted cash		43			(188	)
		Increase in rent payments in excess of levelized rent expense		(111	)		(113	)
		Decrease in accounts payable and other current liabilities		(121	)		(144	)
		Increase in derivative assets and liabilities		(35	)		(1	)
		Proceeds from U.S. Treasury grants		92			—
		Other operating—assets		8			(1	)
		Other operating—liabilities		10			72

	Operating cash flow from continuing operations			159			(91	)
	Operating cash flow from discontinued operations			9			(4	)

		Net cash provided by (used in) operating activities		168			(95	)

Cash Flows From Financing Activities
	Borrowings on long-term debt			7			189
	Payments on long-term debt agreements			(23	)		(43	)
	Borrowings under construction loan			65			—
	Payments to affiliates related to stock-based awards			(2	)		(1	)
	Financing costs			(10	)		(13	)

		Net cash provided by financing activities		37			132

Cash Flows From Investing Activities
	Capital expenditures			(313	)		(138	)
	Proceeds from return of capital and loan repayments and sale of assets			27			11
	Purchase of interest of acquired companies			(4	)		(7	)
	Maturities of short-term investments			1			2
	Increase in restricted cash			—			(1	)
	Investments in other assets			(5	)		(55	)

		Net cash used in investing activities		(294	)		(188	)

Net decrease in cash and cash equivalents				(89	)		(151	)
Cash and cash equivalents at beginning of period				796			1,807

Cash and cash equivalents at end of period			$	707		$	1,656

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

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EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 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 six months ended June 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)	June 30, 2010		December 31, 2009


Cash	$	212	$	106
Money market funds		495		690

Total cash and cash equivalents	$	707	$	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)	June 30, 2010		December 31, 2009


Coal, fuel oil and other raw materials	$	166	$	132
Spare parts, materials and supplies		68		64

Total	$	234	$	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 $3 million at June 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 June 30, 2010

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

Assets at Fair Value
	Money market funds¹		$	521		$	—		$	—		$	—		$	521

	Derivatives
		Electricity	$	—		$	142		$	171		$	(88	)	$	225
		Natural gas		2			—			—			(2	)		—
		Fuel oil		8			—			—			(8	)		—

		Total commodity contracts		10			142			171			(98	)		225

	Total derivatives		$	10		$	142		$	171		$	(98	)	$	225

Liabilities at Fair Value
	Derivatives
		Electricity	$	—		$	(68	)	$	(5	)	$	69		$	(4	)
		Natural gas		(1	)		(2	)		—			1			(2	)

		Total commodity contracts		(1	)		(70	)		(5	)		70			(6	)
		Interest rate contracts		—			(17	)		—			—			(17	)

	Total derivatives		$	(1	)	$	(87	)	$	(5	)	$	70		$	(23	)

			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 June 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 June 30,									Six Months Ended June 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		$	199		$	267		$	2		$	173		$	213		$	3
Total realized/unrealized gains (losses)
	Included in earnings¹		(18	)		(49	)		—			27			97			—
	Included in accumulated other comprehensive income (loss)		(2	)		—			—			4			—			—
Purchases and settlements, net			(19	)		30			(1	)		(43	)		(58	)		(2	)
Transfers in or out of Level 3			6			(8	)		—			5			(12	)		—

Fair value at June 30		$	166		$	240		$	1		$	166		$	240		$	1

Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at June 30¹		$	(2	)	$	13		$	—		$	32		$	71		$	—

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

EME determines the fair value of transfers in and transfers out of each level at the end of each reporting period. Level 1 had no transfers in and out during the second quarters and six months ended June 30, 2010 and 2009. Transfers in and out of Level 2 were not significant during the second quarters and six months ended June 30, 2010 and 2009.

Long-term Obligations

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

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

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

Long-term obligations, including current portion	$	4,021	$	2,732	$	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 value of trade receivables, payables and construction loan 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 (loss). 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 (loss).

Notional Volumes of Derivative Instruments

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

June 30, 2010

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

Electricity	Forwards/Futures	Sales	GWh		29,884	¹		19,257	³		33,785
Electricity	Forwards/Futures	Purchases	GWh		408	¹		18,698	³		36,700
Electricity	Capacity	Sales	MW-Day (in thousands)		183	²		—			218	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		17	²		—			557	²
Electricity	Congestion	Sales	GWh		—			136	⁴		8,964	⁴
Electricity	Congestion	Purchases	GWh		—			1,362	⁴		195,038	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			1.5			45.0
Natural gas	Forwards/Futures	Purchases	bcf		—			—			47.9
Fuel oil	Forwards/Futures	Sales	barrels		—			120,000			319,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			495,000			329,000
Coal	Forwards/Futures	Sales	tons		—			—			1,095,000
Coal	Forwards/Futures	Purchases	tons		—			—			465,000

(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	$	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

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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 (in thousands)		11	²		2	²		736	²
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:

June 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	$	153		$	14		$	167		$	39		$	43		$	82		$	85
	Economic hedges		111			3			114			93			2			95			19
Trading activities			237			121			358			182			50			232			126

			501			138			639			314			95			409			230
Netting and collateral received¹			(355	)		(59	)		(414	)		(314	)		(72	)		(386	)		(28	)

Total		$	146		$	79		$	225		$	—		$	23		$	23		$	202

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.

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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 Six Months Ended June 30,

	Cash Flow Hedge Activity¹ Six Months Ended June 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		30			109
Reclassification from accumulated other comprehensive income to net income		(122	)		(55	)	Operating revenues

Accumulated other comprehensive income derivative gain at June 30	$	83		$	452

¹: Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at June 30, 2010 and 2009 were $50 million and $269 million, respectively.

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 (loss) of $(7) million and $5 million during the second quarters of 2010 and 2009, respectively, and $1 million and $5 million during the six months ended June 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 (loss).

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

		Three Months Ended June 30,					Six Months Ended June 30,

	Income Statement Location	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	Income Statement Location	2010			2009		2010			2009

Economic hedges	Operating revenue	$	(3	)	$	3	$	(7	)	$	16
	Fuel expense		(2	)		14		(1	)		14
Trading activities	Operating revenue		33			17		80			27

Contingent Features/Credit Related Exposure

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has 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

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

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


Collateral provided to counterparties
	Offset against derivative liabilities	$	26	$	49
	Reflected in margin and collateral deposits		108		120
Collateral received from counterparties
	Offset against derivative assets		55		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		(55	)		—			(55	)

Balance at June 30, 2010		$	50		$	(27	)	$	23

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

Included in accumulated other comprehensive income at June 30, 2010 was $60 million, net of tax, in unrealized gains on commodity-based cash flow hedges; and a $10 million, net of tax, unrealized loss related to interest rate hedges.

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

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markets are lower than the contract prices. Approximately $67 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 revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a commodity cash flow hedge is designated is through December 31, 2012.

Note 5. Discontinued Operations

Summarized financial information for discontinued operations is as follows:

	Three Months Ended June 30,					Six Months Ended June 30,

(in millions)	2010		2009			2010		2009

Income (loss) before income taxes	$	4	$	(12	)	$	15	$	(6	)
Provision (benefit) for income taxes		1		(5	)		6		(2	)

Income (loss) from operations of discontinued foreign subsidiaries	$	3	$	(7	)	$	9	$	(4	)

During the second quarter and six months ended June 30, 2010, EME made payments of $15 million and $41 million, respectively, 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 $15 million due primarily to expiration of a contract indemnity during the first six months of 2010 and changes in foreign exchange rates.

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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 six months ended June 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)		95								96						(1	)
Other comprehensive income		30											30
Payments to Edison International for stock purchases related to stock-based compensation		(1	)							(1	)
Other stock transactions, net		2					2
Cash contributions from noncontrolling interests		1														1
Cash distributions to noncontrolling interests		(1	)													(1	)

Balance at June 30, 2009	$	2,890		$	64	$	1,337		$	1,180		$	230		$	79

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		64								64
Other comprehensive loss		(55	)										(55	)
Payments to Edison International for stock purchases related to stock-based compensation		(2	)							(2	)
Other stock transactions, net		3					3
Purchase of noncontrolling interests²		(5	)				(5	)

Balance at June 30, 2010	$	2,781		$	64	$	1,337		$	1,352		$	23		$	5

¹: For the six months ended June 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

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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 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 June 30, 2010 and December 31, 2009, EME had majority interests in 15 wind projects with a total generating capacity of 701 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 June 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)		June 30, 2010		December 31, 2009


Current assets		$	26	$	73
Net property, plant and equipment¹			682		944
Other long-term assets			2		2

	Total assets¹	$	710	$	1,019

Current liabilities		$	16	$	17
Long-term obligations net of current maturities			18		20
Deferred revenues			57		58
Other long-term liabilities			19		21

	Total liabilities	$	110	$	116

Noncontrolling interests		$	5	$	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 $79 million and $81 million at June 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

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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.

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

(in millions)		June 30, 2010


Current assets		$	16
Net property, plant and equipment			81
Other long-term assets			3

	Total assets	$	100

Current liabilities		$	13
Long-term obligations net of current maturities			64
Deferred revenues			13
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 (loss) and cash flow for the six months ended June 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 June 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:

	Six Months Ended June 30,

(in millions)	2010			2009

Revenues	$	341		$	311
Expenses		(302	)		(273	)

Net income	$	39		$	38

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

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these projects. Accordingly, effective January 1, 2010, EME accounts for its interests in these projects under the equity method.

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

	As of June 30, 2010

(in millions)	Investment		Maximum Exposure

Natural gas-fired projects	$	325	$	325
Wind projects		174		174

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 June 30, 2010, entities which EME has accounted for under the equity method had indebtedness of $143 million, of which $54 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 $4 million for the six months ended June 30, 2010 and are estimated at $18 million for the last six months of 2010.

The following are components of pension expense:

	Three Months Ended June 30,						Six Months Ended June 30,

(in millions)	2010			2009			2010			2009

Service cost	$	4		$	4		$	8		$	7
Interest cost		4			3			7			6
Expected return on plan assets		(3	)		(2	)		(5	)		(4	)
Amortization of net loss		—			1			1			2

Total expense	$	5		$	6		$	11		$	11

Postretirement Benefits Other Than Pensions

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

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The following are components of postretirement benefits expense:

	Three Months Ended June 30,						Six Months Ended June 30,

(in millions)	2010			2009			2010			2009

Service cost	$	—		$	—		$	1		$	1
Interest cost		2			2			3			3
Amortization of prior service credit		(1	)		(1	)		(1	)		(1	)
Amortization of net loss		—			1			—			1

Total expense	$	1		$	2		$	3		$	4

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:

	Six Months Ended June 30,

(in millions)	2010			2009

Provision for income tax at federal statutory rate of 35%	$	3		$	41
State tax—net of federal benefit (excludes state tax settlement)		(2	)		9
Production tax credits		(33	)		(30	)
Federal settlement of tax disputes		—			(6	)
Resolution of 1986-2002 state tax issues		(20	)		—
Other		5			3

Income tax expense (benefit) from continuing operations	$	(47	)	$	17

EME recorded a tax benefit of $20 million in the second quarter of 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.

In the second quarter of 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. During the second quarter of 2009, EME recorded an income tax benefit of $6 million due to the settlement and related estimated impact of interest and state income taxes.

Note 10. Commitments and Contingencies

Contractual Obligations

Project Financing

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,

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subject to meeting specified conditions, a $21 million letter of credit facility and a $4 million working capital facility.

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

As of June 30, 2010, there was $65 million outstanding under the construction loan at a weighted average interest rate of 3.35% 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 June 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 six months ended June 30, 2010 was 0.26%. Annual maturities of this debt at June 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 June 30, 2010 was $21 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 June 30, 2010, EME's subsidiaries had firm commitments to spend approximately $447 million during the remainder of 2010 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.

Turbine Commitments

EME has entered into various turbine supply agreements with vendors to support its wind development efforts. As of June 30, 2010, EME had commitments, excluding turbines subject to the legal dispute described below, to purchase 46 wind turbines (69 MW) and had 13 wind turbines (33 MW) in storage to be used for future wind projects. EME has 59 wind turbines (102 MW) available for future projects, excluding turbines allocated to projects in construction and turbines subject to the legal dispute. EME has payment commitments related to wind turbines of $85 million due in 2011. During the second quarter, EME deferred the delivery and $82 million in payments for 69 MW of turbines to January 2011.

Excluded from the turbine agreements referred to above is a turbine supply agreement between Mitsubishi Power Systems Americas, Inc. and EME, which is subject to a legal dispute. EME has made deposits of $68 million for the purchase of 83 wind turbines (199 MW) under this agreement. The

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remaining payments under this agreement subject to dispute are $289 million, mostly related to undelivered wind turbines. Resolution of this dispute will impact whether, and to what extent, future payments may be due under this agreement.

Fuel Supply and Transportation Contracts

At June 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 $936 million, summarized as follows: $251 million for the remainder of 2010, $405 million in 2011, $247 million in 2012, and $33 million in 2013.

At June 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 $314 million, summarized as follows: $143 million for the remainder of 2010, and $171 million in 2011.

In addition to the above, in July 2010, Midwest Generation entered into additional contracts for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements, are estimated to be $101 million for 2011.

Letters of Credit

At June 30, 2010, letters of credit under EME's credit facility aggregated $100 million and were scheduled to expire as follows: $34 million in 2010 and $66 million in 2011. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $29 million and were scheduled to expire as follows: $2 million in 2010 and $27 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 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

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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 217 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2010. Midwest Generation had recorded a $49 million liability at June 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.

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 June 30, 2010, EME had recorded a liability of $39 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.

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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 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. An August status hearing has been scheduled, at which time a schedule for responses to the amended complaints and other procedural matters will be determined.

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

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requirements to obtain a construction permit and to install controls sufficient to meet 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 would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Homer City New Source Review 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

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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.

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 $3 million at June 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.

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Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During the second 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 now received all necessary permits from the Illinois EPA allowing the installation of SNCR technology on multiple units to meet the NO_x portion of the CPS.

In addition, work continued on the possible employment of 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 low-sulfur coal employed by Midwest Generation. Use of this technology in combination with low-sulfur coal 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. 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 this work, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO₂ emissions, at approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years. Midwest Generation expects to seek permits from the Illinois EPA for select initial units later this year.

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, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS 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. 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.

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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 CO₂ 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

Petitions for judicial review of the GHG tailoring rule are to be submitted by August 2, 2010. Legal challenges to the GHG tailoring rule have been filed.

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 substantially reduce power plant emissions of NO_x and SO₂ 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 issuance of a revised rule.

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 and an emissions 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.

Comments on the Transport Rule will be due 60 days after its publication in the Federal Register. 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

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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.

Note 11. Supplemental Cash Flows Information

		Six Months Ended June 30,

(in millions)		2010			2009

Cash paid (received)
	Interest (net of amount capitalized¹)	$	142		$	139
	Income taxes		(68	)		12
	Cash payments under plant operating leases		197			200
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 six months ended June 30, 2010 and 2009 was $23 million and $10 million, respectively.

Note 12. Subsequent Event

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 that converts to a 15-year amortizing term loan subject to meeting specified conditions, a $53 million bridge loan secured by the expected U.S. Treasury grant, a $9 million letter of credit facility and a $3 million working capital facility.

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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 second quarter of 2009 and six months ended June 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 renewable 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 June 30,									Six Months Ended June 30,

(in millions)		2010			2009			Change			2010		2009			Change

Net income (loss) attributable to EME common shareholders		$	(17	)	$	40		$	(57	)	$	64	$	96		$	(32	)

Non-Core Items
	Income (loss) from discontinued operations		3			(7	)		10			9		(4	)		13
	Settlement of tax disputes		20			6			14			20		6			14

	Total non-core items		23			(1	)		24			29		2			27

Core Earnings		$	(40	)	$	41		$	(81	)	$	35	$	94		$	(59	)

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.

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

•: $160 million decreased income from Midwest Generation and Homer City due to lower realized energy revenue and higher plant maintenance costs primarily attributed to scheduled plant outages

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during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EME's results were impacted by $17 million of unrealized losses during the second quarter of 2010 compared to unrealized gains of $24 million during the same period last year.

These decreases were partially offset by the following:

•: $14 million increased energy trading revenue during the second quarter of 2010 due to congestion and basis trading.
•: $9 million decrease in corporate expenses due primarily to lower renewable energy development expenses.

EME's core earnings for the six months ended June 30, 2010 were lower than core earnings for the six months ended June 30, 2009 primarily due to the following:

•: $186 million decreased income from Midwest Generation and Homer City due to lower realized energy revenue and higher plant maintenance costs primarily attributed to scheduled plant outages during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the first half of the year. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EME's results were impacted by $17 million of unrealized losses during the six months ended June 30, 2010 compared to unrealized gains of $39 million during the same period last year.

These decreases were partially offset by the following:

•: $51 million increased energy trading revenue due to congestion and basis trading.
•: $9 million decrease in corporate expenses due primarily to lower renewable energy development expenses.

Consolidated non-core items for EME included:

•: An earnings benefit of $20 million recorded in the second quarter of 2010 resulting from 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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US EPA Developments

In June 2010, the US EPA published its final GHG tailoring rule, with less stringent statutory emissions thresholds for GHGs than those originally proposed in late 2009. Since the rule affects only new or modified sources, it is not expected to have any immediate effect on the fossil-fuel generating stations of Midwest Generation or Homer City.

In June and July of 2010, two proposed rules were published. The first proposed rule, known as the Transport Rule (a replacement for the Clean Air Interstate Rule), would substantially reduce power plant emissions of NO_x and SO₂ starting in 2012, with additional reductions in 2014, and would impose new limitations on emissions allowance trading. The second proposal relates to the handling of coal combustion wastes.

For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies—Contingencies—Environmental Developments."

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EME's Renewable Program

EME has four projects totaling 600 MW under construction. Included among the projects under construction is the 130 MW Taloga project, which is slated to utilize wind turbines that are subject to a legal dispute. EME also had a development pipeline of potential wind projects with projected installed capacity of approximately 3,400 MW at June 30, 2010. EME had a purchase contract for 69 MW of wind turbines, and 33 MW of wind turbines in storage, that are to be used for projects not yet under construction as of June 30, 2010, excluding turbine purchase contracts for 199 MW of wind turbines that are subject to a legal dispute. EME has deferred delivery and payment for the 69 MW of turbines under the purchase contract to January 2011. If EME is unable to develop such projects on acceptable terms and conditions, certain turbine orders may be terminated, which would result in a material charge. 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 financing.

Mitsubishi Lawsuit

EME filed a complaint in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. Matters under dispute include, among other things, the requirement to purchase and pay the remaining purchase price for 199 MW of wind turbines, including related services and warranties, among other items, in the approximate amount of $289 million. The complaint asks the Court for, among other things, an order finding the supply agreement void and unenforceable and for an award of monetary damages, including return to EME of deposits of $68 million previously made for the units subject to dispute. See "Legal Proceedings" in Part II of this quarterly report.

EME's Liquidity

At June 30, 2010, EME had cash and cash equivalents and short-term investments of $333 million to meet liquidity needs as well as $464 million of capacity under its credit facility.

Capital expenditures to complete renewable related projects through 2011 are projected to be $495 million (excluding disputed turbine amounts of approximately $289 million) at June 30, 2010. In addition to available lines of credit and cash and cash equivalents, the following table summarizes the projected sources of cash to fund EME's anticipated expenditures:

(in millions)


Secured project financings:
	Big Sky¹	$	200
	Cedro Hill¹		70
Anticipated U.S. Treasury grants²			377

		$	647

¹: Remaining available balance at June 30, 2010.
²: Estimate based on estimated construction costs and anticipated commercial operations dates in 2011.

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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 second quarters of 2010 and 2009 and six months ended June 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 June 30,						Six Months Ended June 30,

(in millions)	2010			2009			2010			2009

Midwest Generation plants	$	(39	)	$	74		$	48		$	188
Homer City facilities		—			47			37			83
Renewable energy projects		19			11			29			37
Energy trading		31			17			78			27
Big 4 projects		12			11			16			17
Sunrise		7			6			3			1
Doga		—			8			15			8
March Point		—			1			17			3
Westside projects		—			—			1			3
Other projects		3			3			6			5
Other operating income (expense)		(1	)		—			1			—

		32			178			251			372
Corporate administrative and general		(34	)		(43	)		(70	)		(79	)
Corporate depreciation and amortization		(4	)		(3	)		(8	)		(6	)

AOI¹	$	(6	)	$	132		$	173		$	287

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 (loss) as reflected on EME's consolidated statements of income (loss):

		Three Months Ended June 30,					Six Months Ended June 30,

(in millions)		2010			2009		2010		2009

AOI		$	(6	)	$	132	$	173	$	287
Less:
	Equity in earnings of unconsolidated affiliates		20			21		39		28
	Dividend income from projects		1			9		17		10
	Production tax credits		19			14		33		30

Operating Income (Loss)		$	(46	)	$	88	$	84	$	219

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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 June 30,					Six Months Ended June 30,

(in millions)			2010			2009		2010		2009

Operating Revenues			$	281		$	340	$	660	$	724
Operating Expenses
	Fuel¹			98			110		239		233
	Plant operations			169			106		268		202
	Plant operating leases			18			19		37		38
	Depreciation and amortization			28			27		56		54
	Administrative and general			7			5		12		10

	Total operating expenses			320			267		612		537

Operating Income (Loss)				(39	)		73		48		187

Other Income				—			1		—		1

AOI			$	(39	)	$	74	$	48	$	188

Statistics²
	Generation (in GWh):
		Energy only contracts		5,430			6,361		13,642		12,117
		Load requirements services contract		—			447		—		1,333

	Total			5,430			6,808		13,642		13,450

	Aggregate plant performance:
		Equivalent availability		59.8%			78.5%		72.7%		80.6%
		Capacity factor		45.5%			57.1%		57.5%		56.7%
		Load factor		76.2%			72.7%		79.1%		70.3%
		Forced outage rate		10.4%			5.7%		8.2%		6.4%
	Average realized price/MWh:
		Energy only contracts	$	41.50		$	41.38	$	40.31	$	44.41
		Load requirements services contract	$	—		$	62.47	$	—	$	62.52
	Capacity revenue only (in millions)		$	58		$	42	$	105	$	81
	Average realized fuel costs/MWh		$	17.55		$	18.19	$	16.99	$	18.37

¹: Included in fuel costs were $1 million and $14 million during the second quarters of 2010 and 2009, respectively, and $5 million and $33 million during the six months ended June 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 six months ended June 30, 2010 and 2009, respectively. Transfers of SO₂ emission allowances from Midwest Generation were $5 million during the first six 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 decreased $113 million and $140 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of

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2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. The decline in realized gross margin during the second quarter was driven by lower generation, partially offset by higher capacity revenues. The year-to-date decline in realized gross margin was driven by lower average realized energy prices, partially offset by higher capacity revenues. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by transmission line tornado damage impacting the Powerton Station.

Included in operating revenues were unrealized gains (losses) of $(3) million and $5 million for the second quarters of 2010 and 2009, respectively, and $4 million and $20 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 were due to both the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges, and hedge contracts which are not accounted for as cash flow hedges (referred to as economic hedges). Unrealized gains in 2009 were primarily due to economic hedge contracts that are accounted for on a mark-to-market basis.

Included in fuel expenses were unrealized gains (losses) of $(2) million and $14 million for the second quarters of 2010 and 2009, respectively, and $(7) million and $14 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) were due to oil futures contracts which were accounted for as economic hedges. The contracts hedge a portion of 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 June 30,				Six Months Ended June 30,

(in millions)		2010		2009		2010		2009

Operating Revenues		$	129	$	161	$	304	$	326
Operating Expenses
	Fuel¹		57		63		127		127
	Plant operations		39		22		76		56
	Plant operating leases		27		25		52		50
	Depreciation and amortization		4		3		9		8
	Administrative and general		2		1		3		2

	Total operating expenses		129		114		267		243

Operating Income			—		47		37		83

AOI		$	—	$	47	$	37	$	83

Statistics²
	Generation (in GWh)		2,289		3,025		5,243		5,683
	Equivalent availability		64.5%		90.5%		72.3%		83.7%
	Capacity factor		55.5%		73.4%		63.9%		69.3%
	Load factor		86.0%		81.1%		88.4%		82.8%
	Forced outage rate		14.1%		7.0%		12.1%		9.5%
	Average realized energy price/MWh	$	48.78	$	46.24	$	49.57	$	51.29
	Capacity revenue only (in millions)	$	29	$	18	$	58	$	30
	Average fuel costs/MWh	$	25.08	$	20.91	$	24.23	$	22.36

¹: Included in fuel costs were $1 million during each of the second quarters of 2010 and 2009, and $5 million and $8 million during the six months ended June 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 six months ended June 30, 2010. Transfers of NO_x emission allowances from Homer City were $0.4 million and $1 million during the six months ended June 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 $47 million and $46 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, higher unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. The decline in realized gross margin was driven by lower generation and higher coal costs, partially offset by higher capacity revenues. The Homer City facilities experienced increased forced outages in 2010 compared to 2009 due to opacity-related deratings.

Included in operating revenues were unrealized gains (losses) from hedge activities of $(12) million and $5 million for the second quarters of 2010 and 2009, respectively, and $(14) million and $5 million for

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the six months ended June 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.

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 revenue less unrealized gains (losses) and other non-energy related revenue by (ii) generation as shown in the table below. Revenue related to capacity sales is excluded from the calculation of average realized energy price.

Midwest Generation Plants		Three Months Ended June 30,						Six Months Ended June 30,

(in millions)		2010			2009			2010			2009

Operating revenues		$	281		$	340		$	660		$	724
Less:
	Load requirements services contract		—			(28	)		—			(83	)
	Unrealized (gains) losses		3			(5	)		(4	)		(20	)
	Capacity and other revenues		(58	)		(44	)		(106	)		(83	)

Realized revenues		$	226		$	263		$	550		$	538

Generation—energy only contracts (in GWh)			5,430			6,361			13,642			12,117
Average realized energy price/MWh		$	41.50		$	41.38		$	40.31		$	44.41

Homer City Facilities		Three Months Ended June 30,						Six Months Ended June 30,

(in millions)		2010			2009			2010			2009

Operating revenues		$	129		$	161		$	304		$	326
Less:
	Unrealized (gains) losses		12			(5	)		14			(5	)
	Capacity and other revenues		(29	)		(17	)		(58	)		(30	)

Realized revenues		$	112		$	139		$	260		$	291

Generation (in GWh)			2,289			3,025			5,243			5,683
Average realized energy price/MWh		$	48.78		$	46.24		$	49.57		$	51.29

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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 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 June 30,				Six Months Ended June 30,

(in millions)		2010		2009		2010		2009

Operating revenues
	Midwest Generation plants	$	281	$	340	$	660	$	724
	Homer City facilities		129		161		304		326
	Renewable energy projects		34		31		64		75
	Other revenues		49		25		116		44

Consolidated operating revenues as reported		$	493	$	557	$	1,144	$	1,169

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 expense adjusted for unrealized gains (losses) by (ii) generation as shown in the table below:

Midwest Generation Plants		Three Months Ended June 30,					Six Months Ended June 30,

(in millions)		2010			2009		2010			2009

Fuel expenses		$	98		$	110	$	239		$	233
Add back:
	Unrealized gains (losses)		(2	)		14		(7	)		14

Realized fuel expenses		$	96		$	124	$	232		$	247

Total generation (in GWh)			5,430			6,808		13,642			13,450
Average realized fuel costs/MWh		$	17.55		$	18.19	$	16.99		$	18.37

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 expenses. 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

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

		Three Months Ended June 30,					Six Months Ended June 30,

(in millions)		2010		2009			2010		2009

Fuel expense
	Midwest Generation plants	$	98	$	110		$	239	$	233
	Homer City facilities		57		63			127		127
	Other		6		(1	)		8		(1	)

Consolidated fuel expense as reported		$	161	$	172		$	374	$	359

Statistical Definitions

•: Load requirements services contract generation 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.
•: 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 unplanned maintenance outages and forced deratings.
•: The average realized price for load requirements service contracts 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 revenue 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 June 30,				Six Months Ended June 30,

(in millions)			2010		2009		2010		2009

Operating Revenues			$	34	$	31	$	64	$	75
Production Tax Credits				19		14		33		30

				53		45		97		105

Operating Expenses
	Plant operations			12		12		24		25
	Depreciation and amortization			22		21		43		41
	Administrative and general			—		1		1		2

	Total operating expenses			34		34		68		68

AOI¹			$	19	$	11	$	29	$	37

Statistics²
	Generation (in GWh)³			992		718		1,835		1,538
	Aggregate plant performance³:
		Equivalent availability		90.9%		87.3%		90.8%		84.2%
		Capacity factor		38.5%		30.5%		35.8%		33.4%

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 June 30,					Six Months Ended June 30,

(in millions)		2010		2009			2010			2009

AOI		$	19	$	11		$	29		$	37
Less:
	Production tax credits		19		14			33			30

Operating Income (Loss)		$	—	$	(3	)	$	(4	)	$	7

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 821 GWh and 1,512 GWh for the three months and six months ended June 30, 2010, respectively.

AOI from renewable energy projects increased $8 million and decreased $8 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The second quarter increase in AOI was primarily attributable to higher generation resulting from an increase in projects in operations. The year-to-date decrease in AOI results from higher

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depreciation and operations costs related to additional projects in operations, offset by the impact of the deconsolidation of two renewable projects in 2010. AOI in the second quarter and six months ended June 30, 2009 included $5 million and $16 million, respectively, of liquidated damages from availability guarantees provided by a wind turbine supplier, which compensated EME for lower generation (none recorded in 2010). The second quarter ended June 30, 2010 did not include liquidated damages for equipment warranty related items given completion of the blade remediation program. During the second quarter of 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 $51 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increases in AOI from energy trading activities were attributable to increased revenue in congestion and basis trading.

Adjusted Operating Income from Unconsolidated Affiliates

Doga

AOI from the Doga project decreased $8 million and increased $7 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods 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 increased $14 million for the six months ended June 30, 2010, compared to the corresponding period of 2009. The 2010 increase was primarily due to an $18 million equity distribution received from the project in February 2010. 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 June 30,						Six Months Ended June 30,

(in millions)			2010			2009			2010			2009

Interest income			$	1		$	3		$	2		$	6

Interest expense:
	EME debt		$	(58	)	$	(68	)	$	(118	)	$	(136	)
	Non-recourse debt:
		Midwest Generation		—			(2	)		(1	)		(5	)
		EME CP Holding Co.		(1	)		(1	)		(2	)		(2	)
		Viento Funding II, Inc.		(4	)		—			(8	)		—
		Other projects		(3	)		(2	)		(5	)		(4	)

			$	(66	)	$	(73	)	$	(134	)	$	(147	)

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. Capitalized interest for projects under construction increased $8 million and $13 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009.

Income Taxes

EME's income taxes from continuing operations during the second quarter of 2010 included a $20 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 six months ended June 30, 2010 and 2009, included tax benefits of production tax credits of $33 million and $30 million, respectively.

Results of Discontinued Operations

Income from discontinued operations, net of tax, increased $10 million and $13 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increase was due to lower foreign exchange rates. The year-to-date increase was due to 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 second quarter and six months ended June 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."

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 expenses. The

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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 June 30,					Six Months Ended June 30,

(in millions)		2010			2009		2010			2009

Midwest Generation plants
	Non-qualifying hedges	$	(4	)	$	18	$	(6	)	$	34
	Ineffective portion of cash flow hedges		(1	)		1		3			—
Homer City facilities
	Non-qualifying hedges		—			1		—			—
	Ineffective portion of cash flow hedges		(12	)		4		(14	)		5

Total unrealized gains (losses)		$	(17	)	$	24	$	(17	)	$	39

At June 30, 2010, cumulative unrealized gains of $25 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($16 million for the remainder of 2010, $8 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

At June 30, 2010, EME and its subsidiaries had consolidated cash and cash equivalents of $707 million and a total of $961 million of available borrowing capacity under their credit facilities. EME's consolidated debt at June 30, 2010 was $4.1 billion, of which $107 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 25 years.

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

(in millions)	EME			Midwest Generation


Commitment	$	600		$	500
Less: Commitment from Lehman Brothers subsidiary		(36	)		—

		564			500
Outstanding borrowings		—			—
Outstanding letters of credit		(100	)		(3	)

Amount available	$	464		$	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%.

For the remainder of 2010, EME anticipates capital expenditures of $635 million (excluding a $289 million disputed amount under a turbine supply agreement) to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EME secured a $206 million vendor financing, of which $200 million was available at June 30, 2010, and a $160 million project financing, of which $70 million was available at June 30, 2010. EME intends to file for U.S. Treasury grants for its renewable energy projects in construction.

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.

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Capital Investment Plan

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

(in millions)		July through December 2010		2011		2012


Midwest Generation Plants Plant capital expenditures		$	26	$	79	$	10
	Environmental expenditures¹		93		145		78
Homer City Facilities Plant capital expenditures			8		52		24
	Environmental expenditures²		1		3		22
Renewable Projects Capital and construction expenditures³			495		—		—
	Turbine commitments⁴		—		85		—
Other capital expenditures			12		17		9

Total		$	635	$	381	$	143

¹: Environmental expenditures include primarily expenditures related to SNCR equipment and $156 million for expenditures during the remainder of 2010 to 2012 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: Includes projects under construction where project financing has been secured. The available balance under secured financing arrangements was $270 million as of June 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.
⁴: Turbine commitment figures exclude $289 million which is subject to dispute under provisions in one of the turbine supply agreements. In March 2010, EME filed a breach of contract complaint against this turbine supplier. For additional discussion, see "Legal Proceedings" in Part II of this quarterly report.

Estimated Expenditures for Existing Projects

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

Environmental expenditures at Homer City relate to emission monitoring and control projects. 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

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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.

Estimated Expenditures for Future Projects

EME has wind turbines in storage and on order for wind projects under construction and to be used for future wind projects (turbine commitments are reflected separately in the preceding capital expenditure table). Amounts exclude balance of project costs for 102 MW available for new projects, which EME estimates to be an additional $75 million to $120 million based on typical project costs. 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 programs may depend upon the availability of outside project-level debt and equity financing. Successful completion of the development of a wind project depends upon obtaining permits and agreements necessary to support an investment and may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.

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

	Six Months Ended June 30,

(in millions)	2010			2009

Operating cash flow from continuing operations	$	159		$	(91	)
Operating cash flow from discontinued operations		9			(4	)

Net cash provided by (used in) operating activities		168			(95	)
Net cash provided by financing activities		37			132
Net cash used in investing activities		(294	)		(188	)

Net decrease in cash and cash equivalents	$	(89	)	$	(151	)

Consolidated Cash Flows from Operating Activities

Cash provided by operating activities from continuing operations increased $250 million in the first six months of 2010, compared to the first six months of 2009. The 2010 increase was primarily attributable to a decrease in cash collateral deposits for risk management and energy trading compared to 2009, $92 million received related to U.S. Treasury grants, and changes in the timing of cash receipts and disbursements related to working capital items.

Consolidated Cash Flows from Financing Activities

Cash provided by financing activities from continuing operations decreased $95 million in the first six months of 2010, compared to the first six months of 2009. The 2010 decrease was primarily attributable

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to lower levels of renewable energy project financing. 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."

Consolidated Cash Flows from Investing Activities

Cash used in investing activities from continuing operations increased $106 million in the first six months of 2010, compared to the first six months of 2009. The 2010 increase was primarily due to higher expenditures for construction of renewable energy projects compared to 2009.

Credit Ratings

Overview

On June 29, 2010, Moody's lowered the credit ratings of EME to B3 from B2 and Midwest Generation to Ba2 from Ba1. 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 June 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 June 30, 2010 could increase by approximately $184 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings."

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

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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 June 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 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 June 30, 2010, EME had cash and cash equivalents and short-term investments of $333 million to meet liquidity needs as well as $464 million of capacity under its credit facility. EME's cash and cash equivalents included $188 million held directly by EME, as well as cash and cash equivalents related to EMMT of $143 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)			June 30, 2010			December 31, 2009

Funds Flow Available for Interest Distributions
		Midwest Generation	$	95		$	200
		Homer City		97			75
		Big 4 Projects		71			62
		Viento Funding II, Inc.¹		4			167
		U.S. Treasury grants		92			—
		Renewables		84			41
		Other projects		75			47
	Tax payments received from subsidiaries			57			68
	Realized trading income			86			36
	Tax allocation receipts (payments)			196			139
	Operating expenses			(149	)		(151	)
	Other items, net			(47	)		(14	)

			$	661		$	670

Net Interest Expense EME corporate debt			$	243		$	261
	Addback: Capitalized interest			32			19
	Powerton-Joliet intercompany notes			112			112
	EME interest income			(1	)		(2	)

			$	386		$	390

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

¹: The proceeds of the Viento Funding II wind financing, net of financing costs, were distributed to EME in 2009.

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Corporate-Debt-to-Capital Ratio

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

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


Corporate Debt
	Indebtedness for money borrowed		$	3,700		$	3,700
	Powerton-Joliet termination value			987			1,046
	Letters of credit			103			104

			$	4,790		$	4,850

Corporate Capital
	Common shareholder's equity		$	2,776		$	2,761
	Less:
		Non-cash cumulative changes in accounting		(9	)		1
		Accumulated other comprehensive income		(23	)		(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

				4,230			4,170

	Corporate debt			4,790			4,850

			$	9,020		$	9,020

Corporate-debt-to-capital ratio				0.53			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 June 30, 2010 or for the 12 months ended June 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	0.16 to 1
Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.53 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.

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

(in millions)


Consolidated Net Tangible Assets
	Total consolidated assets		$	8,641
	Less:
		Consolidated current liabilities		495
		Intangible assets		96

			$	8,050

10% Threshold			$	805

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."

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Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 on page 86 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 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 six months of 2010 and 2009:

		24-Hour Average Historical Market Prices¹

		2010		2009

Midwest Generation plants
	Northern Illinois Hub	$	33.44	$	30.08
Homer City facilities
	PJM West Hub	$	43.88	$	41.40
	Homer City Busbar		38.28		38.01

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 June 30, 2010:

		24-Hour Forward Energy Prices¹

		Northern Illinois Hub		PJM West Hub

2010
	July	$	40.32	$	53.39
	August		39.34		52.04
	September		31.05		42.66
	October		26.59		40.15
	November		30.05		41.16
	December		32.43		44.25
2011 calendar "strip"²		$	32.75	$	45.54

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 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-serving transactions and forward contracts accounted for on the accrual basis) as of June 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		9,835	$	42.87		14,152	$	37.93		2,040	$	41.37
Homer City facilities²
	PJM West Hub		2,540		71.19		2,428		52.15		1,182		51.78

Total			12,375				16,580				3,222

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.

In addition, as of June 30, 2010, EMMT had entered into 1.5 bcf of natural gas futures contracts (equivalent to approximately 255 GWh of energy only 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.

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Capacity Price Risk

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

									RPM Capacity Sold in Base Residual Auction				Other Capacity Sales, Net of Purchases²

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

July 1, 2010 to May 31, 2011 Midwest Generation			5,477		(548	)		4,929		4,929	$	174.29		—			—	$	174.29
	Homer City		1,884		(211	)		1,673		1,813		174.29		(140	)	$	55.36		184.24
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		(148	)		1,736		1,736		133.37		—			—		133.37
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	³

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: Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.
³: Includes 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 period of June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $27.73 per MW-day was substantially lower than other areas' capacity prices. The impact of lower capacity prices for this period 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 six months ended June 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 11% and 1%, respectively, compared to 17% and less than 1%, respectively, during the six months ended June 30, 2009. During the six months ended June 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 13% and 8%, respectively.

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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 June 30, 2010 for the remainder of 2010 and the following three years:

	Amount of Coal Under Contract in Millions of Equivalent Tons¹


	July through December 2010		2011		2012		2013

Midwest Generation plants²		10.2		11.7		9.8		—
Homer City facilities		2.5		4.2		1.7		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.
²: In July 2010, Midwest Generation entered into additional contracts for the purchase of 3.9 million tons of coal for 2011.

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 $62.75 per ton at July 2, 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 $13.05 per ton at July 2, 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 $50 per ton during the six months ended June 30, 2010 from $65 per ton in 2009. The average purchase price of annual NO_x allowances decreased to $974 per ton during the six months ended June 30, 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price

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for SO₂ allowances and annual NO_x allowances was $15 per ton and $465 per ton, respectively, at June 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 June 30, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

		June 30, 2010

(in millions)		Exposure²		Collateral			Net Exposure

Credit Rating¹
	A or higher	$	133	$	(28	)	$	105
	A-		120		(6	)		114
	BBB+		27		—			27
	BBB		23		—			23
	BBB-		23		—			23
	Below investment grade		20		(18	)		2

Total		$	346	$	(52	)	$	294

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 $139 million of net accounts receivable and payables and $207 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $108 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 67% of EME's consolidated operating revenues for the six months ended June 30, 2010. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At June 30, 2010, EME's account receivable due from PJM was $66 million.

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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 loan and long-term obligations (including current portion) was $2.8 billion at June 30, 2010, compared to the carrying value of $4.1 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

Homer City New Source Review Notice of Violation

Recent Developments

In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the 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.

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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. The remaining wind turbines, among other items, are under dispute.

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 a wind turbine generator supply agreement for the purchase of wind turbines and related services and warranties. EME's complaint alleges, among other things: (a) that the Mitsubishi entities fraudulently induced EME to enter into the supply agreement by misrepresenting the facts and circumstances surrounding Mitsubishi's rights to certain technology incorporated into the turbines; (b) that the Mitsubishi entities breached the implied covenant of good faith and fair dealing; (c) that the Mitsubishi entities breached their warranty obligations; (d) that the Mitsubishi entities repudiated the supply agreement when they failed to provide EME with adequate assurances of performance; and (e) that certain price escalation provisions in the supply agreement do not reflect the intent of the contracting parties.

The complaint asks the Court for an order finding the supply agreement void and unenforceable or, in the alternative, for an order reforming its price escalation provisions to conform to the contracting parties' intent. The complaint also requests an order of specific performance requiring the Mitsubishi entities to honor their warranties with respect to equipment already purchased, an award of monetary damages (including exemplary and punitive damages), and an accounting of all amounts due under the supply agreement, including reimbursement to EME of amounts previously paid for units it can no longer use and is excused from accepting, together with prejudgment interest, and such other relief as the Court may deem just and proper. In June 2010, EME filed a motion to amend its complaint to include, among other things, additional support for its claims.

The failure of the Mitsubishi entities to perform certain previously contracted services pertaining to the Taloga project, including delivery and commissioning of turbines still in storage, could delay the development of the Taloga project. If the Taloga project does not achieve commercial operation by March 31, 2011, subject to extension under certain circumstances, Taloga's offtaker could seek to terminate or renegotiate its power purchase agreement.

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 June 30, 2010, filed on August 5, 2010, formatted in XBRL: (i) the Consolidated Statements of Income (Loss), (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

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SIGNATURES

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


		EDISON MISSION ENERGY
		By:		/s/ John P. Finneran, Jr. John P. Finneran, Jr. Senior Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)
		Date:		August 5, 2010