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, 2011
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number 333-68630

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


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

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

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

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

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO ý

Number of shares outstanding of the registrant's Common Stock as of August 4, 2011: 100 shares (all shares held by an affiliate of the registrant).

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TABLE OF CONTENTS


GLOSSARY					v
PART I – FINANCIAL INFORMATION					1
ITEM 1. FINANCIAL STATEMENTS					1
	CONSOLIDATED STATEMENTS OF OPERATIONS				1
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)				2
	CONSOLIDATED BALANCE SHEETS				3
	CONSOLIDATED STATEMENTS OF CASH FLOWS				5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS				6
	Note 1. Summary of Significant Accounting Policies				6
		Basis of Presentation			6
		Cash Equivalents			6
		Inventory			6
		Prepaid Expenses and Other			7
		New Accounting Guidance			7
			Accounting Guidance Adopted in 2011		7
				Revenue—Multiple-Deliverables	7
				Fair Value Measurements and Disclosures	7
			Accounting Guidance Not Yet Adopted		7
				Fair Value Measurement	7
				Presentation of Comprehensive Income	7
	Note 2. Consolidated Statement of Changes in Equity				8
	Note 3. Variable Interest Entities				9
		Projects or Entities that are Consolidated			9
		Projects that are not Consolidated			9
	Note 4. Fair Value Measurements				10
		Recurring Fair Value Measurements			10
		Valuation Techniques used to Determine Fair Value			12
			Level 1		12
			Level 2		12
			Level 3		13
		Long-term Debt			13
	Note 5. Debt and Credit Agreements				13
		Project Financings			13
			Walnut Creek		13
			Viento Funding II Wind Financing Amendment		14
		Standby Letters of Credit			14
	Note 6. Derivative Instruments and Hedging Activities				15
		Notional Volumes of Derivative Instruments			16
		Fair Value of Derivative Instruments			18
		Income Statement Impact of Derivative Instruments			18
		Contingent Features			19
		Margin and Collateral Deposits			19
	Note 7. Income Taxes				20
		Effective Tax Rate			20

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		Accounting for Uncertainty in Income Taxes		20
			Unrecognized Tax Benefits	20
		Accrued Interest and Penalties		21
		Bonus Depreciation Impact on EME		21
	Note 8. Compensation and Benefit Plans			21
		Pension Plans and Postretirement Benefits Other Than Pensions		21
			Pension Plans	21
			Postretirement Benefits Other Than Pensions	22
	Note 9. Commitments and Contingencies			22
		Commitments		22
			Fuel Supply Contracts	22
			Turbine Commitments	22
			Capital Expenditures	23
		Guarantees and Indemnities		23
			Environmental Indemnities Related to the Midwest Generation Plants	23
			Environmental Indemnity Related to the Homer City Plant	24
			Indemnities Provided under Asset Sale and Sale-Leaseback Agreements	24
			Other Indemnities	24
		Contingencies		25
			Midwest Generation New Source Review and Other Litigation	25
			Homer City New Source Review and Other Litigation	26
			Environmental Remediation	26
	Note 10. Environmental Developments			27
		Cross-State Air Pollution Rule		27
		Proposed Hazardous Air Pollutant Regulations		28
		Water Quality - Clean Water Act		28
		Greenhouse Gas Litigation Developments		28
	Note 11. Accumulated Other Comprehensive Loss			29
	Note 12. Supplemental Cash Flows Information			30
	Note 13. Discontinued Operations			30
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				31
	MANAGEMENT'S OVERVIEW			33
	Introduction			33
	Highlights of Operating Results			33
	Cross-State Air Pollution Rule			35
	Homer City Capital Needs			36
	Midwest Generation Environmental Compliance Plans and Costs			36
	Walnut Creek Project			37
	EME's Liquidity			37
	RESULTS OF OPERATIONS			39
	Results of Continuing Operations			39
		Overview		39

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	Adjusted Operating Income from Consolidated Operations			40
		Midwest Generation Plants		40
		Homer City		42
		Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions		43
			Average Realized Energy Price	43
			Average Realized Fuel Costs	44
			Statistical Definitions	45
		Seasonality—Coal Plants		45
		Renewable Energy Projects		46
		Energy Trading		46
	Adjusted Operating Income from Unconsolidated Affiliates			47
	Interest Income (Expense)			47
	Income Taxes			47
New Accounting Guidance				48
LIQUIDITY AND CAPITAL RESOURCES				49
Available Liquidity				49
Homer City Outage				49
Bonus Depreciation Impact on EME				50
Capital Investment Plan				51
	Environmental Capital Expenditures			51
	Plant Capital Expenditures			52
	Walnut Creek Project Expenditures			52
	Renewable Energy 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		53
		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				54
EME's Liquidity as a Holding Company				54
	EME's Credit Facility Financial Ratios			54
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 Contracts			57
	Capital Expenditures			57
	Midwest Generation New Source Review and Other Litigation			57
	Homer City New Source Review and Other Litigation			58
Off-Balance Sheet Transactions				58
Environmental Matters and Regulations				58

iii

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	MARKET RISK EXPOSURES		59
	Derivative Instruments		59
		Unrealized Gains and Losses	59
		Fair Value Disclosures	59
	Commodity Price Risk		59
		Energy Price Risk	59
		Capacity Price Risk	61
		Basis Risk	62
		Coal and Transportation Price Risk	62
		Emission Allowances Price Risk	63
	Credit Risk		63
	Interest Rate Risk		64
	CRITICAL ACCOUNTING ESTIMATES AND POLICIES		65
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			65
ITEM 4. CONTROLS AND PROCEDURES			65
	Disclosure Controls and Procedures		65
	Internal Control Over Financial Reporting		65
PART II – OTHER INFORMATION			66
ITEM 1. LEGAL PROCEEDINGS			66
	Midwest Generation New Source Review and Other Litigation		66
	Homer City New Source Review and Other Litigation		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.



2010 Tax Relief Act		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AES		AES Southland Funding, LLC and its affiliates
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
CAIR		Clean Air Interstate Rule
coal plants		Midwest Generation coal plants and Homer City electric generating station
Commonwealth Edison		Commonwealth Edison Company
CPS		Combined Pollutant Standard
CSAPR		Cross-State Air Pollution Rule
EME		Edison Mission Energy
EMMT		Edison Mission Marketing & Trading, Inc.
GAAP		accounting principles generally accepted in the United States of America
GWh		gigawatt-hours
Homer City		EME Homer City Generation L.P.
LIBOR		London Interbank Offered Rate
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations
Midwest Generation		Midwest Generation, LLC
MMBtu		million British thermal units
Moody's		Moody's Investors Service, Inc.
MW		megawatts
MWh		megawatt-hours
NO_X		nitrogen oxide
NYISO		New York Independent System Operator
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
RPM		Reliability Pricing Model
S&P		Standard & Poor's Ratings Services
SO₂		sulfur dioxide
US EPA		United States Environmental Protection Agency
U.S. Treasury grants		Cash grants, under the American Recovery and Reinvestment Act of 2009

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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, unaudited)
			Three Months Ended June 30,						Six Months Ended June 30,

			2011			2010			2011			2010

Operating Revenues			$	536		$	493		$	1,086		$	1,144
Operating Expenses
	Fuel			174			161			356			374
	Plant operations			240			226			432			384
	Plant operating leases			44			45			88			89
	Depreciation and amortization			79			60			151			119
	Asset retirements			8			3			8			4
	Administrative and general			45			44			88			90

		Total operating expenses		590			539			1,123			1,060

	Operating income (loss)			(54	)		(46	)		(37	)		84

Other Income (Expense)
	Equity in income from unconsolidated affiliates			17			20			12			37
	Dividend income			27			1			28			17
	Interest income			—			1			1			2
	Interest expense			(80	)		(66	)		(160	)		(134	)
	Other income, net			2			—			5			2

		Total other income (expense)		(34	)		(44	)		(114	)		(76	)

	Income (loss) from continuing operations before income taxes			(88	)		(90	)		(151	)		8
	Benefit for income taxes			(57	)		(70	)		(102	)		(47	)

Income (Loss) from Continuing Operations				(31	)		(20	)		(49	)		55
Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 13)				(1	)		3			(3	)		9

Net Income (Loss)				(32	)		(17	)		(52	)		64

Net Income Attributable to Noncontrolling Interests				—			—			—			—

Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder			$	(32	)	$	(17	)	$	(52	)	$	64

Amounts Attributable to Edison Mission Energy Common Shareholder
Income (loss) from continuing operations, net of tax			$	(31	)	$	(20	)	$	(49	)	$	55
Income (loss) from discontinued operations, net of tax				(1	)		3			(3	)		9

Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder			$	(32	)	$	(17	)	$	(52	)	$	64

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,

			2011			2010			2011			2010

Net Income (Loss)			$	(32	)	$	(17	)	$	(52	)	$	64
Other comprehensive loss, net of tax
	Pension and postretirement benefits other than pensions
		Amortization of net loss included in expenses, net of tax		—			—			1			—
	Unrealized gains (losses) on derivatives qualified as cash flow hedges
		Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(9) and $(50) for the three months and $(5) and $12 for the six months ended June 30, 2011 and 2010, respectively		(14	)		(77	)		(8	)		18
		Reclassification adjustments included in net income (loss), net of income tax benefit of $6 and $35 for the three months and $12 and $49 for the six months ended June 30, 2011 and 2010, respectively		(7	)		(53	)		(17	)		(73	)

Other comprehensive loss				(21	)		(130	)		(24	)		(55	)

Comprehensive Income (Loss)				(53	)		(147	)		(76	)		9

Comprehensive Income Attributable to Noncontrolling Interests				—			—			—			—

Comprehensive Income (Loss) Attributable to Edison Mission Energy Common Shareholder			$	(53	)	$	(147	)	$	(76	)	$	9

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, 2011		December 31, 2010

Assets
Current Assets
	Cash and cash equivalents		$	833	$	1,075
	Accounts receivable—trade			137		170
	Receivables from affiliates			225		192
	Inventory			259		236
	Derivative assets			39		46
	Restricted cash			11		2
	Margin and collateral deposits			50		59
	Prepaid expenses and other			284		79

		Total current assets		1,838		1,859

Investments in Unconsolidated Affiliates				550		557

Property, Plant and Equipment, less accumulated depreciation of $1,898 and $1,759 at respective dates				5,536		5,332

Other Assets
	Deferred financing costs			52		54
	Long-term derivative assets			63		70
	Restricted deposits			25		44
	Rent payments in excess of levelized rent expense under plant operating leases			1,288		1,187
	Other long-term assets			141		218

		Total other assets		1,569		1,573

Total Assets			$	9,493	$	9,321

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

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EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS (in millions, except share and per share amounts, unaudited)
			June 30, 2011			December 31, 2010

Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	134		$	90
	Payables to affiliates			15			18
	Accrued liabilities			150			201
	Derivative liabilities			6			6
	Interest payable			31			31
	Deferred taxes			38			34
	Current portion of long-term debt			53			48
	Short-term debt			109			96

		Total current liabilities		536			524

Long-term debt net of current portion				4,484			4,342
Deferred taxes and tax credits				787			836
Deferred revenues				319			160
Long-term derivative liabilities				23			19
Other long-term liabilities				604			619

Total Liabilities				6,753			6,500

Commitments and Contingencies (Notes 5, 6, 9 and 10)
Equity
	Common stock, par value $0.01 per share (10,000 shares authorized; 100 shares issued and outstanding at each date)			64			64
	Additional paid-in capital			1,335			1,336
	Retained earnings			1,393			1,448
	Accumulated other comprehensive loss			(55	)		(31	)

		Total Edison Mission Energy common shareholder's equity		2,737			2,817

Noncontrolling Interests				3			4

Total Equity				2,740			2,821

Total Liabilities and Equity			$	9,493		$	9,321

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

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EDISON MISSION ENERGY AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions, unaudited)
			Six Months Ended June 30,
			2011			2010

Cash Flows From Operating Activities
	Net income (loss)		$	(52	)	$	64
	(Income) loss from discontinued operations			3			(9	)

	Income (loss) from continuing operations, net			(49	)		55
	Adjustments to reconcile income (loss) to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(12	)		(37	)
		Distributions from unconsolidated affiliates		15			39
		Depreciation and amortization		164			125
		Deferred taxes and tax credits		(30	)		53
	Changes in operating assets and liabilities:
		Decrease in margin and collateral deposits		9			12
		Decrease in accounts receivables		—			53
		Increase in inventory		(22	)		(34	)
		(Increase) decrease in prepaid expenses and other		(12	)		7
		(Increase) decrease in restricted cash		(9	)		43
		Increase in rent payments in excess of levelized rent expense		(101	)		(111	)
		Increase (decrease) in accounts payable and other current liabilities		1			(121	)
		Increase in derivative assets and liabilities		(23	)		(35	)
		Proceeds from U.S. Treasury grants		—			92
		Decrease in other operating—assets		8			8
		Increase (decrease) in other operating—liabilities		(31	)		10

	Operating cash flow from continuing operations			(92	)		159
	Operating cash flow from discontinued operations			(3	)		9

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

Cash Flows From Financing Activities
	Borrowings on long-term debt			95			7
	Payments on long-term debt			(28	)		(23	)
	Borrowings on short-term debt			32			—
	Borrowings under construction loan			—			65
	Payments to affiliates related to stock-based awards			(4	)		(2	)
	Excess tax benefits related to stock option exercises			1			—
	Financing costs			—			(10	)

		Net cash provided by financing activities from continuing operations		96			37

Cash Flows From Investing Activities
	Capital expenditures			(238	)		(313	)
	Proceeds from return of capital and loan repayments and sale of assets			12			27
	Investments in and loans to unconsolidated affiliates			(7	)		—
	Purchase of interest of acquired companies			—			(4	)
	Maturities of short-term investments			—			1
	Decrease in restricted deposits			19			—
	Investments in other assets			(29	)		(5	)

		Net cash used in investing activities from continuing operations		(243	)		(294	)

Net decrease in cash and cash equivalents				(242	)		(89	)
Cash and cash equivalents at beginning of period				1,075			796

Cash and cash equivalents at end of period			$	833		$	707

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, 2011
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

Edison Mission Energy's (EME's) significant accounting policies were described in "Note 1—Summary of Significant Accounting Policies" on page 94 of EME's annual report on Form 10-K for the year ended December 31, 2010. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011, as discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements and notes.

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 (GAAP) for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2011 are not necessarily indicative of the operating results for the full year. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

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

The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Cash Equivalents

Cash equivalents included money market funds totaling $674 million and $813 million at June 30, 2011 and December 31, 2010, respectively. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months.

Inventory

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

(in millions)	June 30, 2011		December 31, 2010


Coal, fuel oil and other raw materials	$	183	$	163
Spare parts, materials and supplies		76		73

Total inventory	$	259	$	236

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Prepaid Expenses and Other

At June 30, 2011, EME recorded $166 million for U.S. Treasury grants receivable related to the Laredo Ridge and Cedro Hill wind projects that was included in prepaid expenses and other and also in deferred revenues on its consolidated balance sheet.

New Accounting Guidance

Accounting Guidance Adopted in 2011

Revenue—Multiple-Deliverables

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

Fair Value Measurements and Disclosures

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

Accounting Guidance Not Yet Adopted

Fair Value Measurement

In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. EME will adopt this guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on EME's consolidated results of operations, financial position or cash flows.

Presentation of Comprehensive Income

In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. EME will adopt this guidance effective January 1, 2012. EME currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.

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Note 2. Consolidated Statement of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 2011:

	EME Shareholder's Equity

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

Balance at December 31, 2010	$	64	$	1,336		$	1,448		$	(31	)	$	4		$	2,821
Net loss		—		—			(52	)		—			—			(52	)
Other comprehensive loss		—		—			—			(24	)		—			(24	)
Payments to Edison International for stock purchases related to stock-based compensation		—		—			(3	)		—			—			(3	)
Excess tax benefits related to stock option exercises		—		1			—			—			—			1
Other stock transactions, net		—		2			—			—			—			2
Purchase of noncontrolling interests¹		—		(4	)		—			—			(1	)		(5	)

Balance at June 30, 2011	$	64	$	1,335		$	1,393		$	(55	)	$	3		$	2,740

¹: During the second quarter of 2011, EME purchased a noncontrolling interest in Pinnacle Wind Force, LLC, which is now 100% owned by EME.

The following table provides the changes in equity for the six months ended June 30, 2010:

	EME Shareholder's Equity

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

Balance at December 31, 2009	$	64	$	1,339		$	1,280		$	78		$	76		$	2,837
Impact of consolidation and deconsolidation of variable interest entities¹		—		—			10			—			(71	)		(61	)
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	$	64	$	1,337		$	1,352		$	23		$	5		$	2,781

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.

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Note 3. Variable Interest Entities

Projects or Entities that are Consolidated

At June 30, 2011 and December 31, 2010, EME consolidated 13 and 14 projects, respectively, with a total generating capacity of 570 MW and 580 MW, respectively, that have interests held by others. In April 2011, EME sold its 75% ownership interest in a Minnesota wind project. In determining that EME was the primary beneficiary, the key factors considered were EME's ability to direct commercial and operating activities, and EME's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.

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

(in millions)		June 30, 2011		December 31, 2010


Current assets		$	39	$	26
Net property, plant and equipment			712		739
Other long-term assets			5		6

	Total assets	$	756	$	771

Current liabilities		$	23	$	25
Long-term debt net of current portion			68		71
Deferred revenues			69		71
Other long-term liabilities			21		21

	Total liabilities	$	181	$	188

Noncontrolling interests		$	3	$	4

At June 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $163 million and primarily consist of property, plant and equipment.

Projects that are not Consolidated

EME accounts for domestic gas and wind energy projects in which it has less than a 100% ownership interest, and cannot exercise unilateral control, under the equity method. At June 30, 2011 and December 31, 2010, EME had five significant variable interests in natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EME operates three of the four Big 4 projects and the Sunrise project and EME's partner provides the fuel management services for the Big 4 projects. 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 accounts for its variable interests under the equity method.

At June 30, 2011 and December 31, 2010, EME accounts for its interests in two renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects, under the equity method. In addition, EME accounts for its interests in Community Wind North, which achieved commercial operation on May 28, 2011, under the equity method. The commercial and operating activities of these

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entities are jointly directed by representatives of each partner. Thus, EME is not the primary beneficiary of these projects.

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:

	June 30, 2011

(in millions)	Investment		Maximum Exposure

Natural gas-fired projects	$	321	$	321
Renewable energy projects		229		229

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. One of EME's domestic energy projects has long-term debt that is secured by a pledge of project entity assets, but does not provide for recourse to EME. Accordingly, a default under the project financing 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, 2011, entities which EME has accounted for under the equity method had indebtedness of $65 million, of which $16 million is proportionate to EME's ownership interest in this one project.

Note 4. Fair Value Measurements

Recurring Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or a liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. The fair value of derivative assets' nonperformance risk was not material as of June 30, 2011 and December 31, 2010.

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

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

			June 30, 2011

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

Assets at Fair Value
	Money market funds²		$	674	$	—	$	—	$	—		$	674

	Derivative contracts
		Electricity	$	—	$	44	$	91	$	(33	)	$	102
		Fuel oil		6		—		—		(6	)		—
		Coal		—		1		—		(1	)		—

		Total commodity contracts		6		45		91		(40	)		102

	Total assets		$	680	$	45	$	91	$	(40	)	$	776

Liabilities at Fair Value
	Derivative contracts
		Electricity	$	—	$	9	$	7	$	(9	)	$	7
		Interest rate contracts		—		22		—		—			22

	Total liabilities		$	—	$	31	$	7	$	(9	)	$	29

			December 31, 2010


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

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

		Total commodity contracts		9		70		107		(70	)		116

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

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

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

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

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

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

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

(in millions)		2011			2010			2011			2010

Fair value, net assets at beginning of period		$	83		$	199		$	91		$	173
Total realized/unrealized gains (losses)
	Included in earnings¹		18			(18	)		18			27
	Included in accumulated other comprehensive income (loss)		(4	)		(2	)		(3	)		4
Purchases			6			5			11			9
Settlements			(19	)		(24	)		(31	)		(52	)
Transfers in or out of Level 3			—			6			(2	)		5

Fair value, net assets at end of period		$	84		$	166		$	84		$	166

Change during the period in unrealized gains (losses) related to assets and liabilities, net held at end of period¹		$	14		$	(2	)	$	8		$	32

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

EME determines the fair value of transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during the second quarters and six months ended June 30, 2011 and 2010.

Valuation Techniques used to Determine Fair Value

Level 1

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

Level 2

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

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

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Level 3

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

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

Long-term Debt

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

	June 30, 2011				December 31, 2010

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

Long-term debt, including current portion	$	4,537	$	3,886	$	4,390	$	3,670

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

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

Note 5. Debt and Credit Agreements

Project Financings

Walnut Creek

On July 27, 2011, EME completed, through wholly owned subsidiaries, non-recourse financings to fund construction of the Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The financings included $122 million of letter of credit and working capital facilities, and

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also included floating rate construction loans totaling $495 million (with initial fundings of $48 million) that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions.

As of July 27, 2011, EME entered into interest rate swap agreements and forward-starting interest rate swap agreements that converted the floating rate London Interbank Offered Rate (LIBOR) construction loans to fixed rates. Under the interest rate swap agreements, EME will pay fixed rates of an average of 0.81% through May 31, 2013. Under the forward-starting swaps agreements, EME will pay an average fixed rate of 3.59% beginning June 30, 2013 through May 31, 2023. Interest under the project-level construction term loan of $442 million initially accrues at LIBOR plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries. Interest on the intermediate holding company construction term loan of $53 million accrues at LIBOR plus 4.00% over the term.

In May 2011, EME purchased, through wholly owned subsidiaries, select equipment at AES Southland Funding, LLC and its affiliates' (AES's) Huntington Beach facilities and leased such equipment back to an AES affiliate until its planned decommissioning at the end of 2012 for which AES retained the asset retirement obligation. The transaction resulted in an exemption for 90% of emission reduction credits needed to complete permitting activities for the Walnut Creek project. The purchase price of $56 million was recorded in property, plant and equipment, for the component related to permitting, and the remainder attributed to lease receivables. At June 30, 2011, EME's subsidiaries had outstanding $56 million in short-term, non-interest bearing notes payable related to the purchase, which were repaid upon the initial funding of the Walnut Creek project financing in July 2011.

Viento Funding II Wind Financing Amendment

In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255 million, which included a $227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5 million seven-year working capital facility. At June 30, 2011, $216 million was outstanding under this loan. The amount of outstanding letters of credit was $23 million. Interest under the term loan accrues at LIBOR plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary. Viento Funding II, Inc. entered into interest rate swap agreements at 3.415% to hedge the majority of the variable interest rate under the term loan. Approximately $84 million under the swap agreements entered in connection with the 2009 financing were left unchanged at 3.175% and were outstanding at June 30, 2011. For further details regarding the interest rate swap agreements, see Note 6—Derivative Instruments and Hedging Activities. In conjunction with the foregoing, EME expensed $3 million of deferred financing costs and incurred a loss of $2 million from the termination of interest rate swaps, included as part of interest expense on the consolidated statement of operations.

Standby Letters of Credit

At June 30, 2011, standby letters of credit under EME's credit facility aggregated $116 million and were scheduled to expire as follows: $39 million in 2011 and $77 million in 2012. The aggregate amount includes $39 million of letters of credit issued for the benefit of the Southern California Edison Company, an affiliate of EME, which is the power purchase agreement counterparty for the Walnut Creek project. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $51 million, $3 million of which was under the Midwest Generation, LLC (Midwest Generation) credit facility, and were scheduled to expire as follows: $7 million in 2011, $16 million in 2012, $10 million in 2017, and $18 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.

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Note 6. Derivative Instruments and Hedging Activities

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

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

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

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

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Notional Volumes of Derivative Instruments

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

June 30, 2011

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

Electricity	Forwards/Futures	Sales	GWh		18,901	¹		17,660	³		39,629
Electricity	Forwards/Futures	Purchases	GWh		203	¹		17,750	³		42,863
Electricity	Capacity	Sales	MW-Day (in thousands)		171	²		—			17	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		17	²		—			247	²
Electricity	Congestion	Sales	GWh		—			124	⁴		14,314	⁴
Electricity	Congestion	Purchases	GWh		—			5,459	⁴		287,221	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			1.5			354.1
Natural gas	Forwards/Futures	Purchases	bcf		—			1.5			351.8
Fuel oil	Forwards/Futures	Sales	barrels		—			—			45,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			240,000			70,000
Coal	Forwards/Futures	Sales	tons		—			—			2,564,250
Coal	Forwards/Futures	Purchases	tons		—			—			2,564,250

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	84	June 2016
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt	Cash flow		110	December 2020
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		120	December 2025
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		67	March 2026

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December 31, 2010

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

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

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

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

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

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Fair Value of Derivative Instruments

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

June 30, 2011

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

Non-trading activities
	Cash flow hedges	$	27		$	2		$	29		$	14		$	34		$	48		$	(19	)
	Economic hedges		60			4			64			51			1			52			12
Trading activities			141			88			229			98			20			118			111

			228			94			322			163			55			218			104
Netting and collateral received¹			(189	)		(31	)		(220	)		(157	)		(32	)		(189	)		(31	)

Total		$	39		$	63		$	102		$	6		$	23		$	29		$	73

December 31, 2010

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

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

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

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

Income Statement Impact of Derivative Instruments

The following table provides the cash flow hedge activity as part of accumulated other comprehensive loss:

	Cash Flow Hedge Activity¹ Six Months Ended June 30,

	Cash Flow Hedge Activity¹ Six Months Ended June 30,						Income Statement Location
(in millions)	2011			2010			Income Statement Location

Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value		(13	)		30
Reclassification to net income		(29	)		(122	)	Operating revenues

End of period derivative gains (losses)	$	(15	)	$	83

¹: Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at June 30, 2011 and 2010 were $(9) million and $50 million, respectively.

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For additional information, see Note 11—Accumulated Other Comprehensive Loss.

The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains (losses) of none and $(7) million during the second quarters of 2011 and 2010, respectively, and $2 million and $1 million during the six months ended June 30, 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.

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

		Three Months Ended 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	2011			2010			2011		2010

Economic hedges	Operating revenues	$	20		$	(3	)	$	26	$	(7	)
	Fuel		(2	)		(2	)		4		(1	)
Trading activities	Operating revenues		41			33			57		80

Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's and its subsidiaries' credit ratings are below investment grade, EME and its subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features was in an asset position at June 30, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. Future increases in power prices could expose EME, Midwest Generation or Edison Mission Marketing & Trading, Inc. (EMMT) to termination payments or additional collateral postings.

Margin and Collateral Deposits

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

(in millions)		June 30, 2011		December 31, 2010


Collateral provided to counterparties
	Offset against derivative liabilities	$	3	$	4
	Reflected in margin and collateral deposits		50		59
Collateral received from counterparties
	Offset against derivative assets		33		52

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Note 7. Income Taxes

Effective Tax Rate

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

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

(in millions)		2011			2010			2011			2010

Income (loss) from continuing operations before income taxes		$	(88	)	$	(90	)	$	(151	)	$	8

Provision (benefit) for income taxes at federal statutory rate of 35%		$	(30	)	$	(31	)	$	(53	)	$	3
Increase (decrease) in income tax from:
	State tax-net of federal provision (benefit) (excludes state tax settlement)		(4	)		(6	)		(9	)		(2	)
	Production tax credits, net		(18	)		(19	)		(36	)		(33	)
	Resolution of 1986-2002 state tax issues		—			(20	)		—			(20	)
	Other		(5	)		6			(4	)		5

Total benefit for income taxes from continuing operations		$	(57	)	$	(70	)	$	(102	)	$	(47	)

Effective tax rate			65%			78%			68%			nm*

*: Not meaningful.

Accounting for Uncertainty in Income Taxes

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

Unrecognized Tax Benefits

There was no change in unrecognized tax benefits from December 31, 2010. As of June 30, 2011 and December 31, 2010, $148 million of the unrecognized tax benefits, if recognized, would impact the effective tax rate.

Edison International's federal income tax returns and California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 remain subject to audit.

The Internal Revenue Service examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included a proposed adjustment related to EME. The EME-related proposed adjustment increases the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $189 million, including interest and

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penalties through June 30, 2011 (the Internal Revenue Service has asserted a 40% penalty for understatement of tax liability related to this matter). Edison International disagrees with the proposed adjustment and filed a protest with the Internal Revenue Service in the first quarter of 2011. The disputed tax matter is currently being considered in appeals.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to EME's income tax liabilities was $36 million and $32 million as of June 30, 2011 and December 31, 2010, respectively.

The net after-tax interest expense (income) and penalties recognized in income tax expense was $2 million and $(8) million for the three months ended June 30, 2011 and 2010, respectively, and $3 million and $(6) million for the six months ended June 30, 2011 and 2010, respectively.

Bonus Depreciation Impact on EME

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

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the six months ended June 30, 2011, EME made contributions of $7 million, and during the remainder of 2011, expects to make $13 million of additional contributions.

The following were components of pension expense:

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

(in millions)	2011			2010			2011			2010

Service cost	$	5		$	4		$	9		$	8
Interest cost		3			4			7			7
Expected return on plan assets		(3	)		(3	)		(6	)		(5	)
Amortization of net loss		1			—			2			1

Total expense	$	6		$	5		$	12		$	11

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Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2011, EME made contributions of $1 million, and during the remainder of 2011, expects to make $1 million of additional contributions.

The following were components of postretirement benefits expense:

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

(in millions)	2011		2010			2011		2010

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

Total expense	$	2	$	1		$	5	$	3

Note 9. Commitments and Contingencies

Commitments

Fuel Supply Contracts

At June 30, 2011, Midwest Generation and EME Homer City Generation L.P. (Homer City) had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. These commitments are estimated to aggregate $634 million, summarized as follows: $277 million for the remainder of 2011, $304 million in 2012 and $53 million in 2013. In July 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments are estimated to be $6 million for the remainder of 2011, $28 million for 2012, $145 million for 2013, and $150 million for 2014.

Turbine Commitments

At June 30, 2011, EME had commitments to purchase wind turbines of $45 million due in 2011 and $8 million due in 2012. Based on a June 2011 contract amendment, EME's failure to schedule turbine delivery by September 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $29 million charge against earnings. EME has identified a project in which to place these turbines. However, there is no assurance that development will be completed and the turbines will be used for this project.

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

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Capital Expenditures

At June 30, 2011, EME's subsidiaries had firm commitments to spend approximately $242 million during the remainder of 2011, $205 million in 2012 and $19 million in 2013 on capital and construction expenditures. These expenditures primarily relate to the Walnut Creek project, selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants, and the construction of wind projects. EME intends to fund these expenditures through project level financing, U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from operations.

Guarantees and Indemnities

EME and certain of its subsidiaries have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.

Environmental Indemnities Related to the Midwest Generation Plants

In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company (Commonwealth Edison) with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. 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. These indemnities are not limited in term or amount. 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 and Other Litigation." 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 Midwest Generation's 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. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 222 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at June 30, 2011. Midwest Generation had recorded a liability of $55 million at June 30, 2011 related to this contractual indemnity.

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

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Environmental Indemnity Related to the Homer City Plant

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

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. At June 30, 2011, EME had recorded a liability of $45 million related to these matters.

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

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

Other Indemnities

EME provides other indemnifications through contracts entered into in the normal course of business. These include, among other things, indemnities for specified environmental liabilities and for income taxes with respect to assets sold. EME's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances EME may have recourse against third parties. EME has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.

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Contingencies

In addition to the matters disclosed in these notes, EME is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. EME believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.

Midwest Generation New Source Review and Other Litigation

In August 2009, the United States Environmental Protection Agency (US EPA) and the State of Illinois filed a complaint in the Northern District of Illinois alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration (PSD) requirements and of the New Source Performance Standards of the Clean Air Act (CAA), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology (BACT) emission rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard (CPS). Several Chicago-based environmental action groups have intervened in the case.

Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013.

In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages.

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

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Homer City New Source Review and Other Litigation

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

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

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

Environmental Remediation

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

With respect to potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $7 million at June 30, 2011 for estimated environmental investigation and remediation costs for the Midwest Generation plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that require remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified.

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Note 10. Environmental Developments

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted its final Cross-State Air Pollution Rule (CSAPR) which will replace the Clean Air Interstate Rule (CAIR) beginning on January 1, 2012. CSAPR is the final form of a previously proposed replacement for the CAIR, called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide (SO₂) emissions and annual and ozone season nitrogen oxide (NO_x) emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO₂ emissions.

CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO₂ or NO_x emissions from operations will need to be matched by a sufficient amount of SO₂ or NO_x allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO₂ and NO_x allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual compliance period, units must surrender allowances for each ton of SO₂ and NO_x emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for enhanced penalties against a unit that surrenders allowances in excess of certain predefined limits for itself and for the state in which it is located.

The installation of SO₂ controls will require capital commitments for the Midwest Generation plants well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. EME believes that Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR. However, the SO₂ allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO₂ emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether SO₂ allowances in sufficient quantity and at prices that Homer City can pass through in power prices will be available in 2012 and 2013. Also, Homer City's SO₂ shortfall is expected to exceed limits on the number of allowances it will be permitted to surrender, and, therefore, may subject Homer City to penalties in certain cases. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel switching, for complying with Phase I of CSAPR. Failure by Homer City to develop and implement a Phase I compliance plan based on allowances could result in its modifying operations at one or more units or significantly curtailing power output. The cost of allowances, together with possible operational impacts or reductions of output, which may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.

Homer City has begun work on designing SO₂ and particulate emissions control equipment for Units 1 and 2. While the Phase II SO₂ emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO₂ controls at Units 1 and 2. The installation of those SO₂ controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer

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City is continuing to review technologies available to reduce SO₂ and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million.

Homer City does not currently have sufficient capital and does not expect to generate sufficient capital from operations to fund such retrofits and will have to seek financing, which will be subject to decisions by Homer City's lessors, holders of the pass-through certificates and new providers of capital funding. There is no assurance that sufficient financing will be obtained or will not result in significant dilution of Homer City's interest in the Homer City plant.

Proposed Hazardous Air Pollutant Regulations

In March 2011, the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. This regulation is expected to be finalized by November 2011. Based on its continuing review, EME does not expect that these standards, if adopted as proposed, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. EME also does not expect that these standards, if adopted as proposed, would require Homer City to make additional capital requirements beyond those that would be required to comply with CSAPR.

Water Quality—Clean Water Act

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

Greenhouse Gas Litigation Developments

In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions it authorizes displace federal common law nuisance claims that might arise from of the emission of greenhouse gases. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.

Parties to the Kivalina case, the appeal of which was deferred before the Ninth Circuit Court of Appeals pending the Supreme Court's ruling described above, have requested that the appeal recommence and have asked for permission to file additional briefs on the impact of the Supreme Court's ruling. The Kivalina case was brought by the Alaskan Native Village of Kivalina seeking damages of up to $400 million for the cost of relocating the village because the plaintiffs claim that the

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Arctic ice that has protected the village is melting as a result of climate change. The federal district court dismissed the case against Edison International and the other defendants in October 2009. Due to the nature of these potential obligations, EME is unable to estimate the potential liability, if any.

On May 27, 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming among a large number of defendants, Edison International, EME, and three wholly owned subsidiaries of EME (Edison Mission Energy Fuel, Edison Mission Energy Petroleum, and Edison Mission Energy Services). Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.

Note 11. Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss consisted of the following:

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


Balance at December 31, 2010		$	16		$	(47	)	$	(31	)
	Current period change		(25	)		1			(24	)

Balance at June 30, 2011		$	(9	)	$	(46	)	$	(55	)

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

Included in accumulated other comprehensive loss at June 30, 2011 was $4 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $13 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is May 31, 2014.

Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $8 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

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Note 12. Supplemental Cash Flows Information

		Six Months Ended June 30,

(in millions)		2011		2010

Cash paid (received)
	Interest (net of amount capitalized)¹	$	142	$	142
	Income taxes		6		(68	)
	Cash payments under plant operating leases		189		197
Non-cash activities from consolidation of variable interest entity
	Assets	$	—	$	94
	Liabilities		—		99
Non-cash activities from deconsolidation of variable interest entities
	Assets	$	—	$	249
	Liabilities		—		253
Non-cash activities from accrued capital expenditures		$	47	$	47
Purchase of equipment with notes payable		$	56	$	—

¹: Interest paid for the six months ended June 30, 2011 was $158 million. Interest capitalized for the six months ended June 30, 2011 and 2010 was $16 million and $23 million, respectively.

Note 13. Discontinued Operations

Summarized financial information for discontinued operations is as follows:

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

(in millions)	2011			2010		2011			2010

Income (loss) before income taxes	$	—		$	4	$	(2	)	$	15
Provision for income taxes		1			1		1			6

Income (loss) from operations of discontinued foreign subsidiaries	$	(1	)	$	3	$	(3	)	$	9

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

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

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

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

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ability of EME and its subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;

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

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in "Item 1A. Risk Factors" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010. Readers are urged to read this entire quarterly report on Form 10-Q and the annual report on Form 10-K for the year ended December 31, 2010, including the information incorporated by reference, and to carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2010, and as compared to the second quarter of 2010 and the six months ended June 30, 2010. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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MANAGEMENT'S OVERVIEW

Introduction

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

Highlights of Operating Results

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

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

(in millions)		2011			2010			Change			2011			2010		Change

Net income (loss) attributable to EME common shareholder		$	(32	)	$	(17	)	$	(15	)	$	(52	)	$	64	$	(116	)

Non-Core Items
	Income (loss) from discontinued operations		(1	)		3			(4	)		(3	)		9		(12	)
	Settlement of tax disputes		—			20			(20	)		—			20		(20	)

	Total non-core items		(1	)		23			(24	)		(3	)		29		(32	)

Core Earnings (Losses)			(31	)		(40	)		9			(49	)		35		(84	)

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

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

•: $26 million higher income from a distribution received from the Doga project during the second quarter of 2011, with no comparable amount in 2010.
•: $10 million increase in energy trading revenues due to higher congestion and power trading revenues.
•: $5 million increase in renewable energy adjusted operating income due to the increase in wind projects in operation and higher generation from existing wind projects.

These increases were partially offset by the following:

•: $13 million decrease in Midwest Generation adjusted operating income due to lower average realized energy prices and higher operating expenses due primarily to planned plant outages, partially offset by higher capacity revenues.
•: $10 million decrease in Homer City adjusted operating income due mostly to higher operating expenses primarily resulting from plant outages and higher coal costs. Partially offsetting the decrease were unrealized derivative gains of $2 million in 2011 compared to losses of $12 million in 2010.
•: $14 million increase in interest expense due to higher interest related to renewable project financings of $8 million and lower capitalized interest of $6 million.

EME's core earnings for the six months ended June 30, 2011 were lower than core earnings for the six months ended June 30, 2010 primarily due to the following pre-tax items:

•: $45 million decrease in Midwest Generation adjusted operating income due to lower average realized energy prices, lower generation and higher operating expenses, partially offset by higher capacity revenues.
•: $63 million decrease in Homer City adjusted operating income due primarily to lower generation and higher operating expenses resulting from the Unit 1 and 2 outages. Unit 1 returned to service on April 5, 2011, and Unit 2 returned to service on May 25, 2011. In addition, partially offsetting the decrease were unrealized derivative gains of $5 million in 2011 compared to losses of $14 million in 2010.
•: $26 million increase in interest expense due to higher interest expense related primarily to renewable energy projects financings of $19 million and lower capitalized interest of $7 million.
•: $22 million decrease in energy trading revenue due to lower congestion and power trading revenues.

These decreases were partially offset by the following:

•: $16 million increase in renewable energy adjusted operating income due to the increase in wind projects in operation coupled with higher generation.

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Non-core item for EME included:

•: An earnings benefit of $20 million recorded in the second quarter of 2010 related to the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002 as part of the federal settlement of tax disputes and a revision to the interest on federal disputed tax items.

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted its final Cross-State Air Pollution Rule (CSAPR) which will replace the CAIR beginning on January 1, 2012. CSAPR is the final form of a previously proposed replacement for the CAIR, called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual SO₂ emissions and annual and ozone season NO_x emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO₂ emissions.

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controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO₂ and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million.

Homer City Capital Needs

Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete retrofits effectively required by CSAPR Phase II. EME is under no legal obligation to provide funding and has chosen not to. Accordingly, Homer City will need third-party capital to undertake the retrofits required by 2014 under CSAPR. However, restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Consequently, the installation of environmental compliance equipment will be dependent on lessors, holders of the pass-through certificates and new providers of capital funding. Homer City has commenced discussions with its lessors concerning such matters. There can be no assurance that Homer City will be able to raise the financing necessary to install the required SO₂ control equipment in a timely manner or on terms that will not result in a significant dilution of its interest in the Homer City plant.

Failure of Homer City to install the required equipment or determine an economic manner to continue plant operations could result in a loss of its lease and a cessation of plant operations. Cessation of plant operations or a significant reduction of the value of Homer City's interest in the plant could have a material adverse effect on future financial results, cash flow, financial flexibility and assets of EME compared to historical levels. At June 30, 2011, the book value of EME's investment in Homer City was approximately $1.1 billion.

Midwest Generation Environmental Compliance Plans and Costs

During 2011, Midwest Generation continued its permitting and planning activities for NO_x and SO₂ controls to meet the requirements of the CPS. Based on its continuing review, EME also does not expect the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NO_x and SO₂ as well as for hazardous air pollutants, such as mercury, acid gas and non-mercury metals. Based on stack tests performed at various Midwest Generation plants, Midwest Generation believes that currently installed activated carbon injection and particulate removal equipment is

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sufficient to achieve or exceed the mercury standards outlined in the US EPA's existing and proposed rules. Midwest Generation does not anticipate a material change to its current approach in order to comply with CSAPR.

In February 2011, the Illinois Environmental Protection Agency issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or other sodium-based sorbents at the Powerton Station's Units 5 and 6. Midwest Generation had previously received construction permits for dry sorbent injection installation at Waukegan Station's Unit 7.

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

Therefore, decisions about any particular combination of retrofits and shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. 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, subject to the requirements of the CPS and other applicable regulations.

Walnut Creek Project

In March 2008, Walnut Creek Energy, a subsidiary of EME, was awarded a 10-year power sales agreement starting in 2013 for the output from its planned Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The contract was issued by Southern California Edison Company, through a competitive bidding process. Construction began on the Walnut Creek project in June 2011. The Walnut Creek project has estimated construction costs of $575 million and is expected to achieve commercial operation in 2013. In July 2011, Walnut Creek Energy completed non-recourse financings to fund the Walnut Creek project. The Walnut Creek construction loans, including the project level and intermediate holding company loans, have an effective interest rate of 3.11% including the impact of the interest rate swaps through May 31, 2013. For more information, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek."

EME's Liquidity

At June 30, 2011, EME, as a holding company, had cash and cash equivalents of $237 million to meet liquidity needs as well as $448 million of capacity under its credit facility. EME's subsidiary, EMMT, also had cash and cash equivalents of $195 million at June 30, 2011, which can be loaned or distributed to EME subject to applicable laws. In addition, at June 30, 2011, Midwest Generation had cash and cash equivalents of $254 million to meet liquidity needs.

Midwest Generation has not yet committed to the completion of environmental compliance activities for its plants. Additional expenditures for NO_x and SO₂ controls through 2013 are estimated at $535 million based on an assumption that Midwest Generation would retrofit all units over the compliance period, which extends to 2018. Depending upon the facilities selected to be retrofitted, the cost of such retrofitting, and the timing of funding requirements beyond the near term, Midwest Generation may utilize operating cash flow, draw on its credit facilities to the extent these are available when funding is required, or seek debt financing to fund capital expenditures.

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Capital expenditures to complete Walnut Creek and various renewable energy projects for the remainder of 2011 are projected to be $290 million at June 30, 2011. In July, EME secured $495 million in construction and term financing for the Walnut Creek project. In addition, EME used the proceeds of the Laredo Ridge U.S. Treasury grant of $57 million received in July 2011 to repay the Laredo Ridge bridge loan. EME anticipates that the capital investment for renewable energy projects under construction will be funded using a combination of construction and term financings, U.S. Treasury grants and cash on hand. In addition to the U.S. Treasury grant received in July, U.S. Treasury grants of approximately $360 million are anticipated in 2011 and 2012 based on estimated eligible construction costs for renewable projects.

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

For information regarding liquidity, see "Liquidity and Capital Resources—Dividend Restrictions in Major Financings" and refer to "Liquidity Risks" in Item 1A on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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RESULTS OF OPERATIONS

Results of Continuing Operations

Overview

EME operates in one line of business, independent power production. The following section and table provide a summary of results of EME's operating projects and corporate expenses for the second quarters of 2011 and 2010 and six months ended June 30, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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

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

(in millions)	2011			2010			2011			2010

Midwest Generation plants	$	(52	)	$	(39	)	$	3		$	48
Homer City plant¹		(10	)		—			(26	)		37
Renewable energy projects		24			19			45			29
Energy trading¹		41			31			56			78
Big 4 projects		9			12			11			16
Sunrise		6			7			(1	)		3
Doga		26			—			26			15
March Point²		—			—			—			17
Westside projects		(1	)		—			(1	)		1
Other projects		5			3			9			6
Other operating income (expense)		1			(1	)		1			1

		49			32			123			251
Corporate administrative and general		(32	)		(34	)		(66	)		(70	)
Corporate depreciation and amortization		(6	)		(4	)		(12	)		(8	)

AOI³	$	11		$	(6	)	$	45		$	173

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

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

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

(in millions)		2011			2010			2011			2010

AOI		$	11		$	(6	)	$	45		$	173
Less:
	Equity in income of unconsolidated affiliates		17			20			12			37
	Dividend income from projects		27			1			28			17
	Production tax credits		19			19			37			33
	Other income, net		2			—			5			2

Operating Income (Loss)		$	(54	)	$	(46	)	$	(37	)	$	84

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)			2011			2010			2011		2010

Operating Revenues			$	280		$	281		$	631	$	660
Operating Expenses
	Fuel¹			107			98			233		239
	Plant operations			164			167			282		265
	Plant operating leases			18			18			37		37
	Depreciation and amortization			29			28			58		56
	Asset retirements			9			2			9		3
	Administrative and general			5			7			11		12

	Total operating expenses			332			320			630		612

Operating Income (Loss)				(52	)		(39	)		1		48

Other Income				—			—			2		—

AOI			$	(52	)	$	(39	)	$	3	$	48

Statistics²
	Generation (in GWh)			5,560			5,430			13,030		13,642
	Aggregate plant performance
		Equivalent availability		63.7%			59.8%			75.3%		72.7%
		Capacity factor		49.3%			45.5%			58.1%		57.5%
		Load factor		77.4%			76.2%			77.2%		79.1%
		Forced outage rate		5.0%			10.4%			5.1%		8.2%
	Average realized price/MWh		$	37.59		$	41.50		$	37.05	$	40.31
	Capacity revenues only (in millions)		$	68		$	58		$	145	$	105
	Average realized fuel costs/MWh		$	18.88		$	17.55		$	17.65	$	16.99

¹: Included in fuel costs were $0.4 million and $1 million during the second quarters of 2011 and 2010, respectively, and $2 million and $5 million during the six months ended June 30, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NO_x emission allowances

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: to Midwest Generation were $0.4 million during each of the six months ended June 30, 2011 and 2010. Transfers of SO₂ emission allowances from Midwest Generation were none and $5 million during the six months ended June 30, 2011 and 2010, respectively. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."
²: For an explanation of how the statistical data is determined, see "Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions."

AOI from the Midwest Generation plants decreased $13 million for the second quarter ended June 30, 2011, compared to the corresponding period of 2010. The second quarter decrease in AOI was attributable to lower energy revenues, higher fuel costs and higher operating expenses, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices, partially offset by higher generation. The increase in fuel costs was due to higher generation and higher coal costs. The increase in operating expenses was due to higher maintenance and overhauls, including the retirement of equipment that was replaced as part of overhauls.

AOI from the Midwest Generation plants decreased $45 million for six months ended June 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues and higher plant operations costs, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation due to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS.

Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(3) million for the second quarters of 2011 and 2010, respectively, and $2 million and $4 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized gains (losses) in 2011 and 2010 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at the Midwest Generation plants was attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system).

Included in fuel costs were unrealized losses of $1 million and $2 million during the second quarters of 2011 and 2010, respectively, and $2 million and $7 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized losses were due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.

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Homer City

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

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

(in millions)		2011			2010		2011			2010

Operating Revenues¹		$	136		$	129	$	251		$	304
Operating Expenses
	Fuel²		63			57		115			127
	Plant operations		50			38		97			75
	Plant operating leases		26			27		51			52
	Depreciation and amortization		5			4		10			9
	Asset retirements		—			1		—			1
	Administrative and general		2			2		4			3

	Total operating expenses		146			129		277			267

Operating Income (Loss)			(10	)		—		(26	)		37

AOI		$	(10	)	$	—	$	(26	)	$	37

Statistics³
	Generation (in GWh)		2,226			2,289		4,169			5,243
	Equivalent availability		66.6%			64.5%		63.0%			72.3%
	Capacity factor		54.1%			55.5%		50.9%			63.9%
	Load factor		81.2%			86.0%		80.9%			88.4%
	Forced outage rate		15.3%			14.1%		21.3%			12.1%
	Average realized energy price/MWh	$	48.98		$	48.78	$	47.21		$	49.57
	Capacity revenues only (in millions)	$	24		$	29	$	48		$	58
	Average fuel costs/MWh	$	28.22		$	25.08	$	27.63		$	24.23

¹: Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.
²: Included in fuel costs were $0.3 million and $1 million during the second quarters of 2011 and 2010, respectively, and $1 million and $5 million during the six months ended June 30, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO₂ emission allowances to Homer City were none and $5 million during the six months ended June 30, 2011 and 2010, respectively. Transfers of NO_x emission allowances from Homer City were $0.4 million during each of the six months ended June 30, 2011 and 2010. For more information regarding the price of emission allowances, see "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."
³: For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions."

AOI from the Homer City plant decreased $10 million for the second quarter ended June 30, 2011, compared to the corresponding period of 2010. The second quarter decrease in AOI was attributable to higher plant maintenance costs from outages at Units 1 and 2 and higher coal costs, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts.

AOI from the Homer City plant decreased $63 million for six months ended June 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues driven by lower generation and energy prices, and higher plant maintenance costs from outages at Units 1 and 2, partially offset by unrealized gains in 2011 compared to unrealized losses in

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2010 related to hedge contracts and lower fuel costs. The decline in fuel costs was due to lower generation, partially offset by higher coal costs.

Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(12) million for the second quarters of 2011 and 2010, respectively, and $5 million and $(14) million for the six months ended June 30, 2011 and 2010, respectively. Unrealized gains in 2011 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. Unrealized losses in 2010 were attributable to the ineffective portion of forward and futures contracts. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).

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

Average Realized Energy Price

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

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

Midwest Generation Plants (in millions)		Three Months Ended June 30,						Six Months Ended June 30,
Midwest Generation Plants (in millions)		2011			2010			2011			2010

Operating revenues		$	280		$	281		$	631		$	660
Less:
	Unrealized (gains) losses		(2	)		3			(2	)		(4	)
	Capacity and other revenues		(69	)		(58	)		(146	)		(106	)

Realized revenues		$	209		$	226		$	483		$	550

Generation (in GWh)			5,560			5,430			13,030			13,642
Average realized energy price/MWh		$	37.59		$	41.50		$	37.05		$	40.31

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

Homer City Plant (in millions)		Three Months Ended June 30,						Six Months Ended June 30,
Homer City Plant (in millions)		2011			2010			2011			2010

Operating revenues		$	136		$	129		$	251		$	304
Less:
	Unrealized (gains) losses		(2	)		12			(5	)		14
	Capacity and other revenues		(24	)		(29	)		(49	)		(58	)

Realized revenues		$	110		$	112		$	197		$	260

Generation (in GWh)			2,226			2,289			4,169			5,243
Average realized energy price/MWh		$	48.98		$	48.78		$	47.21		$	49.57

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The average realized energy price is presented as an aid in understanding the operating results of the coal plants. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the operating revenues of the coal plants presented in the preceding table and renewable energy projects presented in "—Renewable Energy Projects" to consolidated operating revenues is set forth below:

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

(in millions)		2011		2010		2011		2010

Operating revenues
	Midwest Generation plants	$	280	$	281	$	631	$	660
	Homer City plant		136		129		251		304
	Renewable energy projects		59		34		111		64
	Other revenues		61		49		93		116

Consolidated operating revenues as reported		$	536	$	493	$	1,086	$	1,144

Average Realized Fuel Costs

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

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

Midwest Generation Plants (in millions)		Three Months Ended June 30,						Six Months Ended June 30,
Midwest Generation Plants (in millions)		2011			2010			2011			2010

Fuel costs		$	107		$	98		$	233		$	239
Less:
	Unrealized losses		(1	)		(2	)		(2	)		(7	)

Realized fuel costs		$	106		$	96		$	231		$	232

Generation (in GWh)			5,560			5,430			13,030			13,642
Average realized fuel costs/MWh		$	18.88		$	17.55		$	17.65		$	16.99

The average realized fuel costs are presented as an aid in understanding the operating results of the Midwest Generation plants. Average realized fuel costs are a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel costs. Management believes that average realized fuel costs are meaningful for investors as this information reflects the impact of

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hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the fuel costs of the coal plants to consolidated fuel costs is set forth below:

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

(in millions)		2011		2010		2011		2010

Fuel costs
	Midwest Generation plants	$	107	$	98	$	233	$	239
	Homer City plant		63		57		115		127
	Other		4		6		8		8

Consolidated fuel costs as reported		$	174	$	161	$	356	$	374

Statistical Definitions

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

Seasonality—Coal Plants

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

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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)			2011		2010		2011		2010

Operating Revenues			$	59	$	34	$	111	$	64
Production Tax Credits				19		19		37		33

				78		53		148		97

Operating Expenses
	Plant operations			18		12		36		24
	Depreciation and amortization			37		22		68		43
	Administrative and general			1		—		2		1

	Total operating expenses			56		34		106		68
Equity in income (loss) from unconsolidated affiliates				1		—		1		(1	)
Other Income				1		—		2		1

AOI¹			$	24	$	19	$	45	$	29

Statistics²
	Generation (in GWh)³			1,555		992		2,940		1,835
	Aggregate plant performance³
		Equivalent availability		93.3%		90.9%		93.7%		90.8%
		Capacity factor		41.0%		38.5%		39.5%		35.8%

¹: AOI is equal to operating income (loss) under GAAP plus equity in income (losses) of unconsolidated affiliates, production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects.
²: The statistics section summarizes key performance measures related to wind projects, which represents substantially all of the renewable energy projects.
³: Includes renewable energy projects that are unconsolidated at EME. Generation excluding unconsolidated projects was 1,336 GWh and 821 GWh in the second quarter of 2011 and 2010, respectively, and 2,536 GWh and 1,512 GWh in the six months ended June 30, 2011 and 2010, respectively.

AOI from renewable energy projects increased $5 million and $16 million in the second quarter and six months ended June 30, 2011, respectively, compared to the corresponding periods of 2010. The 2011 increases were primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions.

Energy Trading

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

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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 $10 million and decreased $22 million for the second quarter and six months ended June 30, 2011, compared to the corresponding periods of 2010. The second quarter and year-to-date variances were attributable to fluctuations in revenues from congestion and power trading, compared to the same prior-year periods.

Adjusted Operating Income from Unconsolidated Affiliates

Doga. EME received a distribution from the Doga project in the second quarter of 2011 and in the first quarter of 2010. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.

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

Kern River. Kern River Cogeneration Company has entered into an extension of its power purchase agreement with Southern California Edison Company, which was set to expire in June 2011. EME expects that this arrangement will eventually be replaced by a new power purchase agreement, but cannot predict whether a new agreement will be reached on acceptable terms or at all.

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

Interest Income (Expense)

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

(in millions)		2011			2010			2011			2010

Interest income		$	—		$	1		$	1		$	2

Interest expense, net of capitalized interest
	EME debt	$	(63	)	$	(58	)	$	(125	)	$	(118	)
	Non-recourse debt		(17	)		(8	)		(35	)		(16	)

		$	(80	)	$	(66	)	$	(160	)	$	(134	)

EME's interest expense increased primarily due to higher debt balances for wind project financing and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $6 million and $16 million for the second quarter and six months ended June 30, 2011, respectively, compared to $12 million and $23 million for the second quarter and six months ended June 30, 2010, respectively.

Income Taxes

Income taxes for the six months ended June 30, 2011 and 2010 included production tax credits of $37 million and $33 million, respectively. EME's income taxes from continuing operations during the

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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. For a discussion of the status of Edison International's income tax audits, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 7. Income Taxes."

New Accounting Guidance

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

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at June 30, 2011:

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


EME as a holding company		$	237	$	448	$	685
EME subsidiaries without contractual dividend restrictions			195		—		195

EME corporate cash and cash equivalents			432		448		880
EME subsidiaries with contractual dividend restrictions
	Midwest Generation¹		254		497		751
	Homer City		61		—		61
	Other EME subsidiaries		86		—		86

Total		$	833	$	945	$	1,778

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

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

The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2011, which mature in June 2012:

(in millions)	EME			Midwest Generation


Commitments	$	564		$	500
Outstanding borrowings		—			—
Outstanding letters of credit		(116	)		(3	)

Amount available	$	448		$	497

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

Homer City Outage

During the first half of 2011, Homer City Units 1 and 2 were off line due to a steam pipe rupture at Unit 1 and precautionary maintenance at Unit 2. While Unit 1 returned to service on April 5, 2011 and Unit 2 on May 25, 2011, the outages and the continuation of low power prices have impacted Homer City's liquidity. As a result, in order to have sufficient working capital available for operating expenses

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and to pay the equity portion of Homer City's rent payment that was due April 1, 2011 to the owner-lessors, Homer City had to defer certain fuel deliveries, arrange for accelerated payments by EMMT for future energy deliveries under an intercompany arrangement in place between EMMT and Homer City, and draw $12 million from the $20 million equity rent reserve established under its sale-leaseback transaction documents. Homer City must restore the equity rent reserve account and continue to make equity rent payments in order to be entitled to make future distributions. Homer City anticipates that the equity rent reserve balance will be restored in the future. At June 30, 2011, the equity rent reserve balance remained at the drawn balance of $8 million, but Homer City had delivered energy sufficient to eliminate the accelerated payments by EMMT. Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, since April 1, 2011, these revenues have been recorded as part of Homer City's revenues in lieu of their prior classification as EMMT trading revenues. EMMT realized trading revenues of $28 million under this arrangement in 2010.

The actions described above also resulted in Homer City being in compliance with the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2011. Under these documents, rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to holders of senior secured bonds issued in connection with the sale-leaseback transaction, while equity rent is paid to the owner-lessors. In order to pay equity rent, among other requirements, Homer City is required to meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. For additional discussion regarding Homer City's liquidity, see "Management Overview—Cross-State Air Pollution Rule" and "—Homer City Capital Needs."

Bonus Depreciation Impact on EME

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

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Capital Investment Plan

At June 30, 2011, forecasted capital expenditures through 2013 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		July through December 2011		2012		2013


Midwest Generation Plants
	Environmental¹	$	49	$	172	$	317
	Plant capital		11		21		28
Homer City Plant
	Environmental¹		—		—		—
	Plant capital		5		26		16
Walnut Creek Project			173		257		43
Renewable Energy Projects
	Capital and construction		72		—		—
	Turbine commitments		45		8		—
Other capital			7		14		14

Total		$	362	$	498	$	418

¹: For additional information, see "Management's Overview—Cross-State Air Pollution Rule."

Environmental Capital Expenditures

Midwest Generation plants' environmental expenditures include $34 million for remaining expenditures in 2011 related to selective non-catalytic reduction (SNCR) equipment and $501 million for expenditures for the remainder of 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO₂ emissions. EME believes Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR and the proposed National Emission Standards for Hazardous Air Pollutants. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS and other requirements, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project. For additional discussion, see "Management's Overview—Midwest Generation Compliance Plans and Costs."

The capital investment plan set forth in the previous table does not include environmental capital expenditures that Homer City will be required to undertake to meet the requirements of CSAPR. The timing, selection of technology and ultimate capital costs remain uncertain. For a discussion of environmental regulations, see "Management's Overview—Cross-State Air Pollution Rule," "Management's Overview—Homer City Capital Needs," and refer to "Environmental Matters and Regulations" in Item 1 on page 19 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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Plant Capital Expenditures

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

Walnut Creek Project Expenditures

For information on the Walnut Creek project and the related asset purchase, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek."

Renewable Energy Projects

In the second quarter of 2011, EME acquired and commenced construction on the 55 MW Pinnacle wind project. The Community Wind North wind project achieved commercial operation on May 28, 2011, and the Taloga wind project achieved commercial operation on July 13, 2011.

The capital investment plan set forth in the previous table does not include capital expenditures for future projects. At June 30, 2011, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 3,900 MW. The development pipeline represents potential wind projects with respect to which EME either owns the project rights or has exclusive acquisition rights. The pace of additional growth in EME's renewable program will be subject to the availability of third-party equity capital. At June 30, 2011, EME had capitalized costs and turbine deposits totaling $53 million related to renewable energy development efforts. To the extent that the renewable energy projects are not successful, EME would record a charge to write down the carrying amount of these assets.

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)	2011			2010

Operating cash flow from continuing operations	$	(92	)	$	159
Operating cash flow from discontinued operations		(3	)		9

Net cash provided by operating activities		(95	)		168
Net cash provided by financing activities		96			37
Net cash used in investing activities		(243	)		(294	)

Net decrease in cash and cash equivalents	$	(242	)	$	(89	)

Consolidated Cash Flows from Operating Activities

The decrease in the first six months of 2011 as compared to the first six months of 2010 in cash provided by operating activities from continuing operations was primarily attributable to lower net income, $92 million of U.S. Treasury grants received in 2010, and changes in other current liabilities.

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Consolidated Cash Flows from Financing Activities

The increase in the first six months of 2011 as compared to the first six months of 2010 in cash provided by financing activities from continuing operations was primarily attributable to additional wind project borrowings.

Consolidated Cash Flows from Investing Activities

Cash used in investing activities for the first six months of 2011 and 2010 primarily consisted of capital expenditures. In addition, cash used in investing activities for the first six months of 2011 included wind and gas project investments and other capital expenditures.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of June 30, 2011 were as follows:

	Moody's Rating	S&P Rating	Fitch Rating


EME¹	Caa1	B-	CCC
Midwest Generation²	Ba3	B+	BB-
EMMT	Not Rated	B-	Not Rated

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

On June 29, 2011, Moody's lowered the credit ratings of EME to Caa1 from B3 and Midwest Generation to Ba3 from Ba2. On June 30, 2011, Fitch lowered the credit ratings of EME to CCC from B- and Midwest Generation to BB- from BB. All the above ratings are on negative outlook. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

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

Credit Rating of EMMT

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

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Margin, Collateral Deposits and Other Credit Support for Energy Contracts

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

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2011, if wholesale energy prices change or if EMMT enters into additional transactions. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings."

EME's Liquidity as a Holding Company

EME's Credit Facility Financial Ratios

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility. The following details of EME's interest coverage ratio and a maximum corporate-debt-to-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements. At June 30, 2011, EME and its subsidiaries were in compliance with the terms of their debt covenants.

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

			12 Months Ended

(in millions)			June 30, 2011			December 31, 2010

Funds Flow Available for Interest
	Distributions
		Midwest Generation	$	155		$	125
		Homer City		52			74
		Big 4 projects		65			77
		U.S. Treasury grants		—			92
		Renewable energy projects¹		295			223
		Other projects		45			63
	Tax payments received from subsidiaries			139			136
	Realized trading income			101			120
	Tax-allocation receipts (payments)²			15			90
	Operating expenses			(131	)		(139	)
	Other items, net³			(15	)		(56	)

			$	721		$	805

Net Interest Expense
	EME corporate debt		$	234		$	223
	Addback: Capitalized interest			49			54
	Powerton-Joliet intercompany notes			111			112

			$	394		$	389

Ratio				1.83			2.07
Covenant threshold (not less than)				1.20			1.20

¹: Includes $232 million of proceeds from the Cedro Hill, Laredo Ridge, High Lonesome and Viento II wind projects financings during 2010 and 2011 and distributed to EME during the 12 months ended June 30, 2011.
²: Excludes production tax credits for Viento Funding II, Inc.
³: Excludes certain state tax payments which are classified in other items, net.

The Small Business Jobs Act of 2010 and the 2010 Tax Relief Act provisions are expected to impact the timing of tax-allocation payments. For additional discussion of the impact, see "—Available Liquidity—Bonus Depreciation Impact on EME."

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

(in millions)			June 30, 2011			December 31, 2010


Corporate Debt
	Indebtedness for money borrowed		$	3,700		$	3,700
	Powerton-Joliet termination value			882			933
	Letters of credit			119			83

			$	4,701		$	4,716

Corporate Capital
	Common shareholder's equity		$	2,737		$	2,842
	Less:
		Non-cash cumulative changes in accounting		(9	)		(9	)
		Accumulated other comprehensive loss		55			31
	Adjustments:
		After-tax losses incurred on termination of Collins lease		587			587
		Dividend to Mission Energy Holding Company for repayment of 13.5% notes		899			899

				4,269			4,350

	Corporate debt			4,701			4,716

			$	8,970		$	9,066

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

Dividend Restrictions in Major Financings

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at June 30, 2011 or for the 12 months ended June 30, 2011:

Subsidiary	Financial Ratio	Covenant


Midwest Generation (Midwest Generation plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.14 to 1
Homer City (Homer City plant)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	1.75 to 1

To make distributions, including repayment of certain intercompany loans, Homer City must meet the senior rent service coverage ratio. In addition, Homer City is restricted from making distributions until the Homer City equity reserve account is replenished. For additional information, see "—Available Liquidity—Homer City Outage."

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" in Item 7 on page 64 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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

EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At June 30, 2011, the maximum permissible sale or disposition of EME assets is calculated as follows:

(in millions)


Consolidated Net Tangible Assets
	Total consolidated assets		$	9,493
	Less:
		Consolidated current liabilities		536
		Intangible assets		82

			$	8,875

10% Threshold			$	888

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

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

Contractual Obligations and Contingencies

Fuel Supply Contracts

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

Capital Expenditures

For a discussion of capital expenditures, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Commitments—Capital Expenditures."

Midwest Generation New Source Review and Other Litigation

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

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Homer City New Source Review and Other Litigation

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

Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 on page 68 of EME's annual report on Form 10-K for the year ended December 31, 2010. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report.

Environmental Matters and Regulations

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

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MARKET RISK EXPOSURES

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

Derivative Instruments

Unrealized Gains and Losses

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

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

(in millions)		2011			2010			2011			2010

Midwest Generation plants
	Non-qualifying hedges	$	2		$	(4	)	$	1		$	(6	)
	Ineffective portion of cash flow hedges		(1	)		(1	)		(1	)		3
Homer City plant
	Non-qualifying hedges		2			—			3			—
	Ineffective portion of cash flow hedges		—			(12	)		2			(14	)

Total unrealized gains (losses)		$	3		$	(17	)	$	5		$	(17	)

At June 30, 2011, cumulative unrealized gains of $8 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($3 million for the remainder of 2011 and $5 million for 2012).

Fair Value Disclosures

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

Commodity Price Risk

Energy Price Risk

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

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Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and the Electric Reliability Council of Texas (ERCOT).

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

		24-Hour Average Historical Market Prices¹

		2011		2010

Midwest Generation plants
	Northern Illinois Hub	$	34.50	$	33.44
Homer City plant
	PJM West Hub	$	46.52	$	43.88
	Homer City Busbar		42.45		38.28

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at June 30, 2011:

		24-Hour Forward Energy Prices¹

		Northern Illinois Hub		PJM West Hub

2011
	July	$	36.43	$	51.14
	August		38.60		51.32
	September		29.83		43.39
	October		26.21		40.24
	November		29.67		40.84
	December		31.33		46.46
2012 calendar "strip"²		$	33.08	$	46.01

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

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

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

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contracts and forward contracts accounted for on the accrual basis) at June 30, 2011 for electricity expected to be generated during the remainder of 2011 and in 2012 and 2013:

		2011				2012				2013

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

Midwest Generation plants²
	Northern Illinois		6,892	$	38.70		7,798	$	37.38		1,020	$	39.11
Homer City plant^3,⁴
	PJM West Hub		2,002		56.34		1,340		51.66		204		51.85

Total			8,894				9,138				1,224

¹: The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.
²: Includes hedging transactions primarily at the Northern Illinois Hub and to a lesser extent the AEP/Dayton and Cinergy Hubs.
³: Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. Years 2011 and 2012 include hedging activities entered into by EMMT for the Homer City plant that are not designated under the intercompany agreements with Homer City due to limitations under the sale-leaseback transaction documents.
⁴: The average price/MWh includes 175 MW of capacity for periods ranging from July 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at June 30, 2011:

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

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

July 1, 2011 to May 31, 2012
	Midwest Generation		5,477		(495	)		4,982		4,582	$	110.00		400		$	85.00	$	107.99
	Homer City		1,884		(163	)		1,721		1,771		110.00		(50	)		30.00		112.32
June 1, 2012 to May 31, 2013
	Midwest Generation		5,477		(773	)		4,704		4,704		16.46		—			—		16.46
	Homer City		1,884		(232	)		1,652		1,736		133.37		(84	)		16.46		139.31
June 1, 2013 to May 31, 2014
	Midwest Generation		5,477		(827	)		4,650		4,650		27.73		—			—		27.73
	Homer City		1,884		(104	)		1,780		1,780		226.15		—			—		221.03	⁴
June 1, 2014 to May 31, 2015
	Midwest Generation		5,477		(852	)		4,625		4,625		125.99		—			—		125.99
	Homer City		1,884		(190	)		1,694		1,694		136.50		—			—		136.50

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.

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²: Excludes 175 MW of capacity for periods ranging from July 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.
³: Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.
⁴: Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

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

Basis Risk

During the six months ended June 30, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 13%, respectively, due to transmission congestion in PJM. During the six months ended June 30, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub, Cinergy Hub and Northern Illinois Hub by an average of 13%, 2% and 1%, respectively, compared to 11%, 2% and 1%, respectively, during the six months ended June 30, 2010, due to transmission congestion in PJM.

Coal and Transportation Price Risk

The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at June 30, 2011 for the remainder of 2011 and the following two years:

	Amount of Coal Under Contract in Millions of Equivalent Tons¹

	July through December 2011		2012		2013

Midwest Generation plants²		8.9		11.7		—
Homer City plant		2.7		2.2		0.8

¹: The amount of coal under contract in equivalent tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the Homer City plant.
²: In July 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal of 0.5 million tons for the remainder of 2011, 2.0 million tons for 2012, 9.8 million tons for 2013, and 9.8 million tons for 2014.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City plant, increased during 2011 from 2010 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to a price of $78.20 per ton at July 1, 2011, compared to a price of $70 per ton at December 31, 2010, as reported by the Energy Information Administration.

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Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $12.35 per ton and $14.75 per ton during the first six months of 2011. The market price of PRB coal decreased to a price of $13.25 per ton at July 1, 2011, compared to a price of $13.60 per ton at December 31, 2010, 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 December 31, 2011. EME is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are materially higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.

Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, which expires on December 31, 2011, coal plants are required to hold seasonal and annual NO_x allowances.

In the event that actual emissions required are greater than allowances held, EME is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO₂ allowances decreased to $7 per ton during the six months ended June 30, 2011 from $50 per ton in 2010. The average purchase price of annual NO_x allowances decreased to $244 per ton during the six months ended June 30, 2011 from $936 per ton in 2010. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_x allowances was $4 per ton and $147.50 per ton, respectively, at June 30, 2011.

Under CSAPR, beginning January 1, 2012, the amount of SO₂ that a plant emits in its operation will need to be matched by a sufficient amount of SO₂ allowances designated under this program (CSAPR SO₂ allowances) that are either allocated to the plant under the CSAPR program or purchased in the open market. SO₂ allowances under the federal Acid Rain Program cannot be used to satisfy the requirements under CSAPR. EME will be impacted by market prices for additional CSAPR SO₂ allowances required, but availability and market prices are uncertain. For additional information on CSAPR, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments—Cross-State Air Pollution Rule."

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

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default by the counterparty. At June 30, 2011, the balance sheet exposure as described above, by the credit ratings of EME's counterparties, was as follows:

		June 30, 2011

(in millions)		Exposure²		Collateral			Net Exposure

Credit Rating¹
	A or higher	$	123	$	—		$	123
	A-		2		—			2
	BBB+		16		—			16
	BBB		1		—			1
	BBB-		14		—			14
	Below investment grade		32		(31	)		1

Total		$	188	$	(31	)	$	157

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

The credit risk exposure set forth in the above table is composed of $113 million of net accounts receivable and payables and $76 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. 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 $50 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 66% of EME's consolidated operating revenues for the six months ended June 30, 2011. At June 30, 2011, EME's account receivable due from PJM was $73 million.

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

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements," and refer to "Note 5, Debt and Credit Agreements" in Item 8 on page 113 of EME's annual report on Form 10-K for the year ended December 31, 2010.

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CRITICAL ACCOUNTING ESTIMATES AND POLICIES

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7 on page 71 of EME's annual report on Form 10-K for the year ended December 31, 2010. For an update to that disclosure, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For a discussion of EME's legal proceedings, refer to "Contingencies" in Item 8 on page 148 of EME's annual report on Form 10-K for the year ended December 31, 2010. There have been no significant developments with respect to legal proceedings specifically affecting EME since the filing of EME's annual report on Form 10-K for the year ended December 31, 2010, except as follows:

Midwest Generation New Source Review and Other Litigation

Homer City New Source Review and Other Litigation

In April 2011, Homer City filed motions to dismiss two complaints that were filed in January 2011 by the US EPA and two residents, respectively, in the Western District of Pennsylvania.

ITEM 1A. RISK FACTORS

For a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial condition, or future results, refer to "Item 1A. Risk Factors" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010. The risks described in EME's annual report on Form 10-K and in this report are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.

ITEM 6. EXHIBITS

Exhibit No.			Description


	31.1		Certification of the President pursuant to Section 302 of the Sarbanes-Oxley Act.
	31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
	32		Statement Pursuant to 18 U.S.C. Section 1350.
	101		Financial statements from the quarterly report on Form 10-Q of Edison Mission Energy for the quarter ended June 30, 2011, filed on August 4, 2011, formatted in XBRL: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

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SIGNATURES

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


		EDISON MISSION ENERGY
		By:		/s/ Maria Rigatti Maria Rigatti Senior Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)
		Date:		August 4, 2011