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

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 is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "accelerated filer," "large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

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 November 7, 2008: 100 shares (all shares held by an affiliate of the registrant).

		Page

	Glossary	ii
PART I—Financial Information
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	62
Item 4T.	Controls and Procedures	62
PART II—Other Information
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	64
Item 6.	Exhibits	64
	Signatures	65

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


Btu		British thermal units
CAIR		Clean Air Interstate Rule
Commonwealth Edison		Commonwealth Edison Company
CONE		cost of new entry
DOJ		United States Department of Justice
EME		Edison Mission Energy
EME Homer City		EME Homer City Generation L.P.
EMMT		Edison Mission Marketing & Trading, Inc.
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN No. 39-1		Financial Accounting Standards Board Staff Position No. 39-1, "Amendment of FASB Interpretation No. 39"
Fitch		Fitch Ratings
FSP SFAS No. 133-1 and FIN No. 45-4		Financial Accounting Standards Board Staff Position No. 133-1 and FIN No. 45-4, "Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161."
FSP SFAS No. 142-3		Financial Accounting Standards Board Staff Position SFAS No. 142-3, "Determination of the Useful Life of Intangible Assets"
GAAP		generally accepted accounting principles
GHG		greenhouse gas
GWh		gigawatt-hours
ISO(s)		independent system operator(s)
Illinois Plants		EME's largest power plants (fossil fuel) located in Illinois
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
NOV		Notice of Violation
NO_X		nitrogen oxide
NYISO		New York Independent System Operator

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, Unaudited)

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

			2008			2007			2008			2007
Operating Revenues			$	814		$	712		$	2,146		$	1,955
Operating Expenses
	Fuel			220			192			564			520
	Plant operations			135			112			466			425
	Plant operating leases			44			44			132			132
	Depreciation and amortization			50			41			140			117
	(Gain) on buyout of contract and (gain) loss on sale of assets (Note 8)			—			1			(16	)		1
	Administrative and general			57			61			155			145

		Total operating expenses		506			451			1,441			1,340

	Operating income			308			261			705			615

Other Income (Expense)
	Equity in income from unconsolidated affiliates			74			92			123			172
	Dividend income			—			1			10			12
	Interest income			4			21			19			67
	Interest expense			(67	)		(71	)		(204	)		(200	)
	Loss on early extinguishment of debt			—			—			—			(160	)
	Other income (expense), net			4			6			9			6

		Total other income (expense)		15			49			(43	)		(103	)

	Income from continuing operations before income taxes			323			310			662			512
	Provision for income taxes			121			116			237			184
	Minority interest			1			—			1			—

Income From Continuing Operations				203			194			426			328
	Income (loss) from operations of discontinued subsidiaries, net of tax (Note 5)			6			(4	)		—			1

Net Income			$	209		$	190		$	426		$	329

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

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions, Unaudited)

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

			2008			2007			2008			2007
Net Income			$	209		$	190		$	426		$	329
Other comprehensive income (loss), net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of prior service, net of tax		—			(1	)		(1	)		(1	)
		Amortization of net loss, net of tax		—			1			1			1
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $357 and $(17) for the three months and $53 and $(102) for the nine months ended September 30, 2008 and 2007, respectively		535			(28	)		81			(149	)
		Reclassification adjustments included in net income, net of income tax expense (benefit) of $44 and $(8) for the three months and $(45) and $(27) for the nine months ended September 30, 2008 and 2007, respectively		(66	)		12			69			37

Other comprehensive income (loss)				469			(16	)		150			(112	)

Comprehensive Income			$	678		$	174		$	576		$	217

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

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

			September 30, 2008		December 31, 2007

Assets
Current Assets
	Cash and cash equivalents		$	1,745	$	994
	Short-term investments			20		81
	Accounts receivable—trade			237		224
	Receivables from affiliates			15		35
	Inventory			163		149
	Derivative assets			107		56
	Margin and collateral deposits			147		85
	Deferred taxes			—		21
	Prepaid expenses and other			111		89

		Total current assets		2,545		1,734

Investments in Unconsolidated Affiliates				421		387

Property, Plant and Equipment				5,457		4,942
	Less accumulated depreciation and amortization			1,188		1,053

		Net property, plant and equipment		4,269		3,889

Other Assets
	Deferred financing costs			38		41
	Long-term derivative assets			194		91
	Restricted cash			43		48
	Rent payments in excess of levelized rent expense under plant operating leases			878		716
	Other long-term assets			543		366

		Total other assets		1,696		1,262

Total Assets			$	8,931	$	7,272

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

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

			September 30, 2008		December 31, 2007

Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	103	$	73
	Payables to affiliates			26		17
	Accrued liabilities			272		289
	Derivative liabilities			43		28
	Interest payable			99		30
	Deferred taxes			36		—
	Current maturities of long-term obligations			23		17

		Total current liabilities		602		454

Long-term obligations net of current maturities				4,688		3,806
Deferred taxes and tax credits				472		351
Deferred revenues				63		65
Long-term derivative liabilities				11		88
Other long-term liabilities				527		543

Total Liabilities				6,363		5,307

Minority Interest				75		42

Commitments and Contingencies (Note 8)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of September 30, 2008 and December 31, 2007			64		64
	Additional paid-in capital			1,332		1,326
	Retained earnings			1,010		596
	Accumulated other comprehensive income (loss)			87		(63	)

Total Shareholder's Equity				2,493		1,923

Total Liabilities and Shareholder's Equity			$	8,931	$	7,272

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

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, Unaudited)

			Nine Months Ended September 30,

			2008			2007
Cash Flows From Operating Activities
	Net income		$	426		$	329
	Less: Income from discontinued operations			—			(1	)

	Income from continuing operations, net		$	426		$	328
	Adjustments to reconcile income to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(123	)		(171	)
		Distributions from unconsolidated affiliates		85			118
		Depreciation and amortization		146			126
		Minority interest		(1	)		—
		Deferred taxes and tax credits		79			43
		(Gain) on buyout of contract and (gain) loss on sale of assets		(16	)		1
		Loss on early extinguishment of debt		—			160
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		(63	)		21
		Decrease (increase) in accounts receivables		(11	)		1
		Decrease (increase) in inventory		(14	)		6
		Decrease (increase) in prepaid expenses and other		(5	)		28
		Increase in rent payments in excess of levelized rent expense		(162	)		(161	)
		Decrease in accounts payable and other current liabilities		(1	)		(46	)
		Increase in interest payable		69			74
		Decrease (increase) in derivative assets and liabilities		32			(45	)
		Other operating—assets		(35	)		—
		Other operating—liabilities		(4	)		12

	Operating cash flow from continuing operations			402			495
	Operating cash flow from discontinued operations			—			1

		Net cash provided by operating activities		402			496

Cash Flows From Financing Activities
	Borrowings on long-term debt			1,130			2,930
	Payments on long-term debt agreements			(243	)		(2,274	)
	Cash dividends to parent			—			(925	)
	Payments to affiliates related to stock-based awards			(7	)		(29	)
	Excess tax benefits related to stock-based awards			2			9
	Premium paid on extinguishment of debt and financing costs			(1	)		(162	)

		Net cash provided by (used in) financing activities		881			(451	)

Cash Flows From Investing Activities
	Capital expenditures			(316	)		(329	)
	Proceeds from return of capital, loan repayments and sale of assets			9			5
	Proceeds from sale of membership interest			28			—
	Purchase of interest of acquired companies			(11	)		(28	)
	Purchase of short-term investments			(19	)		(20	)
	Maturities and sales of short-term investments			80			394
	Decrease in restricted cash			4			32
	Investments in other assets			(307	)		(229	)

		Net cash used in investing activities		(532	)		(175	)

Net increase (decrease) in cash and cash equivalents				751			(130	)
Cash and cash equivalents at beginning of period				994			1,212

Cash and cash equivalents at end of period			$	1,745		$	1,082

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

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2008
(Unaudited)

EME's significant accounting policies were described in Note 1 to its consolidated financial statements included in its annual report on Form 10-K for the year ended December 31, 2007. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2008 as discussed below in "—Margin and Collateral Deposits" and "—New Accounting Pronouncements." This quarterly report should be read in conjunction with such financial statements.

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position and results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the nine months ended September 30, 2008 are not necessarily indicative of the operating results for the full year.

Certain prior year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

At September 30, 2008, cash equivalents included money market funds, U.S. Treasury securities, U.S. government agency securities and commercial paper totaling $1.6 billion. At December 31, 2007, cash equivalents included money market funds, time deposits (including certificates of deposit) and U.S. Treasury securities totaling $873 million. Cash equivalents, with the exception of money market funds, were stated at cost plus accrued interest. The carrying value of cash equivalents approximates fair value due to maturities of less than three months. For further discussion of money market funds, see Note 2—Fair Value Measurements.

At September 30, 2008 and December 31, 2007, EME had classified all marketable debt securities as held-to-maturity. The securities were carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material.

Prepaid expenses and other on EME's consolidated balance sheets include emission allowances purchased for use of $65 million and $45 million at September 30, 2008 and December 31, 2007, respectively.

Other long-term assets on EME's consolidated balance sheets include the following noncurrent intangible assets:

During the first nine months of 2008, EME purchased emission allowances at its Illinois Plants and Homer City facilities. In addition, EME purchased emission allowances related to thermal projects under development. See "Environmental Matters and Regulations" in Note 8—Commitments and Contingencies for further discussion with respect to annual NO_X allowances purchased by Midwest Generation.

Inventory is stated at the lower of weighted average cost or market. Inventory at September 30, 2008 and December 31, 2007 consisted of the following:

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. See "—New Accounting Pronouncements—Accounting Principles Adopted—FASB Staff Position FIN No. 39-1" for a discussion of EME's adoption of FIN No. 39-1. In accordance with FIN No. 39-1, EME presents a portion of its margin and cash collateral deposits net with its derivative positions on EME's consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $46 million and $36 million at September 30, 2008 and December 31, 2007, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $0.4 million at September 30, 2008.

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. EME adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on EME's consolidated balance sheets, but had no impact on EME's consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in net assets (margin and collateral deposits) of $36 million. The consolidated statement of cash flows for the nine months ended September 30, 2007 has been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flow from continuing operations.

In February 2007, the FASB issued SFAS No. 159, "Fair Value Option for Financial Assets and Liabilities, Including an Amendment of FASB Statement No. 115," which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. EME adopted this pronouncement effective January 1, 2008. The adoption had no impact because EME did not make an optional election to report additional financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. EME adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustment to its consolidated financial statements. The accounting requirements for employers' pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will be January 1, 2009 for nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion, see Note 2—Fair Value Measurements.

On October 10, 2008, the FASB issued FSP SFAS No. 157-3, "Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active." This position clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. It also reaffirms the notion of fair value as an exit price as of the measurement date. This position was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption had no impact on EME's consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial

statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. Early adoption is not permitted.

In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements," which requires an entity to present minority interest that reflects the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity's equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. EME will adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, EME will reclassify minority interest to a component of shareholder's equity (at September 30, 2008 this amount was $75 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. EME will adopt SFAS No. 161 in the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on EME's consolidated results of operations, financial condition or cash flows.

In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally Accepted Accounting Principles," which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements for nongovernmental entities that are presented in conformity with U.S. GAAP. This statement transfers the GAAP hierarchy from the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, "The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles" to the FASB. SFAS No. 162 is effective on November 15, 2008. EME expects that the adoption of this standard will not have an impact on EME's consolidated results of operations, financial condition or cash flows.

In April 2008, the FASB issued FSP SFAS No. 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, "Goodwill and Other Intangible Assets." The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other U.S. GAAP. EME will adopt FSP SFAS No. 142-3 on January 1, 2009. EME is currently evaluating the impact, if any, that the adoption of this position could have on its consolidated financial statements.

In September 2008, the FASB issued FSP SFAS No. 133-1 and FIN No. 45-4. FSP SFAS No. 133-1 requires enhanced disclosures by sellers of credit derivatives and amends FASB Interpretation No. 45 (FIN No. 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others," to require additional disclosure about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN No. 45 are effective for reporting periods ending after November 15, 2008. Since FSP FAS No. 133-1 and FIN No. 45-4 only require additional disclosures, the adoption will not impact EME's consolidated financial position, results of operations or cash flows.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price" in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity's nonperformance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under SFAS No. 157 are:

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

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. The majority of derivative contracts used for hedging purposes are based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub and AEP/Dayton) adjusted for non-performance risks. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. Broker quotes are considered observable when corroborated with prices from exchanges. The majority of the fair value of EME's derivative contracts determined in this manner are classified as Level 2.

Derivatives that trade infrequently (such as financial transmission rights and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant non-performance risks, as discussed below, and long-term power agreements are classified as Level 3. For illiquid financial transmission rights, EME reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when EME concludes a change in objective

criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where EME cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

In assessing non-performance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of non-performance. In light of recent market events, EME utilized market prices for credit default swaps in reducing the fair value of derivative assets with financial institutions by $7 million at September 30, 2008.

Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices (unadjusted) in active markets. At September 30, 2008, EME has invested $20 million in the Reserve Primary Fund (a money market fund). The Reserve incurred a loss related to debt securities of Lehman Brothers Holdings and has announced liquidation of the Reserve with the latest valuation of $0.97 per share. EME has reduced the fair value of the investment by $1 million and transferred the remaining balance into Level 3 as observable market prices are not available.

The following table sets forth EME's financial assets and liabilities that were accounted for at fair value as of September 30, 2008 by level within the fair value hierarchy.

The following table sets forth a summary of changes in the fair value of EME's Level 3 derivative contracts, net for the periods ended September 30, 2008.

		Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008

		(in millions)
Fair value of derivative contracts, net at beginning of periods		$	121		$	120
Total realized/unrealized gains (losses):
	Included in earnings(1)		142			234
	Included in accumulated other comprehensive income (loss)		9			3
Purchases and settlements, net			(56	)		(131	)
Transfers in or out of Level 3			(75	)		(85	)

Fair value of derivative contracts, net at September 30, 2008		$	141		$	141

Change during the periods in unrealized gains (losses) related to derivative contracts, net held at September 30, 2008(1)		$	101		$	56

Unrealized gains on cash flow hedges, net of tax, at September 30, 2008, included unrealized gains on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. As EME's hedged positions for continuing operations are realized, $46 million, after tax, of the net unrealized gains on cash flow hedges at September 30, 2008 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2011.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in 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 $23 million and $(13) million during the third quarters of 2008 and 2007, respectively, and $(8) million and $(23) million during the nine months ended September 30, 2008 and 2007, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in operating revenues on EME's consolidated income statements.

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. EME had power contracts with Lehman Brothers Commodity Services, Inc., a subsidiary of Lehman Brothers Holdings, for Midwest Generation for 2009 and 2010. The obligations of Lehman Brothers Commodity Services under the power contracts are guaranteed by Lehman Brothers Holdings. These contracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the power contracts as such, effective September 12, 2008 when it determined that it was no longer probable that performance would occur. The amount recorded in accumulated comprehensive income (loss) related to the effective portion of the hedges was $24 million pre-tax ($15 million, after tax) on this date. Since the power contracts are no longer being accounted for as cash flow hedges under SFAS No. 133, the subsequent change in fair value was recorded as an unrealized loss during the third quarter of 2008 reflected in operating revenues on EME's consolidated statement of income. Under SFAS No. 133, the pre-tax amount recorded in accumulated other comprehensive income (loss) will be reclassified to operating revenues based on the original forecasted transactions in 2009 ($15 million) and 2010 ($9 million), unless it becomes probable that the forecasted transactions will no longer occur.

EME has a number of wind projects that were consolidated in accordance with FIN 46(R). These projects were funded with nonrecourse debt totaling $19 million at September 30, 2008. Properties serving as collateral for these loans had a carrying value of $51 million and are classified as property, plant and equipment on EME's consolidated balance sheet at September 30, 2008.

EME completed a review of the application of FIN 46(R) to its subsidiaries and affiliates and concluded that it had significant variable interests in variable interest entities as defined in this Interpretation. As of September 30, 2008, these entities consisted of five equity investments (the Big 4 projects and the Sunrise project) that had interests in natural gas-fired facilities with a total generating capacity of 1,782 MW. A wholly owned operations and maintenance subsidiary of EME operates the Big 4 projects, but EME does not supply the fuel consumed or purchase the power generated by these facilities. EME determined that it is not the primary beneficiary in these entities; accordingly, EME continues to account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities, which totaled $379 million as of September 30, 2008.

EME received a payment of £0.4 million (approximately $1 million) and £4 million (approximately $8 million) in the first nine months of 2008 and 2007, respectively. The after-tax income attributable to the Lakeland project was none in the third quarters of 2008 and 2007 and $0.5 million and $5 million for the nine months ended September 30, 2008 and 2007, respectively.

As of September 30, 2008, EME had made approximately $14 million in contributions to its pension plans and estimates to make $1 million of contributions in the last three months of 2008.

As of September 30, 2008, EME had made approximately $1 million in contributions to its postretirement benefits other than pensions and estimates to make $1 million of contributions in the last three months of 2008.

EME's income tax provision from continuing operations was $237 million and $184 million for the nine months ended September 30, 2008 and 2007, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the nine months ended September 30, 2008 and 2007, EME recognized $29 million and $19 million, respectively, of production tax credits related to wind projects and $5 million and $10 million, respectively, related to estimated state income tax benefits allocated from Edison International.

EME is included in the federal consolidated income tax return filed by Edison International. During the third quarter of 2008, the Internal Revenue Service commenced an examination of Edison International's consolidated federal income tax return for the tax years 2003-2006.

These amounts have been updated primarily to reflect EME's financing activities completed during the third quarter of 2008. EME and its subsidiary, Midwest Generation, made borrowings under their credit agreements totaling $898 million to enhance liquidity. Proceeds from these borrowings were invested in U.S. Treasury securities, U.S. government agency securities, and money market funds invested directly in U.S. Treasury securities and U.S. government agency securities.

At September 30, 2008, EME's subsidiaries had firm commitments to spend approximately $204 million during the remainder of 2008 and $42 million in 2009 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. These expenditures are planned to be financed by cash on hand and cash generated from operations.

EME had entered into various turbine supply agreements with vendors to support its wind and thermal development efforts. At September 30, 2008, EME had secured 484 wind turbines (942 MW) and 5 gas-fired turbines (479 MW) for use in future projects for an aggregate purchase price of $1.4 billion, with remaining commitments of $66 million in 2008, $794 million in 2009 and $260 million in 2010. At September 30, 2008, EME had recorded wind turbine deposits of $318 million included in other long-term assets on its consolidated balance sheet.

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the first quarter of 2008 reflected in "(Gain) on buyout of contract and (gain) loss on sale of assets" on EME's consolidated statements of income. The remaining payments due under this contract are $15 million.

EME's subsidiaries had entered into contractual agreements during the first nine months of 2008 to purchase materials for environmental controls equipment. In addition, during the nine months ended September 30, 2008, EME's subsidiaries entered into turbine operations and maintenance agreements. These commitments are currently estimated to aggregate to $196 million, summarized as follows:

remainder of 2008—$3 million, 2009—$31 million, 2010—$48 million, 2011—$48 million, 2012—$46 million, and thereafter—$20 million.

At September 30, 2008, standby letters of credit aggregated $123 million and were scheduled to expire as follows: $13 million in 2008 and $110 million in 2009.

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

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

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV discussed below under "Contingencies—Midwest Generation New Source Review Notice of Violation." By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion

responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2009. Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 208 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at September 30, 2008. Midwest Generation had recorded a $53 million liability at September 30, 2008 related to this matter.

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

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. EME has not recorded a liability related to this indemnity.

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At September 30, 2008, EME had recorded a liability of $97 million related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At September 30, 2008, EME had recorded a liability of $13 million related to these matters.

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. The obligations under this indemnification agreement as of September 30, 2008, if payment were required, would be $63 million. EME has not recorded a liability related to this indemnity.

On May 30, 2008, a group of entities referring to themselves as the "RPM Buyers" filed a complaint at the FERC asking that PJM's RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. The RPM Buyers alleged that the absence of price discipline provided by new capacity resources, together with the ability of existing resources to withhold some capacity within the RPM rules, produced capacity prices in the transition period that are not comparable to those that would have been produced in a competitive market or determined under cost-based regulation, and have requested that the FERC order refunds based on that difference.

On July 10, 2008, EME responded to the RPM Buyers' complaint asking that it be dismissed based upon various legal precedents. A number of other parties, including PJM, also responded to the RPM Buyers' complaint asking that it be dismissed. On September 19, 2008, the FERC dismissed the RPM Buyers' complaint, finding that the RPM Buyers had failed to allege or prove that any party violated PJM's tariff and market rules, and that the prices determined during the transition period were determined in accordance with PJM's FERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC's order dismissing their complaint. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA in the NOV and is developing a litigation strategy. Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME Homer City is investigating the NOV claims and is developing a litigation strategy. EME Homer City cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.

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

EME Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, have sought indemnification and defense from EME Homer City for costs and liability associated with the EME Homer City NOV. EME Homer City responded by undertaking the indemnity obligation and defense of the claims.

At September 30, 2008, Midwest Generation had an $8 million receivable recorded primarily related to insurance claims from unplanned outages. During the first quarter of 2008, $6 million related to business interruption insurance coverage was recorded and has been reflected in other income (expense), net on EME's consolidated statements of income. Midwest Generation received $4 million in cash payments during the third quarter of 2008.

The construction and operation of power plants are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with existing environmental regulatory requirements. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which EME and its subsidiaries conduct their businesses and could require substantial additional capital or operational expenditures or the ceasing of operations at certain of their facilities. There is no assurance that EME's financial position and results of operations would not be materially adversely affected. EME is unable to predict the precise extent to which additional laws and regulations may affect its future operations and capital expenditure requirements.

Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects, which may involve significant capital or operational expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by federal and state regulatory authorities.

With respect to EME's potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $3 million at September 30, 2008 for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

In July 2008, a three-judge panel of the District of Columbia Circuit Court of Appeals issued a decision to vacate the CAIR in its entirety and remand to the US EPA to issue a new rule consistent with the decision once the Court issues its mandate. The decision raised significant questions as to whether the US EPA will be able to design cap-and-trade programs for NO_X and SO₂ that are authorized and consistent with the Clean Air Act provisions that address upwind contributions to downwind states' noncompliance with national ambient air quality standards for ozone and fine particulate matter. Following the decision, the US EPA requested that states reinstate the existing "SIP Call" ozone season NO_X cap-and-trade program, which was due to be replaced by the CAIR.

In September 2008, the US EPA and other parties requested a rehearing of the decision by the same three-judge panel or by the full District of Columbia Circuit Court. In October 2008, the Court ordered the petitioners in the CAIR litigation to file a response to the request for rehearing and specifically address whether any party is seeking to vacate the CAIR and whether the Court should stay its mandate until the US EPA promulgates a revised rule. Although EME cannot predict the outcome of this proceeding, this latest order suggests that the Court may be willing to leave the CAIR in place in some form. The Court's order vacating the CAIR will not become effective until the Court responds to the petitions for a rehearing of its decision; until then, compliance with the CAIR, including the annual NO_X requirements, will be required.

EME is monitoring developments related to the D.C. Circuit's CAIR proceedings. Because Pennsylvania and Illinois promulgated their regulations in response to the CAIR, there is substantial uncertainty as to the impact on these state regulations if the Court denies the petitions for rehearing and issues a mandate to vacate the CAIR. This is particularly true of Pennsylvania's regulatory program, which is modeled on the CAIR and is dependent on the interstate emissions trading program established by the CAIR. Illinois also adopted the CAIR emissions trading programs, but in addition requires Midwest Generation to achieve reductions of NO_X and SO₂ (and mercury) through environmental control retrofits and plant shutdowns pursuant to a Combined Pollutant Standard. However, if the US EPA is required to propose a new regulation to address interstate transport of air pollution, EME cannot be certain that the emissions reductions currently required by the Combined Pollutant Standard will be sufficient to meet such revised regulations. In addition, the US EPA has allowed states to rely on compliance with the CAIR to satisfy obligations under other Clean Air Act programs, including regional haze regulations and reasonably available control technology requirements. Depending on what happens with respect to the CAIR, the Illinois Plants and the Homer City facilities may be subject to additional requirements pursuant to these programs. For further discussion, see "Note 12. Commitments and Contingencies—Environmental Matters and Regulations—Air Quality

Regulation—Clean Air Interstate Rule" to EME's consolidated financial statements included in its annual report on Form 10-K for the year ended December 31, 2007.

Based on the CAIR requirements, Midwest Generation purchased annual NO_X allowances under the new CAIR annual NO_X program. Midwest Generation and EME Homer City continue to plan to meet the requirements of the CAIR as required under current law effective January 1, 2009. If the D.C. Circuit Court issues a mandate to vacate the CAIR, Midwest Generation would no longer need annual NO_X allowances and would record an impairment of $48 million at the time of such action.

In connection with certain wind projects acquired during the second quarter of 2008 and the first and third quarters of 2007, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, during the first nine months of 2008 and 2007, EME accrued for estimated payments that were due upon commencement of construction and/or completion of construction scheduled during 2008 through 2009.

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

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

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of EME's annual report on Form 10-K for the year ended December 31, 2007. Readers are urged to read this entire quarterly report on Form 10-Q and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2007, and as compared to the third quarter of 2007 and nine months ended September 30, 2007. 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, 2007.

EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of developing, acquiring, owning or leasing, operating, and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own all or an interest in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. As of September 30, 2008, EME's subsidiaries and affiliates owned or leased interests in 34 operating projects and 6 wind projects under construction.

Global financial markets are experiencing severe credit tightening and a significant increase in volatility, causing access to capital markets to become subject to increased uncertainty and borrowing costs to rise dramatically. In response, U.S. and foreign governments and central banks have intervened with programs designed to increase liquidity.

EME is a capital intensive business and depends on access to the financial markets to fund capital expenditures, meet contractual obligations and support margin and collateral requirements. EME plans to expand its business development activities to grow and diversify its existing portfolio of power projects, including building new power plants, meeting its environmental commitments and making ongoing capital improvements to its existing generation fleet, all of which require liquidity and access to capital markets in the future. For further discussion, see "Liquidity and Capital Resources—Business Development" and "Liquidity and Capital Resources—Capital Expenditures."

Due to the instability of the financial markets, and to provide protection against a dramatic liquidity crisis, EME and its subsidiary, Midwest Generation, made borrowings under their respective credit agreements totaling $898 million. Proceeds from these borrowings were invested in U.S. Treasury securities, U.S. government agency securities and money market funds invested directly in U.S. Treasury securities and U.S. government agency securities. At September 30, 2008, EME had consolidated cash and cash equivalents and short-term investments of $1.8 billion. Although EME does not have any material debt obligations that mature until 2012, EME's projected capital expenditures require liquidity and access to capital markets in the future.

While the capital markets are expected to recover over time, it is uncertain how long before recovery occurs. Furthermore, the cost of capital has increased, and terms and conditions of debt agreements are expected to be more restrictive. EME has made substantial capital commitments, especially for wind turbines. Pending recovery of the capital markets, EME intends to preserve capital by focusing on a more selective growth strategy (primarily completion of projects under construction, including the Big Sky project in Illinois, and development of sites for future renewable projects deploying current turbine commitments), and using its cash and future cash flow to meet its existing contractual commitments. Moreover, disruption in the financial markets appears to have reduced trading activity in power markets which may affect the level and duration of future hedging activity and potentially increase the volatility of earnings. Long-term disruption in the capital markets could adversely affect EME's business plans and potentially impact EME's financial position.

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Commercial Paper Inc., is one of the lenders in EME's credit agreement representing a commitment of $36 million. In September 2008, Lehman Commercial Paper declined requests for funding under EME's credit agreement. Another subsidiary of Lehman Brothers Holdings, Lehman Brothers Commodity Services, Inc., declined to meet a collateral call on power contracts, including hedge contracts for Midwest Generation for 2009 and 2010. The obligations of Lehman Brothers Commodity Services under the power contracts are guaranteed by Lehman Brothers Holdings. The bankruptcy filing and failure to post collateral are events of default under the related agreements. In October 2008, these power contracts were terminated, resulting in claims against Lehman Brothers Holdings and its subsidiary in bankruptcy. EME recorded a pre-tax loss of $26 million related to power contracts during the third quarter of 2008 reflected in operating revenues on EME's consolidated statement of income. See "Market Risk Exposures—Accounting for Energy Contracts" for further discussion.

Since June 30, 2008, forward energy prices have decreased substantially driven by lower natural gas prices and the financial market developments discussed above. The forward energy market prices for 2009 and 2010 at September 30, 2008 for the Northern Illinois Hub and PJM West Hub have decreased between 13% and 30% since June 30, 2008. At September 30, 2008, EME had entered into derivative hedge contracts that are recorded at fair value on its consolidated financial statements. Since forward

energy prices have decreased since June 30, 2008, the fair value of derivative hedge contracts changed from a net liability position at June 30, 2008 to a net asset position at September 30, 2008, with the effective portion of the contracts recorded as an increase in shareholder's equity ($90 million, after tax). See "Market Risk Exposures—Commodity Price Risk" for further discussion.

In July 2008, a three-judge panel of the District of Columbia Circuit Court of Appeals issued a decision to vacate the CAIR in its entirety and remand to the US EPA to issue a new rule consistent with the decision. In September 2008, US EPA and other parties requested a rehearing of its decision by the same three-judge panel or by the full District of Columbia Circuit Court. In October 2008, the Court ordered the petitioners in the CAIR litigation to file a response to the request for rehearing and specifically address whether any party is seeking to vacate the CAIR and whether the Court should stay its mandate until the US EPA promulgates a revised rule. Although EME cannot predict the outcome of this proceeding, this latest order suggests that the Court may be willing to leave the CAIR in place in some form. The Court's order vacating the CAIR will not become effective until the Court responds to the petitions for a rehearing of its decision; until then, compliance with the CAIR, including the annual NO_X requirements, will be required. If the Court denies the petitions for rehearing and issues a mandate to vacate the CAIR, there will be substantial uncertainty as to the impact of this decision on the SIP regulations promulgated by Pennsylvania and Illinois in response to the CAIR.

Notwithstanding these developments, the Illinois Plants and Homer City facilities continue to be governed by state rules as well as the existing "SIP Call" ozone season NO_X cap-and-trade program (which was due to be replaced by the CAIR). For further discussion, see "Liquidity and Capital Resources—Environmental Matters and Regulations—Air Quality Regulation—Clean Air Interstate Rule."

New wind projects currently receive federal subsidies in the form of production tax credits. Production tax credits for a ten-year period are available for new projects placed in service prior to December 31, 2008. In October 2008, production tax credits were extended for projects placed in service by December 31, 2009 as part of the Emergency Economic Stabilization Act of 2008.

At September 30, 2008, EME had 855 MW of wind projects in service and another 330 MW of wind projects under construction, with scheduled completion dates into 2009. As of the same date, EME had a development pipeline of potential wind projects with an estimated installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. This development pipeline is supported by turbine purchase commitments totaling 942 MW for new wind projects. The majority of the turbines are scheduled to be delivered before the end of 2010.

Key activities during the third quarter of 2008 with respect to wind projects were:

During the first quarter of 2008, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement was approved by the California Public Utilities Commission (CPUC) on September 18, 2008 and by the FERC on October 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. During the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project. See "Liquidity and Capital Resources—Capital Expenditures—Expenditures for New Projects" for further details on the status of this project, including uncertainty regarding availability of emissions credits.

On July 1, 2008, the human resources module, including payroll and timekeeping, was implemented as part of the Edison International enterprise-wide project.

EME's increase in income from continuing operations during the third quarter ended September 30, 2008 was primarily attributable to higher gross margin at the Homer City facilities and Illinois Plants, partially offset by a charge related to power contracts with Lehman Brothers Commodity Services, Inc., lower income from the Big 4 projects and lower interest income. The year-to-date increase in income from continuing operations was primarily due to higher gross margin at the Illinois Plants from higher generation and higher average realized prices and due to higher energy trading income. These increases were partially offset by lower income from the Big 4 projects and Homer City facilities and lower interest income. The 2008 year-to-date earnings also reflect the buyout of a coal contract at the Illinois Plants. The prior year-to-date earnings reflect a $98 million, after tax, loss on early extinguishment of debt recorded during the second quarter of 2007.

For a discussion of EME's critical accounting policies, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview; Critical Accounting Policies—Critical Accounting Policies" of EME's annual report on Form 10-K for the year ended December 31, 2007.

This section discusses operating results for the third quarters of 2008 and 2007 and nine months ended September 30, 2008 and 2007, and is organized under the following headings:

EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the Illinois Plants and the Homer City facilities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the project results set forth in the following table, except as described below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation, and loans from Midwest Generation to EMMT. Equity in income from unconsolidated affiliates relates to energy projects accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

EME uses the words "earnings" or "losses" in this section to describe income or loss from continuing operations before income taxes.

The following section provides a summary of the operating results for the third quarters of 2008 and 2007 and nine months ended September 30, 2008 and 2007 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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

		2008			2007			2008			2007
		(in millions)
Project Earnings (Losses) Before Income Taxes(1)
	*Consolidated operations*
	Illinois Plants	$	238		$	238		$	631		$	515
	Homer City		109			70			152			172
	Energy Trading(2)		46			41			138			103
	Sleeping Bear		2			—			9			—
	Wildorado		3			5			11			7
	San Juan Mesa		—			1			5			4
	Iowa Wind projects		(1	)		—			6			4
	Minnesota Wind projects		—			—			2			2
	Other		3			3			5			4
	*Unconsolidated affiliates*
	Big 4 projects		46			62			82			125
	Sunrise		28			29			33			33
	Doga		—			—			8			14
	Other		(1	)		(2	)		7			7

			473			447			1,089			990
	Corporate interest income		3			21			14			59
	Corporate interest expense		(91	)		(97	)		(271	)		(233	)
	Corporate administrative and general		(50	)		(52	)		(132	)		(120	)
	Loss on early extinguishment of debt		—			—			—			(160	)
	Other income (expense), net		(3	)		(2	)		(9	)		(5	)

		$	332		$	317		$	691		$	531

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

			2008			2007			2008			2007
			(in millions)
Operating Revenues			$	501		$	449		$	1,360		$	1,214
Operating Expenses
	Fuel			142			117			366			311
	Gain on sale of emission allowances(1)			—			(8	)		(3	)		(12	)
	Plant operations			98			84			317			300
	Plant operating leases			19			19			56			56
	Depreciation and amortization			26			25			78			75
	(Gain) on buyout of contract and (gain) loss on sale of assets			—			—			(16	)		1
	Administrative and general			5			5			16			16

	Total operating expenses			290			242			814			747

Operating Income				211			207			546			467

Other Income (Expense)
	Interest income on note receivable from EME			28			29			84			85
	Interest income (expense) and other			(1	)		2			1			(37	)

	Total other income (expense)			27			31			85			48

Income Before Taxes			$	238		$	238		$	631		$	515

Statistics
	Generation (in GWh):
		Energy only contracts		7,333			6,298			19,404			17,441
		Load requirements services contracts		1,080			2,115			4,212			5,728

		Total		8,413			8,413			23,616			23,169
	Aggregate plant performance:
		Equivalent availability(2)		87.4%			86.6%			80.9%			78.7%
		Capacity factor(3)		69.7%			67.9%			65.8%			63.0%
		Load factor(4)		79.8%			78.4%			81.3%			80.1%
		Forced outage rate(5)		8.3%			8.6%			9.0%			7.0%
	Average realized price/MWh:
		Energy only contracts(6)	$	54.25		$	48.15		$	53.44		$	48.73
		Load requirements services contracts(7)	$	63.40		$	65.27		$	62.65		$	63.34
	Capacity revenue only (in millions)		$	41		$	11		$	70		$	17
	Average fuel costs/MWh		$	16.90		$	13.88		$	15.51		$	13.40

Earnings from the Illinois Plants were the same in the third quarter of 2008 and 2007 and increased $116 million in the nine months ended September 30, 2008, compared to the corresponding period of 2007. The third quarter of 2008 earnings were the same as the prior year period with higher average realized energy and capacity prices and unrealized gains discussed below, offset by higher fuel and operating costs and an unrealized loss of $24 million related to power contracts due to the bankruptcy of Lehman Brothers Holdings. In addition, results for the third quarter of 2008 included the impact of heavy rains which resulted in a higher-than-planned forced outage rate. The year-to-date increase in earnings was primarily attributable to higher gross margin, as compared to 2007, lower interest expense in 2008 due to the repayment of debt in May 2007, a $15 million gain recorded during the first quarter of 2008 related to a buyout of a fuel contract (see "Liquidity and Capital Resources—Contractual Obligations and Contingencies—Fuel Supply Contracts" for further discussion). The increase in gross margin was due to higher average realized energy and capacity prices and higher generation, partially offset by higher coal and transportation costs. These increases were partially offset by the $24 million charge related to the power contracts described below.

Included in operating revenues were unrealized losses of $7 million and $8 million for the third quarters of 2008 and 2007, respectively, and $15 million and $26 million for the nine months ended September 30, 2008 and 2007, respectively. In 2008, unrealized losses included $24 million from power contracts for 2009 and 2010 with Lehman Brothers Commodity Services, Inc. These contracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the contracts as such, effective September 12, 2008. Since the power contracts no longer qualify as cash flow hedges under SFAS No. 133 due to non-performance risk, the subsequent change in fair value was recorded as an unrealized loss during the third quarter of 2008. Unrealized gains (losses) were also attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133 and power contracts that did not qualify for hedge accounting under SFAS No. 133 (sometimes referred to as economic hedges). These energy contracts were entered into to hedge the price risk related to projected sales of power. See "Market Risk Exposures—Commodity Price Risk" and "Market Risk Exposures—Accounting for Energy Contracts" for more information regarding forward market prices and the write-off of the power contracts, respectively.

The earnings of the Illinois Plants included interest income of $28 million and $29 million for the third quarters of 2008 and 2007, respectively, and $84 million and $85 million for the nine months ended September 30, 2008 and 2007 related to loans to EME. In August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes.

On December 18, 2007, Unit 6 at the Powerton Station had a duct failure resulting in a suspension of operations at this unit through February 12, 2008. Scheduled maintenance work for the spring of 2008 was accelerated to minimize the aggregate impact of the outage. The duct failure resulted in claims under Midwest Generation's property and business interruption insurance policies. During the first quarter of 2008, $6 million related to business interuption insurance coverage was recorded primarily related to these claims. At September 30, 2008, Midwest Generation had a $4 million receivable recorded related to these claims.

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

		2008		2007		2008		2007
		(in millions)
Operating Revenues		$	236	$	199	$	548	$	573
Operating Expenses
	Fuel(1)		78		85		202		225
	Plant operations		22		18		108		93
	Plant operating leases		25		25		76		76
	Depreciation and amortization		4		4		12		11
	Administrative and general		1		1		3		3

	Total operating expenses		130		133		401		408

Operating Income			106		66		147		165

Other Income (Expense)
	Interest and other income		3		4		5		8
	Interest expense		—		—		—		(1	)

	Total other income		3		4		5		7

Income Before Taxes		$	109	$	70	$	152	$	172

Statistics
	Generation (in GWh)		3,354		3,759		8,796		10,211
	Equivalent availability(2)		93.6%		96.5%		80.9%		89.0%
	Capacity factor(3)		80.5%		90.2%		70.9%		82.6%
	Load factor(4)		86.0%		93.4%		87.6%		92.8%
	Forced outage rate(5)		4.0%		3.5%		8.1%		3.7%
	Average realized energy price/MWh(6)	$	61.95	$	51.48	$	57.69	$	54.42
	Capacity revenue only (in millions)	$	14	$	9	$	33	$	22
	Average fuel costs/MWh	$	23.30	$	22.48	$	23.02	$	22.00

Earnings from Homer City increased $39 million and decreased $20 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The third quarter increase in earnings was primarily attributable to higher operating revenues due to higher average realized energy and capacity prices and an increase in unrealized gains related to hedge contracts discussed below. The year-to-date decrease in earnings was primarily attributable to lower operating revenues primarily from lower generation and higher plant maintenance expenses. Higher forced outages, lower off-peak dispatch and extended planned overhauls in 2008 contributed to lower generation and higher maintenance expenses. The average realized energy price for the nine months ended September 30, 2008 was below the 24-hour PJM average market price at the Homer City busbar primarily due to effective hedge prices being below market prices for the same period. For further discussion, see "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities."

Included in operating revenues were unrealized gains (losses) from hedging activities of $14 million and $(3) million for the third quarters of 2008 and 2007, respectively, and $7 million and $(5) million for nine months ended September 30, 2008 and 2007, respectively. Unrealized gains (losses) were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. See "Market Risk Exposures—Commodity Price Risk" and "Market Risk Exposures—Accounting for Energy Contracts" for more information regarding forward market prices and unrealized gains (losses), respectively.

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the Illinois Plants and the Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinois Plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. See "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants" and "—Energy Price Risk Affecting Sales from the Homer City Facilities" for further discussion regarding market prices.

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

in the eastern power grid using products available over the counter, through exchanges, and from ISOs. The majority of EMMT's trading activities are related to congestion contracts and short-term power arbitrage positions between locations. Earnings from energy trading activities increased $5 million and $35 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The 2008 increases in earnings from energy trading activities resulted from increased congestion and market volatility in key markets.

In April 2008, EMMT entered into three load services requirements contracts in Maryland with local utilities. Under the terms of the load services requirements contracts, EMMT is obligated to supply a portion of each utility's load at fixed prices that vary based on periods specified in the contracts. EMMT is obligated to pay for the cost of supply at each utility's load zones including, energy, capacity, ancillary services and renewable energy credits. The estimated load for the period October 1, 2008 through September 30, 2010 is approximately 4 million megawatt-hours. EMMT has entered into futures contracts to substantially hedge the energy price risk related to these contracts. The above contracts are recorded as derivatives with the change in fair value reflected in trading income above.

Earnings from the Sleeping Bear wind project were $2 million and $9 million for the third quarter and nine months ended September 30, 2008, respectively. EME had no comparable results from the Sleeping Bear wind project in 2007. Commercial operation of the Sleeping Bear wind project commenced during October 2007. In addition, the Sleeping Bear wind project recorded availability warranty income related to the Suzlon wind turbines at its site during the second and third quarters of 2008. See "Liquidity and Capital Resources—Contractual Obligations and Contingencies—Turbine Commitments" for further discussion.

Earnings from the Wildorado wind project decreased $2 million and increased $4 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The third quarter decrease in earnings was primarily due to stronger winds in the third quarter of 2007 as compared to the third quarter of 2008. The year-to-date increase in earnings was primarily attributable to earnings recorded for nine months in 2008, compared to five months in 2007. Commercial operation of the Wildorado wind project commenced during April 2007.

Earnings from the San Juan Mesa wind project decreased $1 million and increased $1 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods in 2007. The third quarter decrease in earnings was attributable to lower wind speed and capacity factors during the three months ended September 30, 2008 as compared to the three months ended September 30, 2007. The year-to-date increase in earnings was primarily due to higher capacity factors in 2008 as compared to 2007.

Earnings from the Iowa wind projects (consisting of the Storm Lake wind project, Crosswinds wind project and Hardin wind project) decreased $1 million and increased $2 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods in 2007. The third quarter decrease was primarily due to lower earnings from the Storm Lake wind project due to lower capacity factors during the third quarter 2008 compared to the third quarter of 2007. The year-to-date increase in earnings was primarily due to availability warranty income recorded during the second and third quarters of 2008, related to the Suzlon wind turbines at the Crosswinds

and Hardin wind project sites. The Hardin and the Crosswinds wind projects achieved commercial operation in May 2007 and June 2007, respectively.

Earnings from the Big 4 projects decreased $16 million and $43 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The decreases in earnings were primarily due to lower earnings from the Sycamore and Watson projects due to lower pricing. For further discussion regarding power sales from the Sycamore and Watson projects, refer to "Item 1. Business—Overview of Facilities—Big 4 Projects" of EME's annual report on Form 10-K for the year ended December 31, 2007. Earnings from the Watson project are based on revised pricing effective January 1, 2008. Watson Cogeneration and SCE have disputed the commencement date of the prior contract which in turn affected the expiration date (Watson Cogeneration's position is April 2008 whereby SCE's position is December 2007).

Earnings from the Doga project decreased $6 million for the nine months ended September 30, 2008, compared to the corresponding period of 2007. The decrease in earnings was attributable to EME accounting for its ownership in the Doga project, effective March 31, 2007, on the cost method (earnings are recognized when cash is distributed from the project).

EME's third quarter equity in income from its energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer months.

EME corporate interest income decreased $18 million and $45 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The decreases were primarily attributable to lower average cash equivalents and short-term investment balances and lower interest rates in 2008 compared to 2007.

EME's interest expense to third parties, before capitalized interest, decreased $2 million and increased $49 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The year-to-date increase primarily resulted from

EME's refinancing activities in May 2007. Capitalized interest increased $4 million and $11 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007, due to wind projects under construction.

Administrative and general expenses decreased $2 million and increased $12 million for the third quarter and nine months ended September 30, 2008, respectively, compared to the corresponding periods of 2007. The year-to-date increase was primarily due to higher labor costs and consulting expenses resulting from EME's growth activities.

Loss on early extinguishment of debt was $160 million for the nine-month period ended September 30, 2007 related to the early repayment of EME's 7.73% senior notes due June 15, 2009 and Midwest Generation's 8.75% second priority senior secured notes due May 1, 2034.

Income (loss) from discontinued operations, net of tax, was $6 million and $(4) million for the third quarters of 2008 and 2007, respectively, and $0.1 million and $1 million for the nine months ended September 30, 2008 and 2007, respectively. The gains in the third quarter of 2008 were primarily due to adjustments for foreign exchange gains associated with contract indemnities related to EME's sale of its international projects in December 2004. For the nine months ended September 30, 2008, these gains were offset by losses primarily due to adjustments for foreign exchange losses and interest expense recorded during the first six months of 2008 associated with the aforementioned contract indemnities. The year-to-date income in 2007 was largely attributable to distributions received from the Lakeland project. For further discussion regarding the Lakeland project, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Discontinued Operations" of EME's annual report on Form 10-K for the year ended December 31, 2007.

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

The following discussion of liquidity and capital resources is organized in the following sections:

		Page

EME's Liquidity		37
Business Development		38
Capital Expenditures		39
EME's Historical Consolidated Cash Flow		40
Credit Ratings		41
Margin, Collateral Deposits and Other Credit Support for Energy Contracts		41
EME's Liquidity as a Holding Company		42
Dividend Restrictions in Major Financings		42
Contractual Obligations and Contingencies		43
Off-Balance Sheet Transactions		45
Environmental Matters and Regulations		46

For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2007.

At September 30, 2008, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.8 billion, EME had a total of $23 million of available borrowing capacity under its $600 million corporate credit facility, and Midwest Generation had a total of $22 million of available borrowing capacity under its $500 million working capital facility. EME's consolidated debt at September 30, 2008 was $4.7 billion. In addition, EME's subsidiaries had $3.6 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 26 years.

The following table summarizes the status of the EME and Midwest Generation credit facilities at September 30, 2008:

Access to the capital markets has become subject to increased uncertainty due to the financial market and economic conditions discussed in "Management's Overview; Critical Accounting Policies—Management's Overview." Accordingly, EME's liquidity is currently comprised of cash on hand and cash flow generated from operations. Pending recovery of the capital markets, EME intends to preserve capital by focusing on a more selective growth strategy (primarily completion of projects under construction, including the Big Sky project in Illinois, and development of sites for future renewable projects deploying current turbine commitments), and using its cash and future cash flow to meet its existing contractual commitments. Moreover, disruption in the financial markets appears to have reduced trading activity in power markets which may affect the level and duration of future hedging activity and potentially increase the volatility of earnings. Long-term disruption in the capital markets could adversely affect EME's business plans and potentially impact EME's financial position.

EME has undertaken a number of activities in 2008 with respect to wind projects, including the following:

In addition, EME submitted bids in competitive solicitations to supply power from solar projects under development in California and has had a number of its proposals short-listed by utilities. Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission interconnection, control of sites, and construction costs estimates, as well as the negotiation of power sales agreements. To support these development activities, EME entered into an agreement with First Solar Electric, LLC to provide design, engineering, procurement, and construction services for solar projects for identified customers, subject to the satisfaction of certain contingencies and entering into definitive agreements for such services for each project.

At September 30, 2008, the estimated capital expenditures through 2010 by EME's subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill inerting projects and ash site disposal development. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control at the Homer City facilities and various projects at the Illinois Plants to achieve specified emissions reductions such as installation of mercury controls. For further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Significant Industry and EME Developments—Environmental Regulations Affecting Coal Plants," "Management's Overview—Significant Industry and EME Developments—Increase in Equipment and Construction Costs," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations—Air Quality Regulation—Clean Air Interstate Rule—Illinois," and "—Environmental Matters and Regulations—Air Quality Regulation—Mercury Regulation" of EME's annual report on Form 10-K for the year ended December 31, 2007.

EME expects to make substantial investments in new projects during the next several years. At September 30, 2008, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 942 MW. The turbine commitments generally represent approximately two-thirds of the total capital costs of EME's wind projects. As of September 30, 2008, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits, an interconnection agreement(s) or other agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed.

In addition, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of the Walnut Creek project. During the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project included in turbine commitments in the above table. Subject to the resolution of the legal challenges discussed below and availability of financing, EME intends to construct the project in advance of the 2013 start date in the power sales contract with total installed costs, excluding interest during construction, estimated in the range of $500 million to $600 million.

In July 2008, the Los Angeles Superior Court found that actions taken by the SCAQMD, in promulgating rules that had made available a "Priority Reserve" of emissions credits for new power generation projects, did not satisfy California environmental laws. In November 2008, the Los Angeles Superior Court issued a writ of mandate enjoining SCAQMD from issuing Priority Reserve emission credits to any facility, including new power projects, until a satisfactory environmental analysis is completed. The writ also ordered the SCAQMD to refrain from taking any action relating to power plant projects approved after August 2007 pursuant to the priority reserve rules until the SCAQMD completes a satisfactory environmental analysis. Separately, in August 2008, substantially the same plaintiffs in the Superior Court action sued the SCAQMD in federal court alleging that the emission credits contained in SCAQMD's Priority Reserve are invalid and seeking to enjoin SCAQMD from transferring them. Due to the lack of available particulate matter (PM10) and SO₂ emission credits in the air basins regulated by SCAQMD, and the difficulty of creating new ones, Walnut Creek is unable to acquire the emission credits that it needs prior to beginning construction until favorable resolution of these legal challenges.

Cash provided by operating activities from continuing operations decreased $93 million in the first nine months of 2008, compared to the first nine months of 2007. The 2008 decrease was primarily attributable to higher margining posted with futures brokers and ISOs to support hedging and trading activities and the purchase of additional NO_X emission allowances in 2008 by Midwest Generation.

Cash provided by financing activities from continuing operations increased $1.3 billion in the first nine months of 2008, compared to the first nine months of 2007. The 2008 increase was primarily attributable to an increase in borrowings in 2008 under EME's corporate credit facility and Midwest Generation's working capital facility. In May 2007, net proceeds of $2.7 billion were received from EME's issuance of senior notes, which were mostly used to repay $587 million of EME's outstanding senior notes, $999.8 million of Midwest Generation's second priority senior secured notes, and $327.8 million of Midwest Generation's senior secured term loan facility. Tender premiums and related fees of $137 million were paid in 2007 associated with the aforementioned financing. In addition, $925 million in dividend payments were made to Mission Energy Holding Company, EME's parent company, in 2007.

Cash used in investing activities from continuing operations increased $357 million in the first nine months of 2008, compared to the first nine months of 2007. The 2008 increase was primarily due to lower net maturities and sales of marketable securities in 2008, compared to 2007. Partially offsetting these increases were proceeds from the sale of 33% of EME's membership interest in the Elkhorn Ridge wind project during the second quarter of 2008.

Credit ratings for EME, Midwest Generation and EMMT, at September 30, 2008, were as follows:

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

EME does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries.

The Homer City sale-leaseback documents restrict EME Homer City's ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through EMMT; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participants that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2008. EME Homer City continues to be in compliance with the terms of the consent. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities."

To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EME subsidiary engaged in the power marketing and trading business. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, because the credit ratings of EMMT and EME are below investment grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. At September 30, 2008, EMMT had deposited $81 million in cash with clearing brokers in support of futures contracts and had deposited $66 million in cash with counterparties in support of forward energy and congestion contracts. In addition, EME had issued letters of credit of $4 million in support of commodity contracts at September 30, 2008.

Future cash collateral requirements may be higher than the margin and collateral requirements at September 30, 2008, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of September 30, 2008 could increase by approximately $90 million over the remaining life of the contracts using a 95% confidence level. Certain EMMT hedge contracts do not require margining, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—EME's Liquidity as a Holding Company" and "—Dividend Restrictions in Major Financings." Furthermore, the hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions would result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT also has hedge contracts that do not require margining, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of hedge contracts with credit-risk related contingent features was a net asset at September 30, 2008 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or posting additional collateral under the contingent features described above.

Midwest Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois Plants. At September 30, 2008, Midwest Generation had available $22 million of borrowing capacity under this credit facility. As of September 30, 2008, Midwest Generation had $29 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $23 million of borrowing capacity available under a $600 million working capital facility to provide credit support to subsidiaries. See "—EME's Liquidity as a Holding Company" for further discussion.

At September 30, 2008, EME had corporate cash and cash equivalents and short-term investments of $882 million to meet liquidity needs. See "—EME's Liquidity." Cash on hand and cash distributions from EME's subsidiaries and partnership investments represent EME's major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "—Dividend Restrictions in Major Financings."

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate debt-to-corporate capital ratio as such terms are defined in the credit facility. The key ratios at September 30, 2008 or for the 12 months ended September 30, 2008 are as follows:

Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries are not available to satisfy EME's

obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at September 30, 2008 or for the 12 months ended September 30, 2008:

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 "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividend Restrictions in Major Financings" of EME's annual report on Form 10-K for the year ended December 31, 2007.

EME's long-term principal debt maturities plus interest payments as of September 30, 2008 were $82 million for the remainder of 2008, $342 million in 2009, $329 million in 2010, $330 million in 2011, $1.2 billion in 2012, and $5.4 billion thereafter. These amounts have been updated primarily to reflect EME's financing activities completed during the third quarter of 2008. See "—EME's Liquidity" for additional details.

EME and General Electric Company entered into an agreement during the second quarter of 2008 with respect to the purchase of 200 wind turbines (totaling 300 MW) together with related services and warranties. The wind turbines are to be delivered in 2010. The agreement contains certain delivery schedules and performance guarantees, along with provisions for liquidated damages if those

guarantees are not met by General Electric. EME may terminate the purchase of individual turbines, or groups of turbines, for convenience; upon such termination, EME would be obligated to pay agreed termination charges to General Electric.

Included as part of the wind projects or turbine purchase commitments described above, EME had purchased turbines from Suzlon Wind Energy Corporation (Suzlon), 189 of which are in service or at project sites under construction. Rotor blade cracks were identified on certain of these Suzlon wind turbines and Suzlon has advised EME that such cracks have also appeared on turbines with another Suzlon customer. Suzlon, with review and oversight from EME's technical experts, is currently completing its analysis and blade testing to determine the root cause of the blade crack issues. To address the commercial impact of these issues on EME and its projects, during the second quarter of 2008, EME signed an agreement with Suzlon providing EME with enhanced warranty and credit protections with respect to the Suzlon turbine issues including the rotor blade crack issues. Under this agreement, EME obtained the right to elect not to purchase some or all of the wind turbines that were to be delivered in 2009 without payment of cancellation fees. On May 30, 2008, EME notified Suzlon of its election not to purchase 150 turbines (315 MW) due to the time needed to complete the root cause analysis and paid no cancellation fees.

In addition to the Suzlon turbines, EME has purchased 71 turbines from Clipper Turbine Works, Inc. (Clipper) of which 20 are in service at the Jeffers wind project and 40 are planned for the High Lonesome wind project. EME recently learned that new problems have been discovered in the blades on certain Clipper wind turbines. EME is expecting to work with Clipper to analyze the root causes of the blade problems and address commercial matters that result from the impact of these issues on its projects.

For further discussion, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Wind Turbine Performance Issues" of EME's annual report on Form 10-K for the year ended December 31, 2007. Also see "Market Risk Exposures—Credit Risk."

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the first quarter of 2008. The remaining payments due under this contract are $15 million.

For a discussion of EME's off-balance sheet transactions, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Transactions" of EME's annual report on Form 10-K for the year ended December 31, 2007. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report.

For a discussion of EME's environmental matters, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations" of EME's annual report on Form 10-K for the year ended December 31, 2007 and the notes to the consolidated financial statements set forth therein. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as follows:

On July 1, 2008, EME began operating activated carbon injection technology to reduce mercury emissions at the Fisk, Crawford, and Waukegan stations. EME anticipates that the same technology will be implemented at the rest of the Illinois Plants in the third quarter of 2009 and at the Homer City facilities in 2010.

On March 12, 2008, the US EPA signed a final rule that implements revisions to the primary and secondary national ambient air quality standards for ozone, originally proposed on July 11, 2007. With regard to the primary standard for ozone, the US EPA has reduced the 8-hour standard to 0.075 parts per million (ppm) from the current standard of 0.84 ppm. The rule became effective on May 27, 2008. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. Based on 2005-2007 data, the Chicago-Gary-Lake County region, in which five of the Illinois Plants are located, is likely to be in non-attainment with the new standard. Available data indicates that the area in which the Homer City facilities are located is likely to be in attainment. EME intends to consider the new standards as part of its overall plan for environmental compliance.

In July 2008, a three-judge panel of the District of Columbia Circuit Court of Appeals issued a decision to vacate the CAIR in its entirety and remand to the US EPA to issue a new rule consistent with the decision once the Court issues its mandate. The decision raised significant questions as to whether the US EPA will be able to design cap-and-trade programs for NO_X and SO₂ that are authorized and consistent with the Clean Air Act provisions that address upwind contributions to downwind states' noncompliance with national ambient air quality standards for ozone and fine particulate matter. Following the decision, the US EPA requested that states reinstate the existing "SIP Call" ozone season NO_X cap-and-trade program, which was due to be replaced by the CAIR.

established by the CAIR. Illinois also adopted the CAIR emissions trading programs, but in addition requires Midwest Generation to achieve reductions of NO_X and SO₂ (and mercury) through environmental control retrofits and plant shutdowns pursuant to a Combined Pollutant Standard. However, if the US EPA is required to propose a new regulation to address interstate transport of air pollution, EME cannot be certain that the emissions reductions currently required by the Combined Pollutant Standard will be sufficient to meet such revised regulations. In addition, the US EPA has allowed states to rely on compliance with the CAIR to satisfy obligations under other Clean Air Act programs, including regional haze regulations and reasonably available control technology requirements. Depending on what happens with respect to the CAIR, the Illinois Plants and the Homer City facilities may be subject to additional requirements pursuant to these programs.

On February 28, 2008, the Native Village of Kivalina and the City of Kivalina, located off the coast of Alaska, filed a complaint in federal court in California against 24 defendants, including Edison International, who directly or through subsidiaries engage in electric generating, oil and gas, or coal mining lines of business. Although EME is not named as a defendant, the complaint identifies EME as a direct or indirect operating subsidiary of Edison International through which Edison International engages in electric power generation. The complaint contends that the alleged global warming impacts of the GHG emissions associated with the defendants' business activities are destroying the plaintiffs' village through the melting of Arctic ice that had previously protected the village from winter storms. The plaintiffs further allege that the village will soon need to be abandoned or relocated at a cost of between $95 million and $400 million. EME cannot predict the outcome of this lawsuit.

EME's primary market risk exposures are associated with the sale of electricity and capacity from, and the procurement of fuel for, its merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures.

This section discusses these market risk exposures under the following headings:

For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2007.

EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

In addition to prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary.

EME uses "earnings at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions at the Illinois Plants, the Homer City facilities, and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss, and earnings at risk measures the potential change in value of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and counterparty credit exposure limits.

To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its electricity sales, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:

The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether the types of hedge transactions set forth above at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME's ability to enter into hedging transactions depends upon its and Midwest Generation's credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois Plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity support for implementation of EME's contracting strategy for the Illinois Plants. In addition, Midwest Generation may grant liens on its property in support of hedging transactions associated with the Illinois Plants. In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See "—Credit Risk" below.

All the energy and capacity from the Illinois Plants is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. As discussed further below, power generated at the Illinois Plants is generally sold into the PJM market.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois Plants are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including the Cinergy Hub in the Midwest Independent Transmission System Operator (MISO). These trading hubs have been the most liquid locations for hedging purposes. See "—Basis Risk" below for further discussion.

PJM has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in the PJM control area and are physically connected to high-voltage transmission lines serving this market.

The following table depicts the average historical market prices for energy per megawatt-hour during the first nine months of 2008 and 2007.

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at September 30, 2008:

The following table summarizes Midwest Generation's hedge position at September 30, 2008:

All the energy and capacity from the Homer City facilities is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City's primary trading hub) during the first nine months of 2008 and 2007:

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at September 30, 2008:

The following table summarizes EME Homer City's hedge position at September 30, 2008:

The average price/MWh for EME Homer City's hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. See "—Basis Risk" below for a discussion of the difference.

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region's need for generation capacity, the cost of which is allocated to load-serving entities through a locational reliability charge.

The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at September 30, 2008:

		Fixed Price Capacity Sales

		Through RPM Auction, Net					Non-unit Specific Capacity Sales				Variable Capacity Sales
		MW		Price per MW-day			MW		Price per MW-day		MW		Price per MW-day
October 1, 2008 to May 31, 2009
	Midwest Generation		2,954	$	122.42	(1)		880	$	64.35		—		—
	EME Homer City		820		111.92			—		—		905	$	62.22	(2)
June 1, 2009 to May 31, 2010
	Midwest Generation		4,614		102.04			715		71.46		—		—
	EME Homer City		1,670		191.32			—		—		—		—
June 1, 2010 to May 31, 2011
	Midwest Generation		4,929		174.29			—		—		—		—
	EME Homer City		1,813		174.29			—		—		—		—
June 1, 2011 to May 31, 2012
	Midwest Generation		4,582		110.00			—		—		—		—
	EME Homer City		1,771		110.00			—		—		—		—

Revenues from the sale of capacity from Midwest Generation and EME Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM's RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, and the CONE.

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

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

Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City facilities and for settlement points at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Illinois Plants. EME's hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME's revenues with respect to such forward contracts include:

Under PJM's market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal transmission losses in addition to the component included for congestion. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as

"basis risk." During the nine months ended September 30, 2008, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 16%, compared to 15% during the nine months ended September 30, 2007. The monthly average difference during the 12 months ended September 30, 2008 ranged from 7% to 21%. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois Plants, although the implementation of marginal losses on June 1, 2007 has lowered energy prices at the Illinois Plants busbars.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub, the Northern Illinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for EME Homer City. A financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME's hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

The Illinois Plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements extending through 2011. The following table summarizes the amount of coal under contract at September 30, 2008 for the remainder of 2008 and the following three years.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian coal, which are related to the price of coal purchased for the Homer City facilities, increased substantially during 2008 from 2007 year-end prices. The price of Northern Appalachian coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to $143 per ton at October 3, 2008 from $55.25 per ton at December 21, 2007, as reported by the Energy Information Administration. Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Illinois Plants increased during 2008 from 2007 year-end prices. The price of PRB coal increased to $14.50 per ton at October 3, 2008 from $11.50 per ton at December 21, 2007, as reported by the Energy Information Administration. The 2008 increase in North Appalachian coal prices were primarily attributable to: 1) increased international and Atlantic basin coal demand, 2) port and rail infrastructure problems and monsoon flooding in Australia, 3) a record cold winter in China, and 4) an energy crisis in South Africa.

EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing

transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are more than 50% of the delivered cost of PRB coal to the Illinois Plants).

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances, and Illinois and Pennsylvania regulations implemented the federal NO_X SIP Call requirement. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs.

The average price of purchased SO₂ allowances decreased to $316 per ton during the first nine months of 2008 from $521 per ton during 2007. The price of SO₂ allowances, determined by obtaining broker quotes and information from other public sources, was $155 per ton as of September 30, 2008.

For an updated discussion of environmental regulations related to emissions, see "Liquidity and Capital Resources—Environmental Matters and Regulations—Air Quality Regulation—Clean Air Interstate Rule."

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview; Critical Accounting Policies—Critical Accounting Policies—Derivative Financial Instruments and Hedging Activities" of EME's annual report on Form 10-K for the year ended December 31, 2007.

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating revenues. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows.

The following table summarizes unrealized gains (losses) from non-trading activities for the third quarters of 2008 and 2007 and nine months ended September 30, 2008 and 2007:

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. EME had power contracts with Lehman Brothers Commodity Services, Inc., a subsidiary of Lehman Brothers Holdings, for Midwest Generation for 2009 and 2010. The obligations of Lehman Brothers Commodity Services under the power contracts are guaranteed by Lehman Brothers Holdings. These contracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the power contracts as such, effective September 12, 2008 when it determined that it was no longer probable that performance would occur. The amount recorded in accumulated comprehensive income (loss) related to the effective portion of the hedges was $24 million pre-tax on this date. Since the power contracts are no longer being accounted for as cash flow hedges under SFAS No. 133, the subsequent change in fair value was recorded as an unrealized loss during the third quarter of 2008. Under SFAS No. 133, the pre-tax amount recorded in accumulated other comprehensive income (loss) will be reclassified to operating revenues based on the original forecasted transactions in 2009 ($15 million) and 2010 ($9 million), unless it becomes probable that the forecasted transactions will no longer occur.

During the three months ended September 30, 2008, unrealized gains resulting from the ineffective portion of cash flow hedges resulted primarily from a change in the fair value of derivatives from a net derivative liability position at June 30, 2008 to a net derivative asset position at September 30, 2008. SFAS No. 133 limits the amounts recorded in accumulated other comprehensive income to the lesser of the change in the fair value of the derivative or the hedge item (forecasted transaction).

At September 30, 2008, unrealized losses of $47 million (including the unrealized losses described above related to Lehman Brothers Commodity Services) were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($8 million for the remainder of 2008, $21 million for 2009, and $18 million for 2010).

The following table summarizes the fair values for outstanding derivative financial instruments used in EME's continuing operations for purposes other than trading, by risk category:

In assessing the fair value of EME's non-trading derivative financial instruments, EME uses quoted market prices and forward market prices adjusted for credit risk. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The increase in fair value of electricity contracts at September 30, 2008 as compared to December 31, 2007 is attributable to a decline in the average market prices for power as compared to contracted prices at September 30, 2008, which is the valuation date. The following table summarizes the maturities and the related fair value, primarily based on actively traded prices, of EME's commodity derivative assets and liabilities as of September 30, 2008:

Prices actively quoted in the preceding table includes derivatives whose fair value is based on quoted market prices and forward market prices adjusted for credit risk.

The fair value of the commodity financial instruments related to energy trading activities as of September 30, 2008 and December 31, 2007, are set forth below:

The change in the fair value of trading contracts for the nine months ended September 30, 2008, was as follows:

EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Fair Value Measurements," for further discussion of EME's adoption of SFAS No. 157.

In the table below, prices actively quoted includes both exchange traded derivatives and non-exchange traded derivatives which are priced based on forward market prices adjusted for credit risk. Also in the table, fair value based on models and other valuation methods includes illiquid financial transmission rights and over-the-counter derivatives at illiquid locations and long-term power agreements which would be considered Level 3 derivative positions. For long-term power agreements, EME's subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.

The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of September 30, 2008):

In conducting EME's hedging and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the

portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At September 30, 2008, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

The credit risk exposure set forth in the above table is comprised of $197 million of net accounts receivable and payables and $194 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties.

Included in the table above are exposures to financial institutions with credit ratings of A- or above. Due to recent developments in the financial markets, the credit ratings may not be reflective of the related credit risks. See "Management's Overview—Financial Markets and Economic Conditions" for further discussion. The total net exposure to financial institutions at September 30, 2008 was $129 million. This total net exposure excludes positions with Lehman Brothers Holdings and its subsidiaries. Five financial institutions comprise 31% of the net exposure above with the largest single net exposure with a financial institution representing 18%. For further discussion, see "Management's Overview—Financial Markets and Economic Conditions—Bankruptcy of Lehman Brothers Holdings." In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $147 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. Margining posted to support these activities also exposes EME to credit risk of the related entities.

EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a power purchase agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power project.

In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

EME's merchant plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 50% of EME's consolidated operating revenues for the nine months ended September 30, 2008. Moody's rates PJM's debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At September 30, 2008, EME's account receivable due from PJM was $57 million.

EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 13% of EME's consolidated operating revenues during the nine months ended September 30, 2008. Commonwealth Edison's senior unsecured debt ratings are BBB- by S&P and Ba1 by Moody's. At September 30, 2008, EME's account receivable due from Commonwealth Edison was $17 million.

For the nine months ended September 30, 2008, a third customer, Constellation Energy Commodities Group, Inc., accounted for 13% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from EME's merchant plants and largely consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB by S&P and Baa2 by Moody's. At September 30, 2008, EME's account receivable due from Constellation was $26 million.

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

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated long-term obligations (including current portion) was $4.3 billion at September 30, 2008, compared to the carrying value of $4.7 billion.

For a discussion of EME's regulatory matters, refer to "Item 1. Business—Regulatory Matters" of EME's annual report on Form 10-K for the year ended December 31, 2007. There have been no

significant developments with respect to regulatory matters specifically affecting EME since the filing of EME's annual report on Form 10-K for the year ended December 31, 2007, except as follows:

On April 4, 2008, the FERC issued an order rejecting PJM's request to revise its RPM to reflect PJM's claimed rise in its CONE values. CONE is one of the two components used by PJM to determine its Variable Resource Requirement curve for the RPM auction. PJM also proposed to add a new section to its tariff permitting PJM to unilaterally request a CONE increase for use in its May 2008 RPM auction for the 2011/2012 delivery year. In rejecting the proposal, the FERC found that PJM had not met timing provisions in its existing tariff to provide sufficient time for stakeholder review of the analysis and advance planning and that it had also failed to establish that its proposal to revise that provision was necessary on a one-time emergency basis to ensure reliable service.

The effect of FERC's actions on future RPM auctions cannot be determined at this time. The CONE as established for the May 2008 RPM auction for the 2011/2012 delivery year is lower than the PJM request.

For a discussion of market risk sensitive instruments, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures" of EME's annual report on Form 10-K for the year ended December 31, 2007. Refer to "Market Risk Exposures" in Item 2 of this quarterly report on Form 10-Q for an update to that disclosure.

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

There were changes as described below 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.

Effective July 1, 2008, the human resources module was implemented as part of the Edison International enterprise-wide project. The implementation of this module and the related workflow capabilities resulted in a material change to EME's financial reporting controls and procedures. Therefore, EME is modifying the design and documentation of the internal control process and procedures relating to the new timekeeping system to replace and supplement existing internal controls over financial reporting, as appropriate. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in EME's internal control over financial reporting.

For a discussion of EME's legal proceedings, refer to "Item 3. Legal Proceedings" of EME's annual report on Form 10-K for the year ended December 31, 2007. 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, 2007, except as follows:

On July 12, 2005, EMMT received a letter from the staff of the FERC Office of Enforcement (FERC Staff) stating that, by the letter, it was commencing a preliminary, non-public investigation of certain bidding practices of EMMT. In October 2006, EMMT was advised that the FERC Staff was prepared to recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged violation of the Energy Policy Act of 2005 and the FERC's rules regarding market behavior, all with respect to certain bidding practices previously employed by EMMT. In ensuing exchanges between EMMT and the FERC Staff, EMMT provided information explaining that the business purpose for its bidding practices was the sale for risk mitigation purposes of a certain amount of power in the real-time rather than the day-ahead market.

Discussions with the FERC Staff led to a settlement agreement, which was accepted and adopted by the FERC in an order issued May 19, 2008. In the settlement agreement EMMT, Midwest Generation, and EME acknowledged that during the course of the investigation, although they had had no intent to mislead the FERC Staff, they had at times failed to provide complete and accurate information in response to FERC Staff inquiries, as required by FERC's regulation (18 CFR § 35.41(b) (2007)). The settlement agreement required the payment of $7 million in civil penalties for violation of 18 CFR § 35.41(b) (2007) and development and implementation of a comprehensive regulatory compliance program at an estimated cost of $2 million. The order and settlement agreement operate to terminate the investigation with no assertion of findings of violation of FERC's rules with respect to the bidding practices that were the subject of the investigation.

On June 18 and 19, 2008, various parties, including the Attorney General of the State of Illinois, the Pennsylvania Public Utility Commission, Delaware Public Service Commission, New Jersey Board of Public Utilities, Indiana Utility Regulatory Commission, the Public Utilities Commission of Ohio, the Virginia State Corporation Commission and the Illinois Commerce Commission, filed various interventions and protests seeking to intervene in the FERC investigation docket for the purpose of seeking clarification that the order and settlement agreement did not foreclose third party rights to seek redress against EMMT, Midwest Generation, and EME for any alleged market manipulation as a result of the bidding behavior or, in the alternative, obtaining an order reopening the investigation docket to allow further investigation into the bidding behavior. On October 7, 2008, the FERC issued an order denying the motions to intervene and dismissing the requests for rehearing and other for relief. The order may be appealed by the potential intervenors on or before December 7, 2008.

developing a litigation strategy. EME Homer City cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.

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" of EME's annual report on Form 10-K for the year ended December 31, 2007. Given current financial market and economic conditions, the capital markets are not currently available to EME. EME cannot provide assurance that capital will be available when needed, or if available, whether EME will be able to raise capital on favorable terms. In addition, until capital markets recover, there may be fewer counterparties willing or able to enter into hedge transactions, which would increase EME's exposure to market risks. For more information on these and other developments, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview; Critical Accounting Policies—Financial Markets and Economic Conditions." 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.

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.


(Mark one)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2008
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to


Delaware		95-4031807
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
18101 Von Karman Avenue, Suite 1700 Irvine, California		92612
(Address of principal executive offices)		(Zip Code)
Registrant's telephone number, including area code: (949) 752-5588


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


PJM		PJM Interconnection, LLC
PRB		Powder River Basin
RPM		reliability pricing model
S&P		Standard & Poor's Ratings Services
SCAQMD		South Coast Air Quality Management District
SCE		Southern California Edison Company
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS No. 133		Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS No. 141(R)		Statement of Financial Accounting Standards No. 141(R), "Business Combinations"
SFAS No. 157		Statement of Financial Accounting Standards No. 157, "Fair Value Measurements"
SFAS No. 161		Statement of Financial Accounting Standards No. 161, "Disclosures About Derivative Instruments and Hedging Activities" (an amendment of FASB No. 133)
SIP(s)		state implementation plan(s)
SO₂		sulfur dioxide
US EPA		United States Environmental Protection Agency

		Level 1		Level 2			Level 3			Netting and Collateral(2)		Total at September 30, 2008

		(in millions)
Assets at Fair Value
	Money market funds(1)	$	1,301	$	—		$	19		$	—	$	1,320
	Derivative contracts		1		139			147			—		287
Liabilities at Fair Value
	Derivative contracts	$	—	$	(80	)	$	(6	)	$	46	$	(40	)

	September 30, 2008		December 31, 2007

	(in millions)
Commercial paper	$	1	$	32
Certificates of deposit		—		41
U.S. Treasury securities		—		7
Corporate bonds		—		1
Money market funds		19		—

Total	$	20	$	81

	September 30, 2008		December 31, 2007

	(in millions)
Amortized intangible assets:
Gross carrying amount	$	5	$	5
Less accumulated amortization		2		1

Amortized intangible assets—net	$	3	$	4

Unamortized intangible assets:
Project development rights	$	11	$	14
Option rights		24		24
Purchased emission allowances		39		23

Unamortized intangible assets	$	74	$	61

	September 30, 2008		December 31, 2007

	(in millions)
Coal and fuel oil	$	110	$	100
Spare parts, materials and supplies		53		49

Total	$	163	$	149

	Unrealized Gains (Losses) on Cash Flow Hedges			Unrecognized Losses and Prior Service Costs, Net(1)			Accumulated Other Comprehensive Income (Loss)

	(in millions)
Balance at December 31, 2007	$	(60	)	$	(3	)	$	(63	)
Current period change		150			—			150

Balance at September 30, 2008	$	90		$	(3	)	$	87

		Page

Management's Overview; Critical Accounting Policies		23
Results of Operations		27
Liquidity and Capital Resources		37
Market Risk Exposures		48

		Page

Results of Continuing Operations		27
Results of Discontinued Operations		36
New Accounting Pronouncements		36

	EME			Midwest Generation

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

		564			500
Outstanding borrowings		(423	)		(475	)
Outstanding letters of credit		(118	)		(3	)

Amount available	$	23		$	22

		October through December 2008		2009		2010

		(in millions)
Illinois Plants
	Plant capital expenditures	$	32	$	65	$	106
	Environmental expenditures		24		103		263
Homer City Facilities
	Plant capital expenditures		11		29		55
	Environmental expenditures		3		8		14
New Projects
	Projects under construction		128		24		—
	Turbine commitments		66		794		260
Other capital expenditures			14		16		11

Total		$	278	$	1,039	$	709

	Moody's Rating	S&P Rating	Fitch Rating

EME	B1	BB-	BB-
Midwest Generation	Baa3	BB+	BBB-
EMMT	Not Rated	BB-	Not Rated

Financial Ratio	Covenant

Interest Coverage Ratio	Not less than 1.2 to 1	1.68 to 1
Corporate Debt to Corporate Capital Ratio	Not more than 0.75 to 1	0.60 to 1

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

	2008		2007
January	$	47.09	$	35.75
February		54.46		56.64
March		58.58		42.04
April		53.87		48.91
May		44.49		44.49
June		56.06		39.76
July		63.79		43.40
August		52.66		57.97
September		43.08		39.68

Nine-Month Average	$	52.68	$	45.40

Subsidiary	Financial Ratio	Covenant

Midwest Generation (Illinois Plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.28 to 1
EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.95 to 1

		Page

Commodity Price Risk		48
Accounting for Energy Contracts		56
Fair Value of Financial Instruments		58
Credit Risk		59
Interest Rate Risk		61
Regulatory Matters		61

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

2008
	October	$	43.27
	November		39.76
	December		43.21

2009 Calendar "strip"(2)		$	48.02

2010 Calendar "strip"(2)		$	48.52

		2008				2009				2010				2011

		GWh		Average price/ MWh		GWh		Average price/ MWh		GWh		Average price/ MWh		GWh		Average price/ MWh
Energy Only Contracts(1)(2)
	Northern Illinois Hub—AEP/Dayton Hub		2,765	$	61.35		9,945	$	65.42		6,534	$	68.62		611	$	76.40
Load Requirements Services Contracts(3)(4)
	Northern Illinois Hub		1,015		63.65		1,571		63.65		—		—		—		—

Total estimated GWh			3,780				11,516				6,534				611

	Historical Energy Prices(1) 24-Hour PJM

	Homer City				West Hub
	2008		2007		2008		2007
January	$	54.32	$	40.30	$	66.80	$	44.63
February		61.74		64.27		68.29		73.93
March		65.37		55.00		70.48		61.02
April		61.99		52.42		69.12		58.74
May		49.37		48.12		59.84		53.89
June		78.72		45.88		98.50		60.19
July		72.39		48.23		91.80		58.89
August		60.16		55.44		73.91		71.00
September		52.33		48.90		66.04		60.14

Nine-Month Average	$	61.82	$	50.95	$	73.86	$	60.27

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

2008
	October	$	57.79
	November		55.32
	December		59.53

2009 Calendar "strip"(2)		$	66.23

2010 Calendar "strip"(2)		$	68.31

		September 30, 2008		December 31, 2007

		(in millions)
Commodity price:
	Electricity contracts	$	102	$	(137	)

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years

	(in millions)
Prices actively quoted	$	99	$	21	$	78	$	—	$	—
Price based on models and other valuation methods		3		—		3		—		—

Total	$	102	$	21	$	81	$	—	$	—

	September 30, 2008				December 31, 2007

	Assets		Liabilities		Assets		Liabilities
	(in millions)
Electricity contracts	$	263	$	165	$	141	$	9
Other		3		2		—		—

	$	266	$	167	$	141	$	9

	(in millions)

Fair value of trading contracts at January 1, 2008	$	132
Net gains from energy trading activities		143
Amount realized from energy trading activities		(161	)
Other changes in fair value		(15	)

Fair value of trading contracts at September 30, 2008	$	99

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years			Maturity >5 years

	(in millions)
Prices actively quoted	$	(39	)	$	(32	)	$	(6	)	$	(1	)	$	—
Prices based on models and other valuation methods		138			58			26			26			28

Total	$	99		$	26		$	20		$	25		$	28

	September 30, 2008

Credit Rating(1)	Exposure(2)		Collateral			Net Exposure
	(in millions)
A or higher	$	140	$	—		$	140
A-		56		—			56
BBB+		56		(1	)		55
BBB		87		(6	)		81
BBB-		31		—			31
Below investment grade		21		(4	)		17

Total	$	391	$	(11	)	$	380

Exhibit No.		Description

31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
32		Statement Pursuant to 18 U.S.C. Section 1350.


		EDISON MISSION ENERGY
		By:		/s/ John P. Finneran, Jr. John P. Finneran, Jr. Senior Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)
		Date:		November 7, 2008


Date: November 7, 2008		/s/ Ronald L. Litzinger Ronald L. Litzinger Chairman of the Board, President and Chief Executive Officer


Dated: November 7, 2008
		/s/ Ronald L. Litzinger Ronald L. Litzinger Chief Executive Officer Edison Mission Energy
		/s/ John P. Finneran, Jr. John P. Finneran, Jr. Chief Financial Officer Edison Mission Energy