10-Q 1 a2184976z10-q.htm 10-Q
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark one)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 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

Commission file number 333-68630

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

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

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):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý
(Do not check if a
smaller reporting company)

Smaller reporting company o

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

Number of shares outstanding of the registrant's Common Stock as of May 8, 2008: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

		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	17
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4T.	Controls and Procedures	46
PART II—Other Information
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 6.	Exhibits	47
	Signatures	48

GLOSSARY

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

Btu		British thermal units
Commonwealth Edison		Commonwealth Edison Company
CONE		cost of new entry
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
GAAP		generally accepted accounting principles
GWh		gigawatt-hours
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
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
RPM		reliability pricing model
S&P		Standard & Poor's Ratings Services
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

iii

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

			Three Months Ended March 31,
			2008			2007
Operating Revenues			$	719		$	673
Operating Expenses
	Fuel			187			176
	Plant operations			136			132
	Plant operating leases			44			44
	Depreciation and amortization			44			35
	Gain on buyout of contract and sale of assets (Note 8)			(16	)		—
	Administrative and general			48			39

		Total operating expenses		443			426

	Operating income			276			247

Other Income (Expense)
	Equity in income from unconsolidated affiliates			12			26
	Dividend income			1			1
	Interest income			8			24
	Interest expense			(71	)		(60	)
	Other income (expense), net			6			(1	)

		Total other income (expense)		(44	)		(10	)

	Income from continuing operations before income taxes			232			237
	Provision for income taxes			82			84

Income From Continuing Operations				150			153
	Income (loss) from operations of discontinued subsidiaries, net of tax (Note 5)			(5	)		3

Net Income			$	145		$	156

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

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

			Three Months Ended March 31,
			2008			2007
Net Income			$	145		$	156
Other comprehensive loss, net of tax:
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Other unrealized holding losses arising during period, net of income tax benefit of $92 and $115 for the three months ended March 31, 2008 and 2007, respectively		(138	)		(169	)
		Reclassification adjustments included in net income, net of income tax expense (benefit) of $6 and $(12) for the three months ended March 31, 2008 and 2007, respectively		(8	)		15

Other comprehensive loss				(146	)		(154	)

Comprehensive Income (Loss)			$	(1	)	$	2

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

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

			March 31, 2008		December 31, 2007
Assets
Current Assets
	Cash and cash equivalents		$	1,129	$	994
	Short-term investments			34		81
	Accounts receivable—trade			260		224
	Receivables from affiliates			16		35
	Inventory			156		149
	Derivative assets			29		56
	Margin and collateral deposits			111		85
	Deferred taxes			118		21
	Prepaid expenses and other			106		89

		Total current assets		1,959		1,734

Investments in Unconsolidated Affiliates				377		387

Property, Plant and Equipment				5,039		4,942
	Less accumulated depreciation and amortization			1,094		1,053

		Net property, plant and equipment		3,945		3,889

Other Assets
	Deferred financing costs			40		41
	Long-term derivative assets			91		91
	Restricted cash			45		48
	Rent payments in excess of levelized rent expense under plant operating leases			765		716
	Other long-term assets			381		366

		Total other assets		1,322		1,262

Total Assets			$	7,603	$	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)

			March 31, 2008			December 31, 2007
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	103		$	73
	Payables to affiliates			60			17
	Accrued liabilities			268			289
	Derivative liabilities			168			28
	Interest payable			98			30
	Current maturities of long-term obligations			13			17

		Total current liabilities		710			454

Long-term obligations net of current maturities				3,881			3,806
Deferred taxes and tax credits				361			351
Deferred revenues				65			65
Long-term derivative liabilities				95			88
Other long-term liabilities				532			543

Total Liabilities				5,644			5,307

Minority Interest				41			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 March 31, 2008 and December 31, 2007			64			64
	Additional paid-in capital			1,327			1,326
	Retained earnings			736			596
	Accumulated other comprehensive loss			(209	)		(63	)

Total Shareholder's Equity				1,918			1,923

Total Liabilities and Shareholder's Equity			$	7,603		$	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)

			Three Months Ended March 31,
			2008			2007
Cash Flows From Operating Activities
	Net income		$	145		$	156
	Less: Income (loss) from discontinued operations			5			(3	)

	Income from continuing operations, net		$	150		$	153
	Adjustments to reconcile income to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(12	)		(25	)
		Distributions from unconsolidated affiliates		15			23
		Depreciation and amortization		46			39
		Deferred taxes and tax credits		11			(22	)
		Gain on buyout of contract and sale of assets		(16	)		—
	Changes in operating assets and liabilities:
		Increase in margin and collateral deposits		(27	)		(13	)
		Decrease (increase) in accounts receivable		(17	)		9
		Increase in inventory		(7	)		(2	)
		Decrease (increase) in prepaid expenses and other		(6	)		48
		Increase in rent payments in excess of levelized rent expense		(49	)		(48	)
		Increase in accounts payable and other current liabilities		50			11
		Increase in interest payable		68			52
		Increase in derivative assets and liabilities		(71	)		(112	)
		Other operating—assets		(7	)		—
		Other operating—liabilities		6			10

	Operating cash flow from continuing operations			134			123
	Operating cash flow from discontinued operations			(5	)		3

		Net cash provided by operating activities		129			126

Cash Flows From Financing Activities
	Borrowings on long-term debt			76			30
	Payments on long-term debt agreements			(6	)		(54	)
	Cash dividends to parent			—			(26	)
	Payments to affiliates related to stock-based awards			(5	)		(21	)
	Excess tax benefits related to stock-based awards			1			6
	Financing costs			(1	)		—

		Net cash provided by (used in) financing activities		65			(65	)

Cash Flows From Investing Activities
	Capital expenditures			(117	)		(130	)
	Proceeds from return of capital, loan repayments and sale of assets			8			10
	Purchase of interest of acquired companies			—			(4	)
	Purchase of short-term investments			—			(25	)
	Maturities and sales of short-term investments			47			108
	Decrease in restricted cash			2			36
	Proceeds from (investments in) other assets			1			(62	)

		Net cash used in investing activities		(59	)		(67	)

Net increase (decrease) in cash and cash equivalents				135			(6	)
Cash and cash equivalents at beginning of period				994			1,213

Cash and cash equivalents at end of period			$	1,129		$	1,207

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

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2008
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

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 three months ended March 31, 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.

Short-term Investments

At March 31, 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.

Held-to-maturity securities, which all mature within one year, consisted of the following:

	March 31, 2008		December 31, 2007
	(in millions)
Commercial paper	$	3	$	32
Certificates of deposit		29		41
Treasury bills		2		7
Corporate bonds		—		1

Total	$	34	$	81

Inventory

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

	March 31, 2008		December 31, 2007
	(in millions)
Coal and fuel oil	$	105	$	100
Spare parts, materials and supplies		51		49

Total	$	156	$	149

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. See "—New Accounting Pronouncements—Accounting Principle's 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 $134 million and $36 million at March 31, 2008 and December 31, 2007, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $6 million at March 31, 2008.

New Accounting Pronouncements

Accounting Principles Adopted

FASB Staff Position FIN No. 39-1—

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 statements of cash flows for the three months ended March 31, 2007 has been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flow from continuing operations.

Statement of Financial Accounting Standards No. 159—

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.

Statement of Financial Accounting Standards No. 157—

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.

Accounting Principles Not Yet Adopted

Statement of Financial Accounting Standards No. 141(R)—

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.

Statement of Financial Accounting Standards No. 160—

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 March 31, 2008 this amount was $41 million).

Statement of Financial Accounting Standards No. 161—

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.

Note 2. Fair Value Measurements

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.

The standard establishes a hierarchy for fair value measurements. Financial assets and liabilities carried at fair value on a recurring basis are classified and disclosed in the three categories outlined below:

•: Level 1—Observable inputs that reflect quoted market prices (unadjusted) for identical assets and liabilities in active markets;
•: Level 2—Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly; and
•: Level 3—Unobservable inputs using data that is not corroborated by market data and primarily based on internal company analysis.

EME's assets and liabilities carried at fair value primarily consist of derivative positions. These positions may include forward sales and purchases of physical power, options and forward price swaps which settle only on a financial basis (including futures contracts).

Level 1 includes derivatives that are exchange traded. The fair values are determined using quoted exchange transaction market prices.

Level 2 includes non-exchange traded derivatives using over-the-counter markets. The fair value of these derivatives is determined using forward market prices adjusted for credit risk. The majority of Level 2 derivatives are entered into for hedging purposes.

Level 3 includes derivatives that trade infrequently such as firm transmission rights and over-the-counter derivatives at illiquid locations and long-term power agreements. Where EME does not have observable market prices, EME believes that the transaction price is the best estimate of fair value at inception. For illiquid firm 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 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 and 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.

When appropriate, valuations are adjusted for various factors including liquidity, bid/offer spreads and credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used.

The following table sets forth EME's financial assets and liabilities that were accounted for at fair value as of March 31, 2008 by level within the fair value hierarchy.

	Level 1			Level 2			Level 3			Netting and Collateral(1)			Total at March 31, 2008
	(in millions)
Assets at Fair Value Derivative contracts	$	—		$	18		$	120		$	(6	)	$	132
Liabilities at Fair Value Derivative contracts	$	(91	)	$	(309	)	$	(9	)	$	134		$	(275	)

(1): Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

The following table sets forth a summary of changes in the fair value of EME's Level 3 derivative contracts, net for the three months ended March 31, 2008.

		(in millions)
Fair value of derivative contracts, net at January 1, 2008		$	120
Total realized/unrealized gains (losses):
	Included in earnings(1)		33
	Included in accumulated other comprehensive loss		(2	)
Purchases and settlements, net			(37	)
Transfers out of Level 3			(3	)

Fair value of derivative contracts, net at March 31, 2008		$	111

Change during the period in unrealized gains (losses) related to derivative contracts, net held at March 31, 2008(1)		$	(4	)

(1): Reported in "Operating Revenues" on EME's consolidated statements of income.

Note 3. Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss consisted of the following:

	Unrealized Losses on Cash Flow Hedges			Unrecognized Losses and Prior Service Costs, Net(1)			Accumulated Other Comprehensive Loss
	(in millions)
Balance at December 31, 2007	$	(60	)	$	(3	)	$	(63	)
Current period change		(146	)		—			(146	)

Balance at March 31, 2008	$	(206	)	$	(3	)	$	(209	)

(1): For further detail, see Note 6—Compensation and Benefit Plans.

Unrealized losses on cash flow hedges, net of tax, at March 31, 2008, included unrealized losses on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. As EME's hedged positions for continuing operations are realized, $149 million, after tax, of the net unrealized losses on cash flow hedges at March 31, 2008 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will decrease 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, 2010.

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 losses of $13 million and $1 million during the first quarters of 2008 and 2007, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in operating revenues in EME's consolidated income statements.

Note 4. Variable Interest Entities

EME has a number of wind projects that were consolidated in accordance with FIN 46(R). These projects were funded with nonrecourse debt totaling $23 million at March 31, 2008. Properties serving as collateral for these loans had a carrying value of $64 million ($53 million and $11 million are classified as property, plant and equipment and prepaid expenses and other, respectively, on EME's consolidated balance sheet at March 31, 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 March 31, 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. An 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 $336 million as of March 31, 2008.

Note 5. Discontinued Operations

Lakeland Project

EME received a payment of £0.4 million (approximately $0.8 million) and £4 million (approximately $8 million) in the first quarters of 2008 and 2007, respectively. The after-tax income attributable to the Lakeland project was $0.5 million and $5 million for the first quarters of 2008 and 2007, respectively.

Summarized Financial Information for Discontinued Operations

	Three Months Ended March 31,
	2008			2007
	(in millions)
Income (loss) before income taxes and minority interest	$	(6	)	$	6
Provision (benefit) for income taxes		(1	)		3
Income (loss) from operations of discontinued subsidiaries		(5	)		3

Note 6. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

As of March 31, 2008, EME had made no contributions to its pension plans and estimates to make $21 million of contributions in the last nine months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and the tax-deductible funding limitations.

The following are components of pension expense:

	Three Months Ended March 31,
	2008			2007
	(in millions)
Service cost	$	5		$	4
Interest cost		4			3
Expected return on plan assets		(3	)		(2	)

Total expense	$	6		$	5

Postretirement Benefits Other Than Pensions

As of March 31, 2008, EME had made no contributions to its postretirement benefits other than pensions and estimates to make $2 million of contributions in the last nine months of 2008. Expected

contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

The following are components of postretirement benefits expense:

	Three Months Ended March 31,
	2008		2007
	(in millions)
Service cost	$	1	$	1
Interest cost		1		1

Total expense	$	2	$	2

Note 7. Income Taxes

EME's income tax provision from continuing operations was $82 million and $84 million for the three months ended March 31, 2008 and 2007, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the three months ended March 31, 2008 and 2007, EME recognized $9 million and $5 million, respectively, of production tax credits related to wind projects and $2 million during each of the first quarters of 2008 and 2007 related to estimated state income tax benefits allocated from Edison International.

Note 8. Commitments and Contingencies

Commitments

Capital Improvements

At March 31, 2008, EME's subsidiaries had firm commitments to spend approximately $240 million during the remainder of 2008 and $4 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, cash generated from operations or existing subsidiary credit agreements.

Turbine Commitments

At March 31, 2008, EME had entered into agreements with vendors securing 483 wind turbines (1,076 MW) for an aggregate purchase price of $1.3 billion, with remaining commitments of $474 million in 2008, $540 million in 2009 and $49 million in 2010. At March 31, 2008, EME had recorded wind turbine deposits of $197 million included in other long-term assets in its consolidated balance sheet.

In addition, EME had 30 wind turbines (90 MW) in temporary storage to be used for future wind projects with remaining commitments of $3 million in 2008. At March 31, 2008, EME had recorded $84 million related to these wind turbines included in other long-term assets in its consolidated balance sheet.

Fuel Supply Contracts

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 buyout 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 $20 million.

Standby Letters of Credit

At March 31, 2008, standby letters of credit aggregated $90 million and were scheduled to expire as follows: $75 million in 2008 and $15 million in 2009.

Guarantees and Indemnities

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

Tax Indemnity Agreements

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. 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 termination of the Collins Station lease in April 2004, Midwest Generation continues to have obligations under the tax indemnity agreement with the former lease equity investor.

Indemnities Provided as Part of the Acquisition of the Illinois Plants

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. 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 211 cases for which Midwest Generation was potentially liable and that had not been

settled and dismissed at March 31, 2008. Midwest Generation had recorded a $54 million liability at March 31, 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.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

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 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.

Indemnities Provided under Asset Sale Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At March 31, 2008, EME had recorded a liability of $108 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 March 31, 2008, EME had recorded a liability of $13 million related to these matters.

Capacity Indemnification Agreements

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 March 31, 2008, if payment were required, would be $67 million. EME has not recorded a liability related to this indemnity.

Contingencies

FERC Notice Regarding Investigatory Proceeding against EMMT

In October 2006, EMMT was advised by the enforcement staff at the FERC that it is 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. EMMT is engaged in discussions with the staff to explore the possibility of resolution of this matter. Discussions

to date have been constructive and may lead to a settlement agreement acceptable to both parties. Should these discussions not result in a settlement and a formal proceeding commenced, EMMT will be entitled to contest any alleged violations before the FERC and an appropriate court. EME believes that EMMT has complied with all applicable laws and regulations in the bidding practices that it employed, and intends to contest vigorously any allegation of violation.

Midwest Generation Potential Environmental Proceeding

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990's 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 United States Department of Justice (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 has identified several defenses which it will raise if the government files suit. At this early stage in the process, 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.

Insurance

At March 31, 2008, Midwest Generation had recorded an $11 million receivable related to insurance claims from unplanned outages, of which $6 million relates to business interruption insurance coverage and has been reflected in other income (expense), net in EME's consolidated statements of income.

Environmental Matters and Regulations

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 $4 million at March 31, 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. See "Note 12. Commitments and Contingencies—Environmental Matters and Regulations" in EME's financial statements included in its annual report on Form 10-K for the year ended December 31, 2007 for a more complete discussion of EME's environmental contingencies.

Note 9. Supplemental Cash Flows Information

		Three Months Ended March 31,
		2008		2007
		(in millions)
Cash paid
	Interest (net of amount capitalized)	$	47	$	12
	Income taxes		60		5
	Cash payments under plant operating leases		92		92
Details of assets acquired
	Fair value of assets acquired	$	—	$	23
	Liabilities assumed		—		—

In connection with certain wind projects acquired during March 2007, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments during the first quarter of 2007 which were due upon commencement of construction in 2007 and/or completion of construction scheduled during 2008.

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:

•: supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;
•: the cost and availability of fuel and fuel transportation services;
•: market volatility and other market conditions that could increase EME's obligations to post collateral beyond the amounts currently expected, and the potential effect of such conditions on the ability of EME and its subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;
•: the cost and availability of emission credits or allowances;
•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including the market structure rules applicable to each market;
•: environmental laws and regulations at both state and federal levels, that could require additional expenditures or otherwise affect EME's cost and manner of doing business;
•: the ability of EME to successfully implement its business strategy, including development projects and future acquisitions;
•: the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities, and technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;
•: the ability of EME to borrow funds and access capital markets on favorable terms;
•: the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other aspects of the complex and volatile markets in which EME and its subsidiaries participate;
•: operating risks, including equipment failure, availability, heat rate, output and availability and cost of spare parts and repairs;
•: project development risks, including those related to siting, financing, construction, permitting, and governmental approvals;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;

•: general political, economic and business conditions;
•: weather conditions, natural disasters and other unforeseen events; and
•: EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and payment agreements with EME's respective affiliates.

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in 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 first quarter ended March 31, 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.

This MD&A is presented in four sections:

		Page
Management's Overview; Critical Accounting Policies		18
Results of Operations		20
Liquidity and Capital Resources		28
Market Risk Exposures		33

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING POLICIES

Management's Overview

Net Income Summary

Net income is comprised of the following components:

	Three Months Ended March 31,
	2008			2007
	(in millions)
Income from continuing operations	$	150		$	153
Income (loss) from discontinued operations		(5	)		3

Net Income	$	145		$	156

EME's decrease in income from continuing operations in the first quarter of 2008, compared to the first quarter of 2007 was primarily attributable to higher net interest expense, lower income from the Homer City facilities and the Big 4 projects and higher costs associated with EME's growth activities. These decreases were mostly offset by higher gross margin and the buyout of a coal contract at the Illinois Plants together with higher energy trading income.

See "Results of Operations" for further discussion of EME's operating results.

Growth Activities

Renewable Energy

At March 31, 2008, EME had 566 MW of wind projects in service and another 447 MW of wind projects under construction, with scheduled completion dates during 2008. 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 and turbines in storage totaling 1,166 MW for new wind projects. The majority of the turbines are scheduled to be delivered before the end of 2009.

During the first quarter of 2008, EME commenced pre-construction activities (approximately $55 million committed to date) for a 240 MW planned wind project in Illinois, referred to as the Big Sky project. The project plans to sell electricity into the PJM market as a merchant generator. Pre-construction activities will be limited to equipment purchases, site development and interconnection activities, pending resolution of wind turbine performance issues noted below. Commercial operations of the Forward wind project (29 MW) and Phase I of the Goat Mountain wind project (80 MW) commenced during April 2008.

Thermal Energy

During the first quarter of 2008, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with Southern California Edison Company 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 is subject to approval of the California Public Utilities Commission (CPUC) which Southern California Edison Company requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. Subsequent to March 31, 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project and, subsequently made equipment deposits of $21 million. The total project costs, excluding interest during construction, are estimated in the range of $500 million to $600 million.

Wind Turbines Performance Issues

Included as part of the wind projects or turbine purchase commitments described above, EME has purchased 475 turbines from Suzlon Wind Energy Corporation (Suzlon) and 71 turbines from Clipper Turbine Works, Inc. (Clipper). Rotor blade cracks were identified on certain Suzlon wind turbines, and rotor blade and gearbox problems were identified on certain Clipper wind turbines. Clipper has commenced its remediation plans that are designed to correct the current deficiencies, at its cost. EME is continuing to work with Suzlon to analyze the root causes of the performance issues and address commercial matters that result from the impact of these issues on EME and 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.

Critical Accounting Policies

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—Critical Accounting Policies" of EME's annual report on Form 10-K for the year ended December 31, 2007.

RESULTS OF OPERATIONS

Introduction

This section discusses operating results for the first quarters of 2008 and 2007, and is organized under the following headings:

		Page
Results of Continuing Operations		20
Results of Discontinued Operations		27
New Accounting Pronouncements		27

Results of Continuing Operations

Overview

EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the Illinois Plants and the Homer City facilities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the following project results, 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 first quarters of 2008 and 2007 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Three Months Ended March 31,
		2008			2007
		(in millions)
Project Earnings (Losses) Before Income Taxes(1)
	*Consolidated operations*
	Illinois Plants	$	253		$	189
	Homer City		55			64
	Energy Trading(2)		41			26
	San Juan Mesa		2			2
	Minnesota Wind projects		1			1
	Storm Lake		2			2
	Wildorado		4			—
	Other		(2	)		1
	*Unconsolidated affiliates*
	Big 4 projects		8			18
	Sunrise		(1	)		(2	)
	Doga		—			4
	Other		4			5

			367			310
	Corporate interest income		7			20
	Corporate interest expense		(90	)		(55	)
	Corporate administrative and general		(40	)		(32	)
	Other income (expense), net		(3	)		(1	)

		$	241		$	242

(1): Project earnings are equal to income from continuing operations before income taxes, except with respect to wind projects, which also include production tax credits. Wind project earnings, including the production tax credits set forth in the table below, were $7 million and $5 million for the first quarters of 2008 and 2007, respectively. The project earnings for the wind projects include $9 million and $5 million of production tax credits for the first quarters of 2008 and 2007, respectively. Production tax credits are recognized as wind energy is generated based upon a per kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by the wind projects are recorded as a reduction in income taxes. Accordingly, project earnings represent a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in project earnings for wind projects is more meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles the total project earnings as shown above with income from continuing operations before income taxes and minority interest under GAAP:

	Three Months Ended March 31,
	2008			2007
	(in millions)
Project earnings	$	241		$	242
Less: Production tax credits		(9	)		(5	)

Income from continuing operations before income taxes	$	232		$	237

(2): Income from energy trading represents the gains recognized from price changes related to contracts for electricity, fuels and transmission congestion. The overhead cost of energy trading is included in administrative and general expenses.

Earnings from Consolidated Operations

Illinois Plants

			Three Months Ended March 31,
			2008			2007
			(in millions)
Operating Revenues			$	468		$	431
Operating Expenses
	Fuel			118			109
	Gain on sale of emission allowances(1)			(2	)		(4	)
	Plant operations			94			89
	Plant operating leases			19			19
	Depreciation and amortization			25			25
	Gain on buyout of contract and disposal of assets			(16	)		—
	Administrative and general			6			5

	Total operating expenses			244			243

Operating Income				224			188

Other Income (Expense)
	Interest income on note receivable from EME			28			28
	Interest income (expense) and other			1			(27	)

	Total other income (expense)			29			1

Income Before Taxes			$	253		$	189

Statistics
	Generation (in GWh):
		Energy only contracts		6,538			6,698
		Load requirements services contracts		1,845			1,932

		Total		8,383			8,630
	Aggregate plant performance:
		Equivalent availability(2)		82.5%			88.0%
		Capacity factor(3)		70.3%			71.2%
		Load factor(4)		85.3%			80.9%
		Forced outage rate(5)		11.8%			5.9%
	Average realized price/MWh:
		Energy only contracts(6)	$	53.16		$	49.06
		Load requirements services contracts(7)	$	62.35		$	61.89
	Capacity revenue only (in millions)		$	9		$	2
	Average fuel costs/MWh		$	14.08		$	12.63

(1): The Illinois Plants sold excess SO₂ emission allowances to the Homer City facilities at fair market value. Sales to the Homer City facilities were $2 million during the first quarter of 2008. These sales reduced operating expenses. EME recorded $1 million and eliminated $1 million of intercompany profit during the first quarter of 2008 on emission allowances sold. The amount eliminated represents emission allowances not yet used by the Homer City facilities at March 31, 2008. In addition, EME recorded $2 million and $4 million of intercompany profit during the first quarters of 2008 and 2007, respectively, on emission allowances sold by the Illinois Plants to the Homer City facilities in the fourth quarters of 2007 and 2006, respectively, but not used by the Homer City facilities until the first quarters of 2008 and 2007, respectively.
(2): The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which

result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(3): The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
(4): The load factor is determined by dividing capacity factor by the equivalent availability factor.
(5): Midwest Generation refers to unplanned maintenance as a forced outage.
(6): The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less (plus) unrealized SFAS No. 133 gains (losses) and other non-energy related revenue by (ii) generation. Revenue related to capacity sales are excluded from the calculation of average realized energy price.

		Three Months Ended March 31,
		2008			2007
		(in millions)
Operating revenues		$	468		$	431
Less (plus):
	Load requirements services contracts		(115	)		(119	)
	Unrealized losses		5			22
	Other revenues		(10	)		(5	)

Realized revenues		$	348		$	329

Generation (in GWh)			6,538			6,698
Average realized energy price/MWh		$	53.16		$	49.06

(7): The average realized price reflects the contract price for sales to Commonwealth Edison under load requirements services contracts that include energy, capacity and ancillary services. It is determined by dividing (i) contract revenue less PJM operating and ancillary charges by (ii) generation.

Earnings from the Illinois Plants increased $64 million in the first quarter of 2008, compared to the first quarter of 2007. The 2008 increase in earnings was primarily attributable to higher gross margin as compared to 2007, a gain of $15 million recorded in 2008 related to the buyout of a fuel contract (see "Liquidity and Capital Resources—Contractual Obligations—Fuel Supply Contracts" for further discussion), and estimated insurance recovery of approximately $6 million primarily related to the outages at the Powerton Station described below. In addition, Midwest Generation had lower interest expense in 2008 due to repayment of debt in May 2007. The increase in gross margin was affected by the following factors: (1) lower unrealized losses in 2008 related to hedge contracts described below, (2) higher average realized energy and capacity prices due to higher market prices, (3) lower generation from unplanned outages, and (4) higher coal and transportation costs per megawatt hour in 2008 mainly due to cost escalations included in the transportation contracts.

Included in operating revenues were unrealized losses of $5 million and $22 million for the first quarters of 2008 and 2007, respectively. Unrealized losses are primarily due to 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. During 2008, power prices increased, resulting in mark-to-market losses on economic hedges. At March 31, 2008, unrealized losses of $23 million were recognized from economic hedges and from the ineffective portion of cash flow hedges related to subsequent periods. The ineffective portion of hedge contracts at the Illinois Plants was primarily attributable to changes in the difference between energy prices at NiHub (the settlement point under forward contracts) and the energy prices at the Illinois Plants busbars (the delivery point where power generated by the Illinois Plants is delivered into the transmission system) resulting from marginal losses. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

The earnings of the Illinois Plants included interest income of $28 million for each of the first quarters of 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.

Powerton Station Outage—

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. At March 31, 2008, Midwest Generation had recorded an $11 million receivable primarily related to these claims.

Homer City

		Three Months Ended March 31,
		2008		2007
		(in millions)
Operating Revenues		$	185	$	198
Operating Expenses
	Fuel(1)		72		72
	Plant operations		29		34
	Plant operating leases		25		25
	Depreciation and amortization		4		3
	Administrative and general		1		1

	Total operating expenses		131		135

Operating Income			54		63

Other Income (Expense)
	Interest and other income		1		2
	Interest expense		—		(1	)

	Total other income		1		1

Income Before Taxes		$	55	$	64

Statistics
	Generation (in GWh)		3,192		3,293
	Equivalent availability(2)		87.5%		86.5%
	Capacity factor(3)		77.5%		80.8%
	Load factor(4)		88.5%		93.3%
	Forced outage rate(5)		9.5%		5.8%
	Average realized energy price/MWh(6)	$	55.94	$	57.86
	Capacity revenue only (in millions)	$	8	$	6
	Average fuel costs/MWh	$	22.57	$	21.81

(1): Included in fuel costs were $5 million and $6 million during the quarters ended March 31, 2008 and 2007, respectively, related to the net cost of SO₂ emission allowances. See "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for more information regarding the price of SO₂ allowances.
(2): The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period. Equivalent

availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(3): The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
(4): The load factor is determined by dividing capacity factor by the equivalent availability factor.
(5): Homer City refers to unplanned maintenance as a forced outage.
(6): The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less (plus) unrealized SFAS No. 133 gains (losses) and other non-energy related revenue by (ii) total generation. Revenue related to capacity sales are excluded from the calculation of average realized energy price.

		Three Months Ended March 31,
		2008			2007
		(in millions)
Operating revenues		$	185		$	198
Less (plus):
	Unrealized losses (gains)		1			(1	)
	Other revenues		(8	)		(6	)

Realized revenues		$	178		$	191

Generation (in GWh)			3,192			3,293
Average realized energy price/MWh		$	55.94		$	57.86

Earnings from Homer City decreased $9 million for the first quarter of 2008, compared to the first quarter of 2007. The 2008 decrease was primarily attributable to lower operating revenues attributable to lower average realized energy prices and lower generation (particularly off-peak) as compared to 2007. Higher forced outages in 2008 contributed to lower generation.

Included in operating revenues were unrealized gains (losses) from hedging activities of $(1) million and $1 million for the first quarters of 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. The ineffective portion of hedge contracts at Homer City was primarily attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). At March 31, 2008, unrealized losses of $22 million were recognized primarily from the ineffective portion of cash flow hedges related to subsequent periods. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

Seasonal Disclosure

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.

Energy Trading

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission congestion primarily in the eastern power grid using products available over the counter, through exchanges and from independent system operators. Earnings from energy trading activities were $41 million and $26 million for the first quarters ended March 31, 2008 and 2007, respectively. The 2008 increase in earnings from energy trading activities was primarily attributable to increased revenues from energy trading in the over-the-counter markets and power sales into New York.

Wildorado

Earnings from the Wildorado wind project were $4 million for the first quarter of 2008. EME had no comparable results from the Wildorado wind project for the first quarter of 2007. Commercial operation of the Wildorado wind project commenced during April 2007.

Earnings from Unconsolidated Affiliates

Big 4 Projects

Earnings from the Big 4 projects decreased $10 million for the first quarter of 2008, compared to the first quarter of 2007. The 2008 decrease in earnings was primarily due to lower earnings from the Sycamore and Watson projects due to lower pricing and, for the Kern River project, due to a planned outage in 2008. 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 Southern California Edison Company have disputed the commencement date of the prior contract which in turn affected the expiration date (Watson Cogeneration's position is April 2008 whereby Southern California Edison Company's position is December 2007). Watson is considering filing a claim for recovery of lost profits due to the early expiration date.

Doga

Earnings from the Doga project decreased $4 million for the first quarter of 2008, compared to the first quarter 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).

Seasonal Disclosure

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.

Corporate Interest Income

EME corporate interest income decreased $13 million for the first quarter of 2008, compared to the first quarter of 2007. The decrease was primarily attributable to lower average short-term investment balances and lower interest rates in 2008 compared to 2007.

Corporate Interest Expense

	Three Months Ended March 31,
	2008		2007
	(in millions)
Interest expense to third parties	$	61	$	26
Interest expense to Midwest Generation(1)		29		29

Total corporate interest expense	$	90	$	55

(1): Includes interest expense of EMMT related to loans from Midwest Generation for margining.

Interest Expense to Third Parties

EME's interest expense to third parties, before capitalized interest, increased $37 million for the first quarter of 2008, compared to the first quarter of 2007. The increase primarily resulted from EME's refinancing activities in May 2007. Capitalized interest increased $2 million for the first quarter of 2008, compared to the first quarter of 2007, due to wind projects under construction.

Corporate Administrative and General Expenses

Administrative and general expenses increased $8 million for the first quarter of 2008, compared to the first quarter of 2007. The increase was primarily due to higher labor costs and consulting expenses resulting from EME's growth activities.

Income Taxes

EME's income tax provision from continuing operations was $82 million and $84 million for the three months ended March 31, 2008 and 2007, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." During the three months ended March 31, 2008 and 2007, EME recognized $9 million and $5 million, respectively, of production tax credits related to wind projects and $2 million during each of the first quarters of 2008 and 2007 related to estimated state income tax benefits allocated from Edison International.

Results of Discontinued Operations

Income (loss) from discontinued operations, net of tax, was $(5) million and $3 million for the first quarters of 2008 and 2007, respectively. The loss in 2008 was primarily due to adjustments for foreign exchange losses and interest expense associated with contract indemnities related to EME's sale of its international projects in December 2004. The 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.

New Accounting Pronouncements

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."

LIQUIDITY AND CAPITAL RESOURCES

Introduction

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

		Page
EME's Liquidity		28
Capital Expenditures		28
EME's Historical Consolidated Cash Flow		29
Credit Ratings		30
Margin, Collateral Deposits and Other Credit Support for Energy Contracts		30
EME's Liquidity as a Holding Company		31
Dividend Restrictions in Major Financings		31
Contractual Obligations		32
Off-Balance Sheet Transactions		32
Environmental Matters and Regulations		32

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 Liquidity

At March 31, 2008, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.2 billion, EME had a total of $515 million of available borrowing capacity under its $600 million corporate credit facility, and Midwest Generation had a total of $422 million of available borrowing capacity under its $500 million working capital facility. EME's consolidated debt at March 31, 2008 was $3.9 billion. In addition, EME's subsidiaries had $3.8 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 27 years.

Capital Expenditures

At March 31, 2008, the estimated capital expenditures through 2010 by EME's subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:

		April through December 2008		2009		2010
		(in millions)
Illinois Plants
	Plant capital expenditures	$	56	$	73	$	44
	Environmental expenditures		53		58		246
Homer City Facilities
	Plant capital expenditures		25		34		26
	Environmental expenditures		12		9		8
New Projects
	Projects under construction		142		4		—
	Turbine commitments		484		651		117
Other capital expenditures			45		14		8

Total		$	817	$	843	$	449

Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, railroad interconnection, 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 and a selenium removal system at the Homer City facilities and various projects at the Illinois Plants to achieve specified emissions reductions such as installation of mercury controls. EME plans to fund these expenditures with debt financings, cash on hand or cash generated from operations. 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.

Expenditures for New Projects

EME expects to make substantial investments in new projects during the next several years. At March 31, 2008, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 1,076 MW. The turbine commitments generally represent approximately two-thirds of the total capital costs of EME's wind projects. As of March 31, 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.

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Cash provided by operating activities from continuing operations increased $11 million in the first quarter of 2008, compared to the first quarter of 2007. The increase was due to timing of cash receipts and disbursements related to working capital items.

Consolidated Cash Flows from Financing Activities

Cash provided by financing activities from continuing operations increased $130 million in the first quarter of 2008, compared to the first quarter of 2007. The 2008 increase was primarily attributable to increased borrowings under Midwest Generation's credit facility and lower debt and dividend payments made in 2008, compared to 2007.

Consolidated Cash Flows from Investing Activities

Cash used in investing activities from continuing operations decreased $8 million in the first quarter of 2008, compared to the first quarter of 2007. The 2008 decrease was primarily due to lower

capital expenditures and turbine deposits in 2008, compared to 2007. Partially offsetting this decrease was lower net maturities and sales of marketable securities in 2008, compared to 2007.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT, at March 31, 2008, were as follows:

	Moody's Rating	S&P Rating	Fitch Rating
EME	B1	BB-	BB-
Midwest Generation	Baa3	BB+	BBB-
EMMT	Not Rated	BB-	Not Rated

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.

Credit Rating of EMMT

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 participant 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."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME's hedging and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME's subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. 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 accounts payable and unrealized losses in connection with these hedging and trading activities. At March 31, 2008, EMMT had deposited $32 million in cash with brokers in margin accounts in support of futures contracts and had deposited $79 million with counterparties in support of forward energy and transmission contracts.

In addition, EME had issued letters of credit of $17 million in support of commodity contracts at March 31, 2008.

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2008, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of March 31, 2008 could increase by approximately $470 million over the remaining life of the contracts using a 95% confidence level.

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 March 31, 2008, Midwest Generation had available $422 million of borrowing capacity under this credit facility. As of March 31, 2008, Midwest Generation had $105 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $515 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.

EME's Liquidity as a Holding Company

Overview

At March 31, 2008, EME had corporate cash and cash equivalents and short-term investments of $822 million to meet liquidity needs. See "—EME's Liquidity." Cash distributions from EME's subsidiaries and partnership investments and unused capacity under its corporate credit facility 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."

Dividend Restrictions in Major Financings

General

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.

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at March 31, 2008 or for the 12 months ended March 31, 2008:

Subsidiary		Financial Ratio		Covenant		Actual
Midwest Generation (Illinois Plants)		Debt to Capitalization Ratio		Less than or equal to 0.60 to 1		0.23 to 1
EME Homer City (Homer City facilities)		Senior Rent Service Coverage Ratio		Greater than 1.7 to 1		3.79 to 1

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "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.

Contractual Obligations

Fuel Supply Contracts

Off-Balance Sheet Transactions

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.

Environmental Matters and Regulations

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:

Air Quality Regulation

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 is expected to become effective during the second quarter of 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, Chicago 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.

Climate Change

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 23 corporate defendants, including Edison International and several electric generating, oil and gas, and coal mining companies. 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 greenhouse gas 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.

MARKET RISK EXPOSURES

Introduction

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:

		Page
Commodity Price Risk		33
Accounting for Energy Contracts		41
Fair Value of Financial Instruments		42
Credit Risk		43
Interest Rate Risk		45
Regulatory Matters		45

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.

Commodity Price Risk

Introduction

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 of 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 limits and counterparty credit exposure limits.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, the unhedged portion will be subject to the

risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:

•: the use of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange,
•: forward sales transactions entered into on a bilateral basis with third parties, including electric utilities and power marketing companies,
•: full requirements services contracts or load requirements services contracts for the procurement of power for electric utilities' customers, with such services including the delivery of a bundled product including, but not limited to, energy, transmission, capacity, and ancillary services, generally for a fixed unit price, and
•: participation in capacity auctions.

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.

Energy Price Risk Affecting Sales from the Illinois Plants

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 in PJM, and may also be entered into at other trading hubs, including the AEP/Dayton Hub in PJM and 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 three months of 2008 and 2007.

	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

Quarterly Average	$	53.38	$	44.81

(1): Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.

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 March 31, 2008:

		24-Hour Northern Illinois Hub Forward Energy Prices(1)
2008
	April	$	55.70
	May		49.49
	June		55.06
	July		65.11
	August		63.23
	September		50.13
	October		47.39
	November		45.89
	December		51.86
2009 Calendar "strip"(2)		$	55.48

(1): Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.
(2): Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.

The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at March 31, 2008:

		2008		2009		2010
Energy Only Contracts(1)
	MWh		7,746,450		7,692,290		3,471,950
	Average price/MWh(2)	$	60.85	$	62.38	$	62.58
Load Requirements Services Contracts
	Estimated MWh(3)		3,689,269		1,571,182		—
	Average price/MWh(4)	$	64.21	$	63.65		—
Total estimated MWh			11,435,719		9,263,472		3,471,950

(1): Primarily at Northern Illinois Hub.
(2): The energy only contracts include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at March 31, 2008 is not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.
(3): Under a load requirements services contract, the amount of power sold is a portion of the retail load of the purchasing utility and thus can vary significantly with variations in that retail load. Retail load depends upon a number of factors, including the time of day, the time of the year and the utility's number of new and continuing customers. Estimated MWh have been forecast based on historical patterns and on assumptions regarding the factors that may affect retail loads in the future. The actual load will vary from that used for the above estimate, and the amount of variation may be material.
(4): The average price per MWh under a load requirements services contract (which is subject to a seasonal price adjustment) represents the sale of a bundled product that includes, but is not limited to, energy, capacity and ancillary services. Furthermore, as a supplier of a portion of a utility's load, Midwest Generation will incur charges from PJM as a load-serving entity. For these reasons, the average price per MWh under a load requirements services contract is not comparable to the sale of power under an energy only contract. The average price per MWh under a load requirements services contract represents the sale of the bundled product based on an estimated customer load profile.

Energy Price Risk Affecting Sales from the Homer City Facilities

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 three months of 2008 and 2007:

	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

Quarterly Average	$	60.48	$	53.19	$	68.52	$	59.86

(1): Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub using historical hourly real-time prices provided on the PJM web-site.

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 March 31, 2008:

		24-Hour PJM West Hub Forward Energy Prices(1)
2008
	April	$	72.25
	May		70.35
	June		77.56
	July		94.04
	August		96.78
	September		74.43
	October		72.40
	November		67.70
	December		75.35
2009 Calendar "strip"(2)		$	75.55

(1): Energy prices were determined by obtaining broker quotes and information from other public sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.
(2): Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.

The following table summarizes EME Homer City's hedge position at March 31, 2008:

		2008			2009			2010
MWh			5,434,350			2,867,200			1,022,400
Average price/MWh(1)		$	60.84		$	73.84		$	77.80

(1): The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at March 31, 2008 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

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.

Capacity Price Risk

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 March 31, 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
April 1, 2008 to May 31, 2008
	Midwest Generation	2,629	$	37.27		500	$	21.31	—		—
	EME Homer City	786		40.80		—		—	925	$	70.37	(1)
June 1, 2008 to May 31, 2009
	Midwest Generation	2,978		123.77	(3)	880		64.35	—		—
	EME Homer City	820		113.22	(3)	—		—	905		63.96	(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		—		—	—		—

(1): Actual contract price is a function of NYISO capacity auction clearing prices for April 2008, and forward over-the-counter NYISO capacity prices on March 31, 2008 for May 2008.
(2): Expected price per MW-day is based on forward over-the-counter NYISO prices on March 31, 2008.
(3): During the first quarter of 2008, PJM updated capacity prices for the period June 1, 2008 to May 31, 2009 to reflect the final incremental auction for this planning year. The adjusted price for capacity per MW-day is $113.22 compared to the original price of $111.92. In addition, the price was affected by Midwest Generation's participation in a supplemental RPM auction which resulted in purchasing certain capacity amounts at a price of $10 per MW-day, thereby reducing the aggregate forward capacity sales for this period and increasing the effective capacity price to $123.77.

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 periods from June 1, 2007 through May 31, 2008 and 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.

Basis Risk

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 a settlement point at the Northern Illinois 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:

•: sales of actual generation in the amounts covered by the forward contracts with reference to PJM spot prices at the busbar of the plant involved, plus,
•: sales to third parties at the price under such hedging contracts at designated settlement points (generally the PJM West Hub for the Homer City facilities and the Northern Illinois Hub for the Illinois Plants) less the cost of power at spot prices at the same designated settlement points.

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 three months ended March 31, 2008 and 2007, 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 12% and 11%, respectively. The monthly average difference during the 12 months ended March 31, 2008 ranged from 7% to 24%. 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 and the Northern Illinois 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.

Coal and Transportation Price 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 March 31, 2008 for the remainder of 2008 and the following three years.

	Amount of Coal Under Contract in Millions of Tons(1)
	April through December 2008	2009	2010	2011
Illinois Plants	12.3	11.7	11.7	—
Homer City facilities	4.3	4.4	0.4	0.1

(1): The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Illinois Plants and 13,000 Btu equivalent for the Homer City facilities.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian coal, which are related to the price of coal purchased for the Homer City facilities, increased substantially during the first quarter of 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 $110.00 per ton at March 28, 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 the first quarter of 2008 from 2007 year-end prices. The price of PRB coal increased to $14.55 per ton at March 28, 2008 from $11.50 per ton at December 21, 2007, as reported by the Energy Information Administration. The 2008 increases in coal prices were primarily attributable to: 1) increased Asian coal demand primarily driven by China and India, 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).

Emission Allowances Price Risk

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 $343 per ton during the first quarter of 2008 from $512 per ton during 2007. The price of SO₂ allowances, determined by obtaining broker quotes and information from other public sources, was $340 per ton as of March 31, 2008.

For a discussion of environmental regulations related to emissions, 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.

Accounting for Energy Contracts

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 in the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the first quarters of 2008 and 2007:

		Three Months Ended March 31,
		2008			2007
		(in millions)
Non-qualifying hedges
	Illinois Plants	$	—		$	(22	)
	Homer City		1			(1	)
Ineffective portion of cash flow hedges
	Illinois Plants		(5	)		—
	Homer City		(2	)		2

Total unrealized losses		$	(6	)	$	(21	)

At March 31, 2008, unrealized losses of $45 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($26 million for the remainder of 2008, $14 million for 2009, and $5 million for 2010).

Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

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:

		March 31, 2008			December 31, 2007
		(in millions)
Commodity price:
	Electricity contracts	$	(388	)	$	(137	)

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 decrease in fair value of electricity contracts at March 31, 2008 as compared to December 31, 2007 is attributable to an increase in the average market prices for power as compared to contracted prices at March 31, 2008, which is the valuation date. The following table summarizes the maturities and the related fair value, based on actively traded prices, of EME's commodity derivative assets and liabilities as of March 31, 2008:

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
	(in millions)
Prices actively quoted	$	(388	)	$	(271	)	$	(117	)	$	—	$	—

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.

Energy Trading Derivative Financial Instruments

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

	March 31, 2008				December 31, 2007
	Assets		Liabilities		Assets		Liabilities
	(in millions)
Electricity contracts	$	134	$	17	$	141	$	9
Other		—		1		—		—

Total	$	134	$	18	$	141	$	9

The change in the fair value of trading contracts for the quarter ended March 31, 2008, was as follows:

	(in millions)
Fair value of trading contracts at January 1, 2008	$	132
Net gains from energy trading activities		42
Amount realized from energy trading activities		(51	)
Other changes in fair value		(7	)

Fair value of trading contracts at March 31, 2008	$	116

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 firm transmission rights and over-the-counter derivatives at illiquid locations and long-term power agreements which would be considered Level 3 derivative positions. For illiquid firm transmission rights, EME determines fair value based on the hypothetical sale of illiquid 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 March 31, 2008):

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
	(in millions)
Prices actively quoted	$	(1	)	$	(19	)	$	18	$	—	$	—
Prices based on models and other valuation methods		117			45			14		23		35

Total	$	116		$	26		$	32	$	23	$	35

Credit Risk

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 activities (excluding load requirements services contracts) are measured as either: (i) the sum of 60 days of accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME's subsidiaries enter into master agreements and other arrangements in conducting hedging and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these agreements. At March 31, 2008, the amount of exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

S&P Credit Rating	March 31, 2008
	(in millions)
A or higher	$	14
A-		35
BBB+		86
BBB		15
BBB-		4
Below investment grade		—

Total	$	154

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 plant.

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 48% of EME's consolidated operating revenues for the three months ended March 31, 2008. Moody's rates PJM's senior unsecured debt Aa3. PJM, an independent system operator 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 March 31, 2008, EME's account receivable due from PJM was $100 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 16% of EME's consolidated operating revenues during the three months ended March 31, 2008. Commonwealth Edison's senior unsecured debt ratings are BBB- by S&P and Ba1 by Moody's. At March 31, 2008, EME's account receivable due from Commonwealth Edison was $17 million. For the three months ended March 31, 2008, a third customer accounted for 11% of EME's consolidated operating revenues.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. 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 $3.9 billion at March 31, 2008, compared to the carrying value of $3.9 billion.

Regulatory Matters

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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.

ITEM 4T. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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.

ITEM 1A. RISK FACTORS

For a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial condition, or future results, refer to "Item 1A. Risk Factors" of EME's annual report on Form 10-K for the year ended December 31, 2007. The risks described in EME's annual report on Form 10-K are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.

ITEM 6. EXHIBITS

Exhibit No.		Description
3.2		Amended and Restated By-Laws of Edison Mission Energy.
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.

SIGNATURES

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

		EDISON MISSION ENERGY
		By:		/s/ W. JAMES SCILACCI W. James Scilacci Senior Vice President and Chief Financial Officer
		Date:		May 8, 2008

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TABLE OF CONTENTS
GLOSSARY

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2008 (Unaudited)

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

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING POLICIES

Management's Overview

LIQUIDITY AND CAPITAL RESOURCES

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4T. CONTROLS AND PROCEDURES

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

ITEM 6. EXHIBITS

SIGNATURES