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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, 2007
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 333-68632

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

Delaware (State or other jurisdiction of incorporation or organization)		95-4867576 (I.R.S. Employer Identification No.)
2600 Michelson Drive, Suite 1700 Irvine, California (Address of principal executive offices)		92612 (Zip Code)
Registrant's telephone number, including area code: (949) 852-3576

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 or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer ý

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 9, 2007: 1,000 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	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	54
Item 4.	Controls and Procedures	54
PART II—Other Information
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 6.	Exhibits	55
	Signatures	56

GLOSSARY

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

Ameren		Ameren Corporation
Btu		British thermal units
Commonwealth Edison		Commonwealth Edison Company
EME		Edison Mission Energy
EME Homer City		EME Homer City Generation L.P.
EMMT		Edison Mission Marketing & Trading, Inc.
Exelon Generation		Exelon Generation Company LLC
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN 46(R)		Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities"
FIN No. 48		Financial Accounting Standards Interpretation No. 48, "Accounting for Uncertainty in Income Taxes"
Fitch		Fitch Ratings
GAAP		generally accepted accounting principles
GWh		gigawatt-hours
Illinois EPA		Illinois Environmental Protection Agency
Illinois Plants		EME's largest power plants (fossil fuel), located in Illinois
ISO		independent system operator
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations
MEHC		Mission Energy Holding Company
Midwest Generation		Midwest Generation, LLC
MISO		Midwest Independent Transmission System Operator
MMBtu		million British thermal units
Moody's		Moody's Investors Service, Inc.
MW		megawatts
MWh		megawatt-hours
NAPP		Northern Appalachian
NO_X		nitrogen oxide
NYISO		New York Independent System Operator
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
S&P		Standard & Poor's Ratings Services

SCE		Southern California Edison Company
SCR		selective catalytic reduction
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. 155		Statement of Financial Accounting Standards No. 155, "Accounting for Certain Hybrid Financial Instruments"
SFAS No. 157		Statement of Financial Accounting Standards No. 157, "Fair Value Measurements"
SFAS No. 159		Statement of Financial Accounting Standards No. 159, "The Fair Value Option for Financial Assets and Liabilities, Including an Amendment of FASB Statement No. 115"
SIP		state implementation plan
SO₂		sulfur dioxide
US EPA		United States Environmental Protection Agency

iii

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

			Three Months Ended March 31,
			2007			2006
Operating Revenues			$	673		$	514
Operating Expenses
	Fuel			176			149
	Plant operations			132			124
	Plant operating leases			44			44
	Depreciation and amortization			35			35
	Gain on sale of assets			—			(4	)
	Administrative and general			39			31

		Total operating expenses		426			379

	Operating income			247			135

Other Income (Expense)
	Equity in income from unconsolidated affiliates			26			25
	Interest income			24			20
	Interest expense			(88	)		(100	)
	Other income			—			8

		Total other income (expense)		(38	)		(47	)

	Income from continuing operations before income taxes			209			88
	Provision for income taxes			73			30

Income From Continuing Operations				136			58
	Income from operations of discontinued subsidiaries, net of tax (Note 4)			3			73

Net Income			$	139		$	131

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

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

			Three Months Ended March 31,
			2007			2006
Net Income			$	139		$	131
Other comprehensive income (loss), net of tax:
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(115) and $128 for the three months ended March 31, 2007 and 2006, respectively		(169	)		185
		Reclassification adjustments included in net income, net of income tax expense (benefit) of $(12) and $20 for the three months ended March 31, 2007 and 2006, respectively		15			(30	)

Other comprehensive income (loss)				(154	)		155

Comprehensive Income (Loss)			$	(15	)	$	286

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

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

			March 31, 2007		December 31, 2006
Assets
Current Assets
	Cash and cash equivalents		$	1,207	$	1,241
	Short-term investments			475		558
	Accounts receivable—trade			205		178
	Accounts receivable—affiliates			28		52
	Inventory			160		158
	Derivative assets			33		272
	Margin and collateral deposits			172		69
	Prepaid expenses and other			48		96

		Total current assets		2,328		2,624

Investments in Unconsolidated Affiliates				353		367

Property, Plant and Equipment				4,411		4,272
	Less accumulated depreciation and amortization			1,016		981

		Net property, plant and equipment		3,395		3,291

Other Assets
	Deferred financing costs			46		49
	Long-term derivative assets			88		114
	Restricted cash			55		91
	Rent payments in excess of levelized rent expense under plant operating leases			604		556
	Long-term margin and collateral deposits			47		4
	Other long-term assets			260		187

		Total other assets		1,100		1,001

Total Assets			$	7,176	$	7,283

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

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

			March 31, 2007			December 31, 2006
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	39		$	69
	Accounts payable—affiliates			77			6
	Accrued liabilities			239			270
	Derivative liabilities			89			82
	Interest payable			103			78
	Deferred taxes			9			59
	Current maturities of long-term obligations			115			132

		Total current liabilities		671			696

Long-term obligations net of current maturities				3,824			3,830
Deferred taxes and tax credits				277			351
Deferred revenues				63			61
Long-term derivative liabilities				30			9
Other long-term liabilities				529			523

Total Liabilities				5,394			5,470

Minority Interest				46			47

Commitments and Contingencies (Note 7)
Shareholder's Equity
	Common stock, par value $0.01 per share; 1,000 shares authorized; 1,000 shares issued and outstanding as of March 31, 2007 and December 31, 2006			—			—
	Additional paid-in capital			2,230			2,244
	Accumulated deficit (Note 1)			(441	)		(579	)
	Accumulated other comprehensive income (loss)			(53	)		101

Total Shareholder's Equity				1,736			1,766

Total Liabilities and Shareholder's Equity			$	7,176		$	7,283

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

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

			Three Months Ended March 31,
			2007			2006
Cash Flows From Operating Activities
	Net income		$	139		$	131
	Less: Income from discontinued operations			(3	)		(73	)

	Income from continuing operations, net		$	136		$	58
	Adjustments to reconcile income to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(25	)		(24	)
		Distributions from unconsolidated affiliates		23			42
		Depreciation and amortization		40			39
		Deferred taxes and tax credits		(21	)		14
		Gain on sale of assets		—			(4	)
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		(146	)		109
		Decrease (increase) in accounts receivable		(3	)		144
		Increase in inventory		(2	)		(41	)
		Decrease (increase) in prepaid expenses and other		48			(25	)
		Increase in rent payments in excess of levelized rent expense		(48	)		(48	)
		Decrease in accounts payable and accrued liabilities		(4	)		(18	)
		Increase in interest payable		25			9
		Decrease (increase) in derivative assets and liabilities		36			(15	)
		Other operating—liabilities		10			4

	Operating cash flow from continuing operations			69			244
	Operating cash flow from discontinued operations			3			69

		Net cash provided by operating activities		72			313

Cash Flows From Financing Activities
	Borrowings on long-term debt			30			—
	Payments on long-term debt agreements			(54	)		(214	)
	Payments to affiliates related to stock-based awards			(21	)		(7	)
	Excess tax benefits related to stock option exercises			6			3

		Net cash used in financing activities		(39	)		(218	)

Cash Flows From Investing Activities
	Capital expenditures			(130	)		(59	)
	Proceeds from return of capital and loan repayments			10			—
	Purchase of interest of acquired companies			(4	)		(18	)
	Proceeds from sale of interest in projects			—			43
	Purchase of short-term investments			(25	)		(95	)
	Maturities and sales of short-term investments			108			50
	Decrease in restricted cash			36			9
	Proceeds from (investments in) other assets			(62	)		12

		Net cash used in investing activities		(67	)		(58	)

Net increase (decrease) in cash and cash equivalents				(34	)		37
Cash and cash equivalents at beginning of period				1,241			1,197

Cash and cash equivalents at end of period			$	1,207		$	1,234

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

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2007
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

MEHC'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, 2006. MEHC follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for uncertain tax positions (discussed below in "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 for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three months ended March 31, 2007 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. 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, 2007 and December 31, 2006, EME had classified all marketable debt securities as held-to-maturity and 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, 2007		December 31, 2006
	(in millions)
Commercial paper	$	406	$	417
Certificates of deposit		69		141

Total	$	475	$	558

Income Taxes

MEHC is included in the consolidated federal and state income tax returns of Edison International and participates in tax-allocation and payment agreements with other subsidiaries of Edison International. MEHC calculates its tax provision in accordance with these tax agreements. MEHC's current tax liability or benefit is determined on a "with and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding MEHC's taxable income or loss and state apportionment factors. This method is similar to a separate company return, except that MEHC recognizes, without regard to separate company limitations, additional tax

liabilities or benefits based on the impact to the combined group of including MEHC's taxable income or losses and state apportionment factors.

MEHC accounts for deferred income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted income tax rates. Investment and energy tax credits are deferred and amortized over the term of the power purchase agreement of the respective project. Interest expense and penalties associated with income taxes are reflected in the caption "Provision for income taxes" on the consolidated statements of income. For further discussion of income taxes, see Note 6—Income Taxes.

Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at March 31, 2007 and December 31, 2006 consisted of the following:

	March 31, 2007		December 31, 2006
	(in millions)
Coal and fuel oil	$	114	$	112
Spare parts, materials and supplies		46		46

Total	$	160	$	158

New Accounting Pronouncements

Accounting Principles Adopted

Statement of Financial Accounting Standards Interpretation No. 48—

In July 2006, the FASB issued FIN No. 48, which clarifies the accounting for uncertain tax positions. FIN No. 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. EME adopted FIN No. 48 effective January 1, 2007. Based on the current status of discussions with tax authorities related to open tax years under audit and other information currently available, implementation of FIN No. 48 resulted in a cumulative-effect adjustment that increased accumulated deficit by $1 million.

Statement of Financial Accounting Standards No. 155—

In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133 and SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated under paragraph 12 of SFAS No. 133 prior to the

adoption of this Statement. The adoption of this standard had no effect on EME's consolidated financial statements for the quarter ended March 31, 2007.

Accounting Principles Not Yet Adopted

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 will adopt SFAS No. 157 on January 1, 2008. EME is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial statements.

Statement of Financial Accounting Standards No. 159—

In February 2007, the FASB issued SFAS No. 159 which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. Upon adoption, the first remeasurement to fair value would be reported as a cumulative-effect adjustment to the opening balance of retained earnings. EME will adopt SFAS No. 159 on January 1, 2008. EME is currently evaluating the impact of adopting SFAS No. 159 on its consolidated financial statements.

Stock-Based Compensation

Edison International's stock, stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units have been granted to EME employees under Edison International's long-term incentive compensation programs. Edison International usually does not issue new common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of option exercises, performance shares and restricted stock units. Deferred stock units granted to management are settled in cash, not stock and represent a liability.

On April 26, 2007, Edison International's shareholders approved a new incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. No additional awards will be granted under Edison International's prior stock-based compensation plans on or after April 26, 2007, and all future issuances will be made under the new plan. The maximum number of shares of Edison International's common stock that may be issued or transferred pursuant to awards under the new incentive plan is 8.5 million shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued. For further discussion, see "Stock-Based Compensation" in Note 5.

Note 2. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consisted of the following:

	Unrealized Gains (Losses) on Cash Flow Hedges			Unrecognized Losses and Prior Service Costs, Net			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance at December 31, 2006	$	111		$	(10	)	$	101
Current period change		(154	)		—			(154	)

Balance at March 31, 2007	$	(43	)	$	(10	)	$	(53	)

Unrealized losses on cash flow hedges, net of tax, at March 31, 2007, include 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. The change from unrealized gains to unrealized losses during the first quarter of 2007 resulted from an increase in market prices for power.

As EME's hedged positions for continuing operations are realized, approximately $29 million, after tax, of the net unrealized losses on cash flow hedges at March 31, 2007 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will offset 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, 2009.

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 approximately $1 million and $11 million during the first quarters of 2007 and 2006, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in operating revenues in EME's consolidated income statements.

Note 3. Variable Interest Entities

U.S. Wind Force is a development stage enterprise formed to develop wind projects in West Virginia, Pennsylvania and Maryland. In December 2006, a subsidiary of EME entered into a loan agreement with U.S. Wind Force to fund the redemption of a membership interest held by another party, repayment of loans, distributions to equity holders and to fund future development of wind projects. In accordance with FIN 46(R), EME is the primary beneficiary and, accordingly, consolidated U.S. Wind Force at December 15, 2006. At March 31, 2007, the assets consolidated included $17 million of intangible assets, primarily related to project development rights, and are classified as part of other long-term assets in EME's consolidated balance sheet. As project development is completed, the project development rights will be considered part of property, plant and equipment and depreciated over the estimated useful lives of the respective projects.

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, 2007, 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 $310 million as of March 31, 2007.

Note 4. Discontinued Operations

Lakeland Project

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by the project's counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claims have been settled, EME received payments of £61 million (approximately $106 million) in the first quarter of 2006 and £4 million (approximately $8 million) in January 2007. The after-tax income attributable to the Lakeland project was $5 million and $73 million for the first quarters of 2007 and 2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

Summarized Financial Information for Discontinued Operations

	Three Months Ended March 31,
	2007		2006
	(in millions)
Income before income taxes and minority interest	$	6	$	111
Provision for income taxes		3		38
Income from operations of discontinued foreign subsidiaries		3		73

Note 5. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

EME previously disclosed in its financial statements for the year ended December 31, 2006 that it expected to contribute $14 million to its pension plans in 2007. As of March 31, 2007, $0.6 million in contributions has been made. EME continues to expect to contribute $14 million to its pension plans in 2007.

Components of pension expense are:

	Three Months Ended March 31,
	2007			2006
	(in millions)
Service cost	$	4		$	5
Interest cost		3			2
Expected return on plan assets		(2	)		(2	)

Total expense	$	5		$	5

Postretirement Benefits Other Than Pensions

EME previously disclosed in its financial statements for the year ended December 31, 2006 that it expected to contribute $1 million to its postretirement benefits other than pensions in 2007. As of March 31, 2007, $0.4 million in contributions has been made. EME continues to expect to contribute $1 million to its postretirement benefits other than pensions in 2007.

Components of postretirement benefits expense are:

	Three Months Ended March 31,
	2007		2006
	(in millions)
Service cost	$	1	$	1
Interest cost		1		1

Total expense	$	2	$	2

Stock-Based Compensation

Total stock-based compensation expense (reflected in the caption "Administrative and general" on the consolidated statements of income) was $1.5 million and $2.1 million for the three months ended March 31, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $0.5 million and $0.7 million for the three months ended March 31, 2007 and 2006, respectively.

Stock Options

A summary of the status of Edison International's stock options granted to EME employees is as follows:

			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding, December 31, 2006	3,014,145		$	25.52
Granted	360,107		$	47.41
Exercised	(573,630	)	$	20.10

Outstanding at March 31, 2007	2,800,622		$	29.44	7.23

Vested and expected to vest at March 31, 2007	2,690,217		$	29.07	7.18	$	47,556,320

Exercisable at March 31, 2007	1,508,551		$	22.89	6.28	$	35,990,255

Stock options granted in 2007 do not accrue dividend equivalents.

The amount of cash used by Edison International to settle stock options exercised by EME employees was $33 million and $13 million for the three months ended March 31, 2007 and 2006, respectively. Cash received by Edison International from options exercised by EME employees was $14 million and $6 million for the three months ended March 31, 2007 and 2006, respectively. The estimated tax benefit from options exercised was $6 million and $3 million for the three months ended March 31, 2007 and 2006, respectively.

Note 6. Income Taxes

MEHC's income tax provision from continuing operations was $73 million and $30 million for the quarters ended March 31, 2007 and 2006, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. EME recognized $5 million of production tax credits related to wind projects during each of the three months ended March 31, 2007 and 2006, and $2 million during each of the three months ended March 31, 2007 and 2006 related to estimated state income tax benefits allocated from Edison International.

The total amount of unrecognized tax benefits as of the date of adoption of FIN No. 48 was $84 million. The total amount of unrecognized tax benefits as of the date of adoption that, if recognized, would affect the effective tax rate was $83 million. The total amount of accrued interest and penalties was $41 million as of the date of adoption. The total amount of interest expense and penalties recognized in income tax expense was $5 million and $2 million for the three months ended March 31, 2007 and 2006, respectively.

MEHC and its subsidiaries remain subject to examination by the Internal Revenue Service, the California Franchise Tax Board, and other state authorities from 1994 to present. MEHC continues its efforts to resolve open tax issues with the Internal Revenue Service and state authorities. The timing for resolving these open tax positions is subject to uncertainty, but it is reasonably possible that some portion of these open tax positions could be resolved in the next twelve months.

Note 7. Commitments and Contingencies

Commitments

Capital Improvements

At March 31, 2007, EME's subsidiaries had firm commitments to spend approximately $133 million during the remainder of 2007 and $25 million in 2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. Also included are expenditures for dust collection and mitigation system and environmental improvements. 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, 2007, EME had entered into agreements with vendors securing 357 wind turbines (734 MW) with remaining commitments of $508 million in 2007 and $176 million in 2008. EME has the option to purchase an additional 83 wind turbines (199 MW) for delivery in 2009. In addition, EME had entered into an agreement for the purchase of five gas turbines and related equipment for an aggregate purchase price of approximately $145 million with remaining commitments of $53 million in 2007 and $3 million in 2008. In February 2007, EME was advised that it was an unsuccessful bidder in the request for offers conducted by SCE for the supply of generation capacity. EME plans to use the turbines which it had purchased and reserved for this bid for other generation supply opportunities. At March 31, 2007, EME had recorded turbine deposits of $210 million included in other long-term assets in EME's consolidated balance sheet.

Fuel Supply Contracts

Midwest Generation has entered into additional fuel purchase commitments during the first three months of 2007. These additional commitments are currently estimated to be $106 million in 2008, $74 million in 2009, and $77 million in 2010.

Coal Transportation Agreements

Midwest Generation 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. Midwest Generation commitments under this agreement are based on actual coal purchases from the PRB. Accordingly, contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first three months of 2007 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $110 million for 2008, $75 million for 2009, and $76 million for 2010.

Standby Letters of Credit

At March 31, 2007, standby letters of credit aggregated $51 million and were scheduled to expire as follows: $27 million in 2007 and $24 million in 2008.

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 that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, 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 will continue 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 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 has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). 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 176 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2007. Midwest Generation had recorded a $64 million liability at March 31, 2007 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, 2007, EME had recorded a liability of $97 million related to these matters.

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

triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

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. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project's power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of March 31, 2007, if payment were required, would be $92 million. EME has not recorded a liability related to these indemnities.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate

A subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement that expires in August 2007. EME believes there is sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Contingencies

FERC Notice Regarding Investigatory Proceeding against EMMT

At the end of 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 FERC's rules with respect to certain bidding practices employed by EMMT. EMMT is engaged in discussions with the staff to explore the possibility of resolution of this matter. Should a formal proceeding be commenced, EMMT will be entitled to contest any alleged violations before the FERC and an appropriate court. EME believes that EMMT has complied with the FERC's rules and intends to contest vigorously any allegation of violation. EME cannot predict at this time the outcome of this matter or estimate the possible liability should the outcome be adverse.

Midway-Sunset Cogeneration Company

San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset Cogeneration Company, which owns a 225 MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC involving claims for refunds from entities that sold power and related services into the California markets operated by the California Power Exchange and the California Independent System Operator (collectively the California Markets) at prices that were allegedly not just and reasonable, as required by the Federal Power Act.

Midway-Sunset is a party to these proceedings because Midway-Sunset was a seller in the California Markets during 2000 and 2001, both for its own account and on behalf of SCE and PG&E, the utilities to which the majority of Midway-Sunset's power was contracted for sale. As a seller into the California Markets, Midway-Sunset is potentially liable for refunds to purchasers in these markets.

The claims asserted against Midway-Sunset for refunds related to power sold into the California Markets, including power sold on behalf of SCE and PG&E, are estimated to be less than $70 million for all periods under consideration. Midway-Sunset has calculated its potential liability for refunds related to power sold into the California Markets on its own behalf (excluding power sold on behalf of SCE and PG&E) to be approximately $0.5 million for the period October 2, 2000 through June 20, 2001. Midway Sunset's potential liability for sales on its own behalf during the period May 1, 2000 through October 1, 2000 has not yet been calculated but is not expected to be material. These calculations were made in accordance with the methodology approved by the FERC, but it is possible that this methodology will be challenged.

Because Midway-Sunset did not retain any proceeds from power sold into the California Markets on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed those proceeds on to the utilities, EME believes that PG&E and SCE are obligated to reimburse Midway-Sunset for any refund liability that it incurs as a result of sales made into the California Markets on their behalf. Midway-Sunset intends vigorously to assert these positions. However, at this time EME cannot predict the outcome of this matter.

Challenges of Illinois Power Procurement Auction Results

EMMT participated successfully in the first Illinois power procurement auction, held in September 2006 according to rules approved by the Illinois Commerce Commission, and entered into two load requirements services contracts through which it is delivering electricity, capacity and specified ancillary, transmission and load following services necessary to serve a portion of Commonwealth Edison's residential and small commercial customer load, using contracted supply from Midwest Generation.

EME believes that EMMT's actions in regard to the Illinois auction were appropriate and lawful and intends to defend vigorously all of the matters described below. However, at this time EME cannot predict the outcome of these matters.

FERC Complaint—

On March 16, 2007, the Office of the Attorney General for the State of Illinois filed a complaint at the FERC alleging that the prices resulting from the Illinois auction resulted in unjust and unreasonable rates under the Federal Power Act and that participating wholesale sellers in the Illinois auction had colluded and manipulated the results of the auction. All successful participants in the Illinois auction, including EMMT, were named as respondents. The Office of the Attorney General asked the FERC to order refunds and to revoke the respondents' market-based rate pricing authority.

Class Action Lawsuits—

On April 4, 2007, EMMT was served with a complaint filed in the Circuit Court of Cook County, Illinois, by Saul R. Wexler, individually and on behalf of a class of similarly situated electric ratepayers in Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On

April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division.

On March 30, 2007, David Schafer, Tim Perry, Pat Martin and Michael Murray, individually and on behalf of a class of similarly situated electric ratepayers in Illinois, filed a complaint in the Circuit Court of Cook County, Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. EMMT has not been formally served in the case. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division.

Litigation

EME experiences other routine litigation in the normal course of its business. None of such pending routine litigation is expected to have a material adverse effect on EME's consolidated financial position or results of operations.

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. 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 expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by regulatory authorities.

With respect to EME's potential liabilities arising under 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 has accrued approximately $4 million at March 31, 2007 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 environmental activity 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 MEHC's financial statements included in its annual report on Form 10-K for the year ended December 31, 2006 for a more complete discussion of EME's environmental contingencies.

Note 8. Supplemental Statements of Cash Flows Information

		Three Months Ended March 31,
		2007		2006
		(in millions)
Cash paid
	Interest (net of amount capitalized)	$	66	$	88
	Income taxes		5		5
	Cash payments under plant operating leases		92		92
Details of assets acquired
	Fair value of assets acquired	$	23	$	29
	Liabilities assumed		—		—

During the first quarter of 2007, EME accrued $19 million in connection with the purchase price of wind projects acquired in March 2007 due upon completion of construction. During the first quarter of 2006, EME accrued $11 million in connection with the purchase price of the Wildorado wind project due upon completion of construction.

Note 9. Subsequent Event

On May 7, 2007, EME completed a private offering of $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notes due 2019 and $700 million of its 7.625% senior notes due 2027. EME will pay interest on the senior notes on May 15 and November 15 of each year, beginning on November 15, 2007.

EME used the proceeds of the offering of the senior notes, together with cash on hand, to purchase approximately $587 million of EME's outstanding 7.73% senior notes due 2009, to purchase $999.8 million of Midwest Generation's 8.75% second priority senior secured notes due 2034, to repay the outstanding amount ($327.8 million) of Midwest Generation's senior secured term loan facility, and to make a dividend payment of $899 million to MEHC which enabled MEHC to purchase approximately $795.7 million of its 13.5% senior secured notes due 2008. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees, and accrued interest. MEHC expects to record a total pre-tax loss of approximately $242 million (approximately $148 million after tax) on early extinguishment of debt during the second quarter of 2007.

In addition, on May 7, 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million.

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

This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect MEHC's current expectations and projections about future events based on MEHC'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 MEHC 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 MEHC 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 coal, natural gas, and fuel oil, and associated transportation;
•: 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 regulations 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 to 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;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: general political, economic and business conditions; and

•: weather conditions, natural disasters and other unforeseen events.

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 MEHC's Annual Report on Form 10-K for the year ended December 31, 2006. Readers are urged to read this entire quarterly report on Form 10-Q and carefully consider the risks, uncertainties and other factors that affect MEHC's business. Forward-looking statements speak only as of the date they are made, and MEHC is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by MEHC with the Securities and Exchange Commission.

This MD&A discusses material changes in the results of operations, financial condition and other developments of MEHC since December 31, 2006, and as compared to the first quarter ended March 31, 2006. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of MEHC's annual report on Form 10-K for the year ended December 31, 2006.

The presentation of information below pertaining to EME and its consolidated subsidiaries should not be understood to mean that EME has agreed to pay or become liable for any debt of MEHC. EME and MEHC are separate entities with separate obligations. MEHC is the sole obligor on the 13.50% senior secured notes due 2008, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes.

This MD&A is presented in four sections:

		Page
Management's Overview; Critical Accounting Policies		20
Results of Operations		24
Liquidity and Capital Resources		33
Market Risk Exposures		42

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING POLICIES

Management's Overview

Results of Operations

Net income is comprised of the following components:

	Three Months Ended March 31,
	2007			2006
	(in millions)
MEHC (parent company):
Loss from continuing operations	$	(17	)	$	(17	)
EME and its Consolidated Subsidiaries:
Income from continuing operations		153			75
Income from discontinued operations		3			73

Net Income	$	139		$	131

EME's improvement in income from continuing operations in the first quarter of 2007 was primarily attributable to an increase in wholesale energy margins driven by higher generation and energy prices at both the Illinois Plants and Homer City facilities. Generation comparisons at the Homer City facilities were impacted by a transformer outage that lasted during part of the first quarter of 2006. In addition, results at the Illinois Plants in 2007 were impacted by unrealized losses related to non-qualifying hedges under SFAS No. 133.

EME's income from discontinued operations during the first quarter of 2007 and 2006, net of tax, was primarily related to distributions authorized by the liquidators of the Lakeland power project. The activities of the Lakeland liquidator are near completion and substantially all the distributions from the Lakeland project have been made.

Financing Activities

On May 7, 2007, EME completed a private offering of $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notes due 2019 and $700 million of its 7.625% senior notes due 2027. The proceeds were used, together with cash on hand, to:

•: purchase substantially all of EME's outstanding 7.73% senior notes due 2009,
•: purchase substantially all of Midwest Generation's 8.75% second priority senior secured notes due 2034,
•: repay the outstanding balance of Midwest Generation's senior secured term loan facility ($327.8 million), and
•: make a dividend payment to MEHC which enabled MEHC to purchase substantially all of its 13.5% senior secured notes due 2008.

MEHC intends to redeem the remaining 13.5% senior secured notes due 2008 that were not tendered, subject to market conditions. MEHC expects to record a total pre-tax loss of approximately $242 million (approximately $148 million after tax) on early extinguishment of debt during the second quarter of 2007. See "Liquidity and Capital Resources—Financing Activities."

In addition to the above-mentioned debt refinancing, on May 7, 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million, and Midwest Generation plans to replace its existing $500 million senior secured working capital facility with a new senior secured working capital facility with a longer maturity date and less restrictive covenants. Midwest Generation intends to use its new secured working capital facility to provide credit support for its hedging activities, including through the option to extend power hedges by granting the counterparties a first lien to secure such hedges, and general working capital purposes.

The above-mentioned refinancing activities eliminate MEHC's reliance on dividends from EME and the restrictive covenants set forth in the indenture related to the 13.5% senior secured notes due 2008, improve MEHC and EME's overall liquidity, extend the maturity dates of indebtedness, reduce annual interest costs, improve operating flexibility, and improve EME's ability to capitalize on growth opportunities.

Business Development

EME has undertaken a number of key activities in 2007 with respect to wind projects, including the following:

•: In March 2007, EME acquired three wind projects in development in Utah and Wyoming totaling 212 MW. Two of the projects are in preliminary stages of development. The third project, referred to as the Mountain Wind I project, is 61 MW and expected to commence construction during the second quarter of 2007 with completion scheduled during the fourth quarter of 2007. The estimated capital cost of this project, excluding capitalized interest, is $104 million. The project plans to sell electricity to PacifiCorp under a 20-year power purchase agreement.
•: In March 2007, EME completed a transaction to acquire the remaining membership interests in two wind projects in development in Pennsylvania totaling 67 MW. Construction of these projects is expected to commence during the second quarter of 2007 with completion scheduled during the fourth quarter of 2007. The estimated capital cost, excluding capitalized interest, is $115 million. One of the projects, referred to as the Forward project, is 29 MW and plans to sell electricity to Constellation New Energy under a 10-year power purchase agreement. The other project, referred to as the Lookout project, is 38 MW and plans to sell electricity into PJM as a merchant wind generator.
•: In March 2007, EME purchased wind turbines and related services and warranties for an aggregate purchase price of approximately $253 million (a portion of which is currently denominated in Japanese yen and subject to exchange rate fluctuations) with deliveries scheduled for 2008. EME has also made a reservation fee payment of $8 million for additional turbines for 2009 delivery. Subject to issuance of a notice to proceed by June 30, 2007, the aggregate purchase price for these turbines and related services and warranties is approximately $255 million (a portion of which is also denominated in Japanese yen and subject to exchange rate fluctuations).
•: In April 2007, EME completed a transaction to acquire six projects in development in Texas and Oklahoma totaling 700 MW. These projects are in various stages of development with target completion dates of 2008 through 2010. Under the purchase and sale agreement, the purchase price is comprised of an initial payment and subsequent payments tied to milestones and adjustments based on EME's projected internal rate of return in individual projects. Completion of development of these projects is dependent on a number of items, including, among other things, obtaining power sales agreements, and in certain cases, permits and interconnection agreements.

PJM Reliability Pricing Model

In April 2007, PJM completed the first capacity auction under the PJM Reliability Pricing Model. EME participated in the auction for the period June 1, 2007 through May 31, 2008. After accounting for previous forward sales of capacity, EMMT sold net 3,013 MW of capacity from the Illinois Plants and net 886 MW of capacity from the Homer City facilities. The Illinois Plants and the Homer City facilities are located in the "Rest of Market" area which had a clearing price of $40.80 per MW-day.

ERP Initiative

Progress continued during the first quarter of 2007 on preparation for the installation of an enterprise resources planning (ERP) application from SAP. Financial, procurement and material management systems are scheduled for implementation during the third quarter of 2007 with the human resources systems scheduled for the second quarter of 2008 as part of the Edison International enterprise-wide project.

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 Estimates" of MEHC's annual report on Form 10-K for the year ended December 31, 2006.

RESULTS OF OPERATIONS

Introduction

This section discusses operating results for the first quarters of 2007 and 2006, and is organized under the following headings:

		Page
Results of Continuing Operations		24
Results of Discontinued Operations		31
New Accounting Pronouncements		32

Results of Continuing Operations

Overview

EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of power generated 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 for margining. 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.

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

The following section provides a summary of the operating results for the first quarters of 2007 and 2006 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Three Months Ended March 31,
		2007			2006
		(in millions)
Project Earnings (Losses) Before Income Taxes(1)
	*Consolidated operations*
	Illinois Plants	$	189		$	127
	Homer City		64			(2	)
	Energy Trading(2)		26			30
	San Juan Mesa		2			4
	Gain on sale of assets		—			4
	Storm Lake		2			—
	Other		2			—
	*Unconsolidated affiliates*
	Big 4 projects		18			23
	Sunrise		(2	)		(2	)
	Doga		4			(1	)
	Other		5			1

			310			184
	MEHC and EME corporate interest income		20			17
	MEHC and EME corporate interest expense		(83	)		(94	)
	MEHC and EME corporate administrative and general		(32	)		(24	)
	Other income (expense), net		(1	)		10

		$	214		$	93

(1): Project earnings are equal to income from continuing operations before income taxes, except for production tax credits. Accordingly, project earnings for the wind projects include $5 million of production tax credits for each of the first quarters of 2007 and 2006. 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 (losses) 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 under GAAP:

	Three Months Ended March 31,
	2007			2006
	(in millions)
Project earnings	$	214		$	93
Less: Production tax credits		(5	)		(5	)

Income from continuing operations before income taxes	$	209		$	88

(2): Income from energy trading represents the gains recognized from price changes related to contracts for electricity, fuel 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,
			2007			2006
			(in millions)
Operating Revenues			$	431		$	346
Operating Expenses
	Fuel			109			94
	Gain on sale of emission allowances(1)			(4	)		(6	)
	Plant operations			89			81
	Plant operating leases			19			19
	Depreciation and amortization			25			25
	Administrative and general			5			5

	Total operating expenses			243			218

Operating Income				188			128

Other Income (Expense)
	Interest income on note receivable from EME			28			28
	Interest expense and other			(27	)		(29	)

	Total other income (expense)			1			(1	)

Income Before Taxes			$	189		$	127

Statistics
	Generation (in GWh)
		Energy only contracts		6,698			7,244
		Load requirements services contracts(2)		1,932			—

		Total		8,630			7,244
	Aggregate plant performance
		Equivalent availability(3)		88.0%			86.8%
		Capacity factor(4)		71.2%			59.8%
		Load factor(5)		80.9%			68.8%
		Forced outage rate(6)		5.9%			2.8%
	Average realized price/MWh
		Energy only contracts(7)	$	49.06		$	45.21
		Load requirements services contracts(8)	$	61.89		$	—
	Capacity revenue only (in millions)		$	2		$	6
	Average fuel costs/MWh		$	12.63		$	12.92

(1): EME recorded $4 million and $6 million of intercompany profit during the first quarters of 2007 and 2006, respectively, on emission allowances sold by the Illinois Plants to the Homer City facilities in the fourth quarters of 2006 and 2005, respectively, but not used by the Homer City facilities until the first quarters of 2007 and 2006, respectively.
(2): Represents two load requirements services contracts, awarded as part of an Illinois auction, with Commonwealth Edison that commenced on January 1, 2007.
(3): 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.

(4): 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.
(5): The load factor is determined by dividing capacity factor by the equivalent availability factor.
(6): Midwest Generation refers to unplanned maintenance as a forced outage.
(7): The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized 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.
(8): 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 $62 million in the first quarter of 2007, compared to the first quarter of 2006. The 2007 increase was primarily due to higher energy revenues resulting from higher generation and average realized energy prices as compared to 2006. Partially offsetting these increases were higher maintenance costs and an increase in unrealized losses in 2007 related to hedge contracts described below.

Included in operating revenues were unrealized gains (losses) of $(22) million and $10 million for the first quarters of 2007 and 2006, respectively. Unrealized gains (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 2007, power prices increased, resulting in mark-to-market losses on economic hedges. The 2007 unrealized losses included $14 million of mark-to-market losses from economic hedges for periods subsequent to March 31, 2007, resulting from an increase in market prices during the first quarter of 2007. 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 2007 and 2006 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.

Homer City

			Three Months Ended March 31,
			2007			2006
			(in millions)
Operating Revenues			$	198		$	123
Operating Expenses
	Fuel(1)			72			61
	Gain on sale of emission allowances(2)			—			—
	Plant operations			34			35
	Plant operating leases			25			25
	Depreciation and amortization			3			4
	Administrative and general			1			1

	Total operating expenses			135			126

Operating Income (Loss)				63			(3	)

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

	Total other income			1			1

Income (Loss) Before Taxes			$	64		$	(2	)

Statistics
	Generation (in GWh)			3,293			2,521
	Aggregate plant performance
		Equivalent availability(3)		86.5%			71.8%
		Capacity factor(4)		80.8%			61.9%
		Load factor(5)		93.3%			86.3%
		Forced outage rate(6)		5.8%			23.4%
	Average realized energy price/MWh(7)		$	57.86		$	49.57
	Capacity revenue only (in millions)		$	6		$	3
	Average fuel costs/MWh		$	21.81		$	23.93

(1): Included in fuel costs were $6 million and $12 million during the quarters ended March 31, 2007 and 2006, 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 Homer City facilities sold excess NO_X emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $6 million in the first quarter of 2006. These sales reduced operating expenses. EME eliminated the intercompany transaction for emission allowances sold but not yet used by the Illinois Plants at March 31, 2006.
(3): 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.
(4): 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.
(5): The load factor is determined by dividing capacity factor by the equivalent availability factor.
(6): Homer City refers to unplanned maintenance as a forced outage.

(7): The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized SFAS No. 133 gains (losses) and other non-energy related revenue by (ii) total generation.

Earnings from Homer City increased $66 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 increase was primarily attributable to higher generation and average realized energy prices and lower prices of SO₂ emission allowances as compared to 2006. During the first quarter of 2006, an unplanned outage at Unit 3 contributed to lower generation and higher plant operating costs.

Included in operating revenues were unrealized gains (losses) from hedging activities of $1 million and $(5) million for the first quarter of 2007 and 2006, 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, 2007, unrealized losses of $11 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.

Homer City Unit 3 Outage—

On January 29, 2006, the main power transformer on Unit 3 of the Homer City facilities failed resulting in a suspension of operations at this unit. Homer City secured a replacement transformer and Unit 3 returned to service on May 5, 2006. The main transformer failure resulted in claims under Homer City's property and business interruption insurance policies. At March 31, 2007, Homer City had a $13 million receivable related to these claims. Resolution of the claims is subject to a number of uncertainties, including computations of the lost profit during the outage period.

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 ISOs. Earnings from energy trading activities were $26 million and $30 million for the first quarters ended March 31, 2007 and 2006, respectively.

San Juan Mesa

Earnings from the San Juan Mesa wind project decreased $2 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 decline in earnings was primarily due to a decrease in EME's ownership interest of the San Juan Mesa wind project to 75% from 100% in March 2006. During the first quarter of 2006, EME completed the sale of 25% of its ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceeds from the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million during the first quarter of 2006.

Storm Lake

Earnings from the Storm Lake wind project increased $2 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 increase in earnings was primarily due to higher generation.

Earnings from Unconsolidated Affiliates

Big 4 Projects

Earnings from the Big 4 projects decreased $5 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 decrease in earnings was primarily due to lower steam and energy prices and, for the Kern River project, lower volumes sold in 2007. The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding Corp. of $1 million and $2 million for the first quarters of 2007 and 2006, respectively.

Doga

Earnings from the Doga project increased $5 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 increase in earnings was primarily due to a planned outage that affected the first quarter of 2006 results.

Other

Earnings from other unconsolidated affiliates increased $4 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 increase in earnings was attributable to an increase in earnings from the Westside projects primarily due to lower maintenance expenses, partially offset by lower steam and energy prices.

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.

MEHC and EME Corporate Interest Expense

	Three Months Ended March 31,
	2007		2006
	(in millions)
MEHC (excluding EME) interest expense to third parties	$	28	$	28
EME's interest expense to third parties		26		38
EME's interest expense to Midwest Generation(1)		29		28

Total corporate interest expense	$	83	$	94

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

EME Interest Expense to Third Parties

EME's interest expense to third parties decreased $12 million for the first quarter of 2007, compared to the first quarter of 2006. The decrease was primarily attributable to lower interest rates resulting from EME's refinancing in June 2006 and an increase of $6 million in capitalized interest in 2007 from wind projects under construction.

MEHC and EME Corporate Administrative and General Expenses

Administrative and general expenses increased $8 million for the first quarter of 2007, compared to the first quarter of 2006. The increase was primarily due to higher development costs incurred in 2007 mostly related to wind projects. See "Management's Overview; Critical Accounting Policies—Management's Overview."

Other Income (Expense), Net

Other income (expense), net decreased $11 million for the first quarter of 2007, compared to the first quarter of 2006. The 2007 decrease was primarily attributable to an $8 million gain related to receipt of shares from Mirant Corporation from settlement of a claim recorded during the first quarter of 2006.

Income Taxes

MEHC's income tax provision from continuing operations was $73 million and $30 million during the first quarters of 2007 and 2006, 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." EME recognized $5 million of production tax credits related to wind projects during each of the three months ended March 31, 2007 and 2006, and $2 million during each of the three months ended March 31, 2007 and 2006 related to estimated state income tax benefits allocated from Edison International.

Results of Discontinued Operations

Income from discontinued operations, net of tax, was $3 million and $73 million for the first quarters of 2007 and 2006, respectively, largely attributable to distributions received from the Lakeland project, discussed below.

Lakeland Project

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of default by the project's counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claims have been settled, EME received payments of £61 million (approximately $106 million) in the first quarter of 2006 and £4 million (approximately $8 million) in January 2007. The after-tax income attributable to the Lakeland project was $5 million and $73 million for the first quarters of 2007 and 2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting EME, see "Mission Energy Holding Company 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
Financing Activities		33
EME's Liquidity		34
Capital Expenditures		34
MEHC's Historical Consolidated Cash Flow		35
Credit Ratings		36
Margin, Collateral Deposits and Other Credit Support for Energy Contracts		37
EME's Liquidity as a Holding Company		37
Dividend Restrictions in Major Financings		38
Contractual Obligations and Contingencies		39
Off-Balance Sheet Transactions		41
Environmental Matters and Regulations		41

For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with MEHC's annual report on Form 10-K for the year ended December 31, 2006.

Financing Activities

EME's Liquidity

At March 31, 2007, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.7 billion, and EME had a total of $952 million of available borrowing capacity under its $500 million corporate credit facility and a $500 million working capital facility at Midwest Generation. EME's consolidated debt at March 31, 2007 was $3.1 billion. In addition, EME's subsidiaries had $4.2 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 28 years.

Capital Expenditures

At March 31, 2007, the three-year estimated capital expenditures by EME's subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:

		April through December 2007		2008		2009
		(in millions)
Illinois Plants
	Plant capital expenditures	$	35	$	40	$	50
	Environmental expenditures		21		39		66
Homer City Facilities
	Plant capital expenditures		14		26		20
	Environmental expenditures		6		9		15
Wind and Thermal Projects
	Projects under construction		98		—		—
	Turbine commitments		561		179		—
	Other expenditures		54		—		—
Corporate capital expenditures			12		7		7

Total		$	801	$	300	$	158

Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls and dust collection/mitigation systems, a spare main power transformer, railroad interconnection and an expansion of a coal cleaning plant refuse site. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control and SCR performance improvements 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 finance these expenditures with financings, cash on hand or cash generated from operations. See further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview—Business Strategy," "Liquidity and Capital Resources—Environmental Matters and Regulations—Air Quality Regulation—Clean Air Act—Illinois," and "Liquidity and Capital Resources—Environmental Matters and Regulations—Air Quality Regulation—Mercury Regulation" of MEHC's annual report on Form 10-K for the year ended December 31, 2006.

Expenditures for New Projects

EME expects to make substantial investments in new projects during the next three years. In addition to the capital expenditures to purchase turbines set forth in the above table, EME has entered into a letter of intent to purchase 300 turbines (totaling 630 MW) for delivery in 2008 and 2009. The purchase of these turbines is subject to completion of a definitive turbine purchase agreement. EME has also made a reservation fee payment of $8 million for 83 additional turbines (totaling 199 MW) for 2009 delivery, subject to issuance of a notice to proceed by June 30, 2007. Estimated capital expenditures under these agreements would be approximately $940 million, not including the cost to complete construction, if the maximum number of turbines were purchased.

As of April 30, 2007, EME has a development pipeline of potential wind projects with an installed capacity of approximately 2,700 MW (the development pipeline represents potential projects which EME either owns the project rights or has exclusive negotiation rights). Completion of these projects is dependent upon a number of items which may include, depending on the project's status, completion of a power sales agreement, permits, an interconnection agreement or other agreements necessary to start construction. Additional projects may from time to time be added to the development pipeline, and there is no assurance that the projects included in the development pipeline currently or added in the future will lead to the successful completion of a wind project.

MEHC's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Cash provided by operating activities from continuing operations decreased $175 million in the first quarter of 2007, compared to the first quarter of 2006. The 2007 decrease was primarily attributable to an increase of $146 million in required margin and collateral deposits in 2007 for EME's hedging and trading activities, compared to a decrease of $109 million in 2006. This change resulted from an increase in forward market prices in 2007 from 2006. Partially offsetting this decrease was higher pre-tax income from continuing operations in 2007 compared to 2006.

Cash provided by operating activities from discontinued operations decreased $66 million in the first quarter of 2007, compared to the first quarter of 2006. The 2007 decrease reflects higher distributions received in 2006 compared to 2007 from the Lakeland power project. See "Results of Operations—Results of Discontinued Operations—Lakeland Project" for more information regarding these distributions.

Consolidated Cash Flows from Financing Activities

Cash used in financing activities from continuing operations decreased $179 million in the first quarter of 2007, compared to the first quarter of 2006. The 2007 decrease was primarily attributable to a repayment of $170 million on Midwest Generation's $500 million working capital facility during the first quarter of 2006.

Consolidated Cash Flows from Investing Activities

Cash used in investing activities from continuing operations increased $9 million in the first quarter of 2007, compared to the first quarter of 2006. The 2007 increase was primarily due to higher capital expenditures and turbine deposits in 2007, compared to 2006, largely related to the wind projects. Mostly offsetting these increases was net maturities and sales of marketable securities of $83 million in the first quarter of 2007, compared to net purchases of marketable securities of

$45 million in the first quarter of 2006. In addition, EME paid $18 million towards the purchase price of the Wildorado wind project, and received proceeds of $43 million from the sale of 25% of its ownership interest in the San Juan Mesa project during the first quarter of 2006.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT, at March 31, 2007, are as follows:

		Moody's Rating	S&P Rating	Fitch Rating
EME		B1	BB-	BB-
Midwest Generation:
	First priority senior secured rating	Baa3	BB	BBB-
	Second priority senior secured rating	Ba2	B+	BB+
EMMT		Not Rated	BB-	Not Rated

Subsequent to March 31, 2007, the rating agencies affirmed the above-mentioned EME ratings in connection with the financing activities discussed above under "Financing Activities" and affirmed the rating for the Midwest Generation first priority secured revolving credit facility, except that S&P increased its rating to BB+ from BB.

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. MEHC 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 or EME 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. Because the credit ratings of EMMT and EME are below investment grade, EME has historically 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, 2007, EMMT had deposited $157 million in cash with brokers in margin accounts in support of futures contracts and had deposited $62 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $2 million in support of commodity contracts at March 31, 2007.

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2007, 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, 2007 could increase by approximately $410 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, 2007, Midwest Generation had available $495 million of borrowing capacity under this credit facility. As of March 31, 2007, Midwest Generation had $65 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and a $500 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, 2007, EME had corporate cash and cash equivalents and short-term investments of $1.3 billion 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."

Historical Distributions Received By EME

The following table is presented as an aid in understanding the cash flow of EME's continuing operations and its various subsidiary holding companies which depend on distributions from subsidiaries and affiliates to fund general and administrative costs and debt service costs of recourse debt.

		Three Months Ended March 31,
		2007		2006
		(in millions)
Distributions from Consolidated Operating Projects:
	Edison Mission Midwest Holdings (Illinois Plants)(1)	$	117	$	185
	EME Homer City (Homer City facilities)		35		—
	Holding companies of other consolidated operating projects		1		—
Distributions from Unconsolidated Operating Projects:
	Edison Mission Energy Funding Corp. (Big 4 Projects)(2)		28		40
	Holding company for Doga project		13		—
	Holding companies for Westside projects		6		2
	Holding companies of other unconsolidated operating projects		1		—

Total Distributions		$	201	$	227

(1): Subsequent to March 31, 2007, Edison Mission Midwest Holdings made an additional distribution of $178 million.
(2): The Big 4 projects consist of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy Funding Corp.

Intercompany Tax-Allocation Agreement

MEHC and EME are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of MEHC and EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of MEHC and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC, EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC and EME receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC's or EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, MEHC and EME are obligated during periods they generate taxable income to make payments under the tax-allocation agreements.

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 for the twelve months ended March 31, 2007:

Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation (Illinois Plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	5.98 to 1
Midwest Generation (Illinois Plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	1.88 to 1
EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	3.20 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 MEHC's annual report on Form 10-K for the year ended December 31, 2006.

Contractual Obligations and Contingencies

Contractual Obligations

Capital Improvements

Turbine Commitments

Fuel Supply Contracts

Coal Transportation Agreements

Contingencies

Challenges of Illinois Power Procurement Auction Results

FERC Complaint—

Class Action Lawsuits—

The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division.

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 MEHC's annual report on Form 10-K for the year ended December 31, 2006. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in MEHC'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 MEHC's annual report on Form 10-K for the year ended December 31, 2006 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 MEHC's annual report, except as follows:

Climate Change

On April 2, 2007, the United States Supreme Court issued an opinion in Massachusetts et. al. v. Environmental Protection Agency, et. al., ruling that US EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act and that it has a duty to (i) determine whether greenhouse gas emissions of new motor vehicles contribute to climate change or (ii) offer a reasoned explanation for its failure to make such a determination when presented with a request for a rulemaking on the issue by the state claimants. The Court ruled that US EPA's failure to make the necessary determination or offer a reasonable explanation for its refusal to do so was impermissible. While this case hinged on a provision of the Clean Air Act related to emissions of motor vehicles, a parallel provision of the Clean Air Act applies to stationary sources such as electric generators. EME believes that the Court's Massachusetts decision may spur additional congressional action to require reductions of greenhouse gas emissions by all material sources, including electric generators.

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		42
Accounting for Energy Contracts		49
Fair Value of Financial Instruments		50
Credit Risk		51
Interest Rate Risk		53
Foreign Exchange Rate Risk		53
Regulatory Matters		54

For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with MEHC's annual report on Form 10-K for the year ended December 31, 2006.

Commodity Price Risk

Overview

EME's revenues and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market areas where EME's merchant plants are located. Among the factors that influence the price of energy, capacity and ancillary services in these markets are:

•: prevailing market prices for coal, natural gas and fuel oil, and associated transportation;
•: 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/or 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;
•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;
•: the cost and availability of emission credits or allowances;
•: the availability, reliability and operation of competing power generation facilities, including nuclear generating plants, where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;

•: weather conditions prevailing in surrounding areas from time to time; and
•: changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

A discussion of commodity price risk for the Illinois Plants and the Homer City facilities is set forth below.

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 "value at risk" to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities, and its trading positions. The use of value at risk 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 over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach 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, and
•: 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.

The extent to which EME enters into contracts to hedge its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether sales 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 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 MISO. These trading hubs have been the most liquid locations for hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. 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 2007 and 2006.

	24-Hour Northern Illinois Hub Historical Energy Prices(1)
	2007		2006
January	$	35.75	$	42.27
February		56.64		42.66
March		42.04		42.50

Quarterly Average	$	44.81	$	42.48

(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, 2007:

2007		24-Hour Northern Illinois Hub Forward Energy Prices(1)
	April	$	41.80
	May		42.14
	June		43.97
	July		57.28
	August		59.10
	September		42.10
	October		41.98
	November		43.47
	December		49.32
2008 Calendar "strip"(2)		$	47.92

(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, 2007:

		2007		2008		2009
Energy Only Contracts(1)
	MWh		11,968,150		10,837,600		2,048,000
	Average price/MWh(2)	$	48.32	$	61.37	$	60.00
Load Requirements Services Contracts
	Estimated MWh(3)		6,449,440		6,209,608		1,805,816
	Average price/MWh(4)	$	64.29	$	64.01	$	63.65
Total estimated MWh			18,417,590		17,047,208		3,853,816

(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, 2007 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 2007 and 2006:

	Historical Energy Prices(1) 24-Hour PJM
	Homer City				West Hub
	2007		2006		2007		2006
January	$	40.30	$	48.67	$	44.63	$	54.57
February		64.27		49.54		73.93		56.39
March		55.00		53.26		61.02		58.30

Quarterly Average	$	53.19	$	50.49	$	59.86	$	56.42

(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-ISO 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, 2007:

2007		24-Hour PJM West Hub Forward Energy Prices(1)
	April	$	52.35
	May		53.03
	June		57.33
	July		76.64
	August		79.32
	September		55.00
	October		54.72
	November		56.49
	December		61.30
2008 Calendar "strip"(2)		$	63.37

(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 Homer City's hedge position at March 31, 2007:

		2007			2008			2009
MWh			5,714,350			7,232,000			2,048,000
Average price/MWh(1)		$	64.29		$	60.85		$	71.05

(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, 2007 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

The average price/MWh for 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.

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. 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, 2007 and 2006, 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 11%. The monthly average difference during the 12 months ended March 31, 2007 ranged from 3% to 23%. 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.

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 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 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 2010. The following table summarizes the amount of coal under contract at March 31, 2007 for the remainder of 2007 and the following three years.

	Amount of Coal Under Contract in Millions of Tons(1)
	April through December 2007	2008	2009	2010
Illinois Plants	12.5	14.6	11.7	11.7
Homer City facilities	3.9	2.1	0.8	—

(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 NAPP coal, which are related to the price of coal purchased for the Homer City facilities, increased during the first quarter of 2007 from 2006 year-end prices. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to $44.50 per ton at March 23, 2007 from $43.00 per ton at December 15, 2006, as reported by the Energy Information Administration. The 2007 increase in the NAPP coal price was in line with normal market price volatility. Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content), which is purchased for the Illinois Plants decreased during the first quarter of 2007 from 2006 year-end prices due to continuing high stockpiles and oversupply of the market. The

price of PRB coal decreased from $9.90 per ton at December 15, 2006 to $8.55 per ton at March 23, 2007, as reported by the Energy Information Administration.

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 $478 per ton during the first quarter of 2007 from $664 per ton during 2006. The price of SO₂ allowances, determined by obtaining broker quotes and information from other public sources, was $435 per ton as of March 31, 2007.

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 MEHC's annual report on Form 10-K for the year ended December 31, 2006.

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, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Management's Overview; Critical Accounting Estimates—Critical Accounting Estimates—Derivative Financial Instruments and Hedging Activities" of MEHC's annual report on Form 10-K for the year ended December 31, 2006.

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 2007 and 2006:

			Three Months Ended March 31,
			2007			2006
			(in millions)
	Non-qualifying hedges
		Illinois Plants	$	(22	)	$	8
		Homer City		(1	)		(2	)
	Ineffective portion of cash flow hedges
		Illinois Plants		—			2
		Homer City		2			(3	)

Total unrealized gains (losses)			$	(21	)	$	5

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 (in millions):

		March 31, 2007			December 31, 2006
Commodity price:
	Electricity	$	(94	)	$	184

In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. 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, 2007 as compared to December 31, 2006 is attributable to an increase in the average market prices for power as compared to contracted prices at March 31, 2007, 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, 2007 (in millions):

		Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years			Maturity >5 years
Prices actively quoted		$	(94	)	$	(71	)	$	(23	)	$	—		$	—

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of March 31, 2007 and December 31, 2006, are set forth below (in millions):

	March 31, 2007				December 31, 2006
	Assets		Liabilities		Assets		Liabilities
Electricity	$	102	$	6	$	313	$	207
Other		—		—		5		—

Total	$	102	$	6	$	318	$	207

The change in the fair value of trading contracts for the quarter ended March 31, 2007, was as follows (in millions):

Fair value of trading contracts at January 1, 2007	$	111
Net gains from energy trading activities		28
Amount realized from energy trading activities		(32	)
Other changes in fair value		(11	)

Fair value of trading contracts at March 31, 2007	$	96

Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of March 31, 2007) (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	12	$	11	$	1	$	—	$	—
Prices based on models and other valuation methods		84		4		13		19		48

Total	$	96	$	15	$	14	$	19	$	48

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, 2007, 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, 2007
	(in millions)
A or higher	$	12
A-		28
BBB+		55
BBB		38
BBB-		1
Below investment grade		—

Total	$	134

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, 2007. Moody's rates PJM's senior unsecured debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At March 31, 2007, EME's account receivable due from PJM was $89 million. For the three months ended March 31, 2007, a second customer accounted for 14% of EME's consolidated operating revenues.

Beginning in January 2007, 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 18% of EME's consolidated operating revenues during the three months ended March 31, 2007. Commonwealth Edison's senior unsecured debt rating was downgraded below investment grade by S&P in October 2006 and by Moody's in March 2007. As a result, Commonwealth Edison is required to pay EME twice a month for sales under these contracts. At March 31, 2007, EME's account receivable due from Commonwealth Edison was $36 million. Commonwealth Edison has stated that it would face possible bankruptcy if an electric rate freeze, which expired January 1, 2007, was re-introduced through legislation which is currently pending in the Illinois General Assembly. In addition, the Illinois Attorney General and other parties have appeals pending before the Illinois Supreme Court pertaining to the Illinois Commerce Commission orders which authorized Commonwealth Edison and Ameren to procure power through a reverse auction process. EME is unable to predict the outcome of the appeals or whether legislation or other policy changes affecting utility rates or procurement practices will be enacted, and, if so, what effect these developments may have on Commonwealth Edison's performance under the load requirements services contracts.

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 MEHC's consolidated long-term obligations (including current portion) was $4.3 billion at March 31, 2007, compared to the carrying value of $3.9 billion. The fair market value of MEHC's parent only total long-term obligations was $0.9 million at March 31, 2007, compared to the carrying value of $0.8 million.

Foreign Exchange Rate Risk

EME is exposed to foreign currency risk associated with the purchase of certain turbines in which a portion of the purchase price is denominated in Japanese yen. Under the terms of the related agreement, EME has the option of fixing the foreign currency rate at the time of a notice to proceed which is required by June 30, 2007. See "Liquidity and Capital Resources—Contractual Obligations and Contingencies—Contractual Obligations—Turbine Commitments."

Regulatory Matters

For a discussion of EME's regulatory matters, refer to "Item 1. Business—Regulatory Matters" of MEHC's annual report on Form 10-K for the year ended December 31, 2006. There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing of MEHC's annual report on Form 10-K for the year ended December 31, 2006, except as follows:

Two legal actions have been instituted against successful participants in the 2006 Illinois power procurement auction, including EMMT. For further discussion, see "Liquidity and Capital Resources—Contractual Obligations and Contingencies—Contingencies—Challenges of Illinois Power Procurement Auction Results."

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 MEHC's annual report on Form 10-K for the year ended December 31, 2006. Refer to "Market Risk Exposures" in Item 2 of this quarterly report on Form 10-Q for an update to that disclosure.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

MEHC's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of MEHC'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, MEHC's disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

There were no changes in MEHC's internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, MEHC'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 MEHC's annual report on Form 10-K for the year ended December 31, 2006. There have been no significant developments with respect to legal proceedings specifically affecting EME since the filing of MEHC's annual report on Form 10-K for the year ended December 31, 2006.

ITEM 1A. RISK FACTORS

For a discussion of the risks, uncertainties, and other important factors which could materially affect MEHC's business, financial condition, or future results, refer to "Item 1A. Risk Factors" of MEHC's annual report on Form 10-K for the year ended December 31, 2006. The risks described in MEHC's annual report on Form 10-K are not the only risks facing MEHC. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect MEHC's business, financial condition or future results.

ITEM 6. EXHIBITS

Exhibit No.		Description
10.1	†	Supply Agreement, dated as of March 28, 2007, between Edison Mission Energy and Mitsubishi Power Systems Americas, Inc., incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2007.
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.

†: Confidential treatment requested.

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.

		MISSION ENERGY HOLDING COMPANY
		By:	/s/ W. JAMES SCILACCI W. James Scilacci Senior Vice President and Chief Financial Officer
		Date:	May 9, 2007

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TABLE OF CONTENTS
GLOSSARY
PART I—FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In millions, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2007 (Unaudited)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PART II—OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS
ITEM 1A. RISK FACTORS
ITEM 6. EXHIBITS
SIGNATURES

MISSION ENERGY HOLDING CO 10-Q