10-Q

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark one)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2006
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                               to

Commission file number 333-68630

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

Delaware	95-4031807
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
18101 Von Karman Avenue, Suite 1700 Irvine, California	92612
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (949) 752-5588

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

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer 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 8, 2006: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

		Page
PART I – Financial Information
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4.	Controls and Procedures	52
PART II – Other Information
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	54
	Signatures	55

PART I – FINANCIAL INFORMATION
ITEM 1.    FINANCIAL STATEMENTS

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

			Three Months Ended March 31,
			2006			2005
Operating Revenues
	Electric revenues		$	483		$	494
	Net gains from price risk management and energy trading			17			12
	Operation and maintenance services			5			5
	Other revenues			5			—
		Total operating revenues		510			511
Operating Expenses
	Fuel			149			165
	Plant operations			117			106
	Plant operating leases			44			44
	Operation and maintenance services			5			5
	Depreciation and amortization			32			31
	Administrative and general			31			36
		Total operating expenses		378			387
	Operating income			132			124
Other Income (Expense)
	Equity in income from unconsolidated affiliates			24			36
	Interest and other income			28			9
	Gain on sale of assets			4			—
	Loss on early extinguishment of debt			—			(4	)
	Interest expense			(71	)		(76	)
		Total other income (expense)		(15	)		(35	)
	Income from continuing operations before income taxes			117			89
	Provision for income taxes			44			34
Income From Continuing Operations				73			55
	Income from operations of discontinued subsidiaries, net of tax (Note 6)			73			7
Net Income			$	146		$	62

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

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

			Three Months Ended March 31,
			2006			2005
Net Income			$	146		$	62
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 $128 and $(55) for the three months ended March 31, 2006 and 2005, respectively		185			(70	)
		Reclassification adjustments included in net income, net of income tax expense of $20 and $3 for the three months ended March 31, 2006 and 2005, respectively		(30	)		(5	)
Other comprehensive income (loss)				155			(75	)
Comprehensive Income (Loss)			$	301		$	(13	)

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

2

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

			March 31, 2006		December 31, 2005
Assets
Current Assets
	Cash and cash equivalents		$	1,228	$	1,147
	Short-term investments			228		183
	Accounts receivable—trade			181		335
	Accounts receivable—affiliates			9		8
	Inventory			161		120
	Assets under price risk management and energy trading			113		78
	Margin and collateral deposits			459		561
	Deferred taxes			63		155
	Prepaid expenses and other			88		68
		Total current assets		2,530		2,655
Investments in Unconsolidated Affiliates				372		391
Property, Plant and Equipment				3,737		3,653
	Less accumulated depreciation and amortization			830		798
		Net property, plant and equipment		2,907		2,855
Other Assets
	Deferred financing costs			40		42
	Long-term assets under price risk management and energy trading			106		90
	Restricted cash			100		105
	Rent payments in excess of levelized rent expense under plant operating leases			443		395
	Long-term margin and collateral deposits			130		137
	Other long-term assets			83		118
		Total other assets		902		887
Total Assets			$	6,711	$	6,788

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

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

			March 31, 2006			December 31, 2005
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	64		$	32
	Accounts payable			55			62
	Accrued liabilities			175			206
	Liabilities under price risk management and energy trading			230			418
	Interest payable			87			51
	Current maturities of long-term obligations			48			50
		Total current liabilities		659			819
Long-term obligations net of current maturities				3,110			3,303
Deferred taxes and tax credits				198			171
Long-term liabilities under price risk management and energy trading				45			83
Other long-term liabilities				539			544
Total Liabilities				4,551			4,920
Minority Interest				39			24
Commitments and Contingencies (Note 8)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of March 31, 2006 and December 31, 2005			64			64
	Additional paid-in capital			2,185			2,209
	Retained deficit			(72	)		(218	)
	Accumulated other comprehensive loss			(56	)		(211	)
Total Shareholder's Equity				2,121			1,844
Total Liabilities and Shareholder's Equity			$	6,711		$	6,788

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

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

			Three Months Ended March 31,
			2006			2005 Revised(1)
Cash Flows From Operating Activities
	Net income		$	146		$	62
	Less: Income from discontinued operations			(73	)		(7	)
	Income from continuing operations, net		$	73		$	55
	Adjustments to reconcile income to net cash provided by (used in) operating activities:
		Equity in income from unconsolidated affiliates		(24	)		(36	)
		Distributions from unconsolidated affiliates		42			36
		Depreciation and amortization		35			31
		Deferred taxes and tax credits		14			32
		Gain on sale of assets		(4	)		—
		Loss on early extinguishment of debt		—			4
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		109			(76	)
		Decrease (increase) in accounts receivable		152			(53	)
		Increase in inventory		(41	)		(7	)
		Decrease (increase) in prepaid expenses and other		(19	)		9
		Increase in rent payments in excess of levelized rent expense		(48	)		(5	)
		Increase (decrease) in accounts payable		26			(25	)
		Decrease in accrued liabilities		(44	)		(62	)
		Increase in interest payable		36			34
		Increase (decrease) in net assets under risk management		(15	)		5
		Other operating—assets		—			2
		Other operating—liabilities		3			9
				295			(47	)
	Operating cash flow from discontinued operations			69			(3	)
		Net cash provided by (used in) operating activities		364			(50	)
Cash Flows From Financing Activities
	Payments on long-term debt agreements			(192	)		(201	)
	Cash dividends to parent			(12	)		(360	)
	Payments for price appreciation on stock-based awards			(7	)		(4	)
	Excess tax benefits related to stock option exercises			3			—
		Net cash used in financing activities		(208	)		(565	)
Cash Flows From Investing Activities
	Capital expenditures			(59	)		(14	)
	Proceeds from return of capital and loan repayments			—			5
	Purchase of interest of acquired companies			(18	)		—
	Proceeds from sale of interest in projects			43			—
	Proceeds from sale of discontinued operations			—			124
	Purchase of short-term investments			(95	)		—
	Maturities and sales of short-term investments			50			140
	Decrease in restricted cash			9			52
	Turbine deposits			(9	)		—
	Proceeds from other assets			4			3
				(75	)		310
	Investing cash flow from discontinued operations			—			5
		Net cash provided by (used in) investing activities		(75	)		315
Net increase (decrease) in cash and cash equivalents				81			(300	)
Cash and cash equivalents at beginning of period				1,147			2,272
Cash and cash equivalents at end of period				1,228			1,972
Cash and cash equivalents classified as part of discontinued operations				—			(2	)
Cash and cash equivalents of continuing operations			$	1,228		$	1,970

(1)

See Note 1—Revisions for further explanation.

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

5

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2006
(Unaudited)

Note 1. General

        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 for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three months ended March 31, 2006 are not necessarily indicative of the operating results for the full year.

        Edison Mission Energy's (EME's) significant accounting policies are described in Note 2 to its Consolidated Financial Statements as of December 31, 2005 and 2004, included in EME's annual report on Form 10-K for the year ended December 31, 2005. EME follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for stock-based compensation (explained below). This quarterly report should be read in connection with such financial statements. Terms used but not defined in this report are defined in EME's annual report on Form 10-K for the year ended December 31, 2005.

Stock-Based Compensation

        EME's stock-based compensation plans primarily include the issuance of Edison International stock options and performance shares. Edison International usually does not issue new common stock for equity awards earned. 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 performance shares earned. The amount of cash used to settle stock options exercised was $13 million and $6 million for the quarters ended March 31, 2006 and 2005, respectively. The amount of cash used to settle performance shares classified as equity awards was $11 million and $4 million for the quarters ended March 31, 2006 and 2005, respectively. Edison International has approximately 13.8 million shares remaining for future issuance under its stock-based compensation plans, which are described more fully in Note 10—Stock Compensation Plans.

        Prior to January 1, 2006, EME accounted for these plans using the intrinsic value method. Upon grant, no stock-based compensation cost for stock options was reflected in net income, as the grant date was the measurement date, and all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Previously, stock-based compensation cost for performance shares was remeasured at each reporting period and related compensation expense was adjusted. As discussed in Note 11—New Accounting Pronouncements, effective January 1, 2006, EME implemented a new accounting standard that requires companies to use the fair value accounting method for stock-based compensation resulting in the recognition of expense for all stock-based compensation awards. EME recognizes stock-based compensation expense on a straight-line basis over the vesting period. EME recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, EME recognized stock-based compensation expense over the explicit vesting period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal vesting period for the award, stock-based compensation will be recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement. If EME recognized stock-based compensation expense for awards granted prior to January 1, 2006, over a period to the

6

date the participant first became eligible for retirement, stock-based compensation expense would have increased by $0.1 million and $0 million for the quarters ended March 31, 2006 and 2005, respectively.

        Total stock-based compensation expense (reflected in the caption "Administrative and general" on the consolidated statements of income) was $2 million and $6 million for the three months ended March 31, 2006 and 2005, respectively. The income tax benefit recognized in the income statement was $1 million and $2 million for the three months ended March 31, 2006 and 2005, respectively.

        The following table illustrates the effect on net income if EME had used the fair value accounting method for the quarter ended March 31, 2005.

	Three Months Ended March 31, 2005
	(in millions)
Net income, as reported	$	62
Add: stock-based compensation expense using the intrinsic value accounting method – net of tax		4
Less: stock-based compensation expense using the fair value accounting method – net of tax		(3	)
Pro forma net income	$	63

Reclassifications

        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.

Revisions

        EME revised its Consolidated Statements of Cash Flows for the three months ended March 31, 2005 to separately disclose the operating and investing portion of the cash flows attributable to its discontinued operations consistent with its Consolidated Statements of Cash Flow for the year ended December 31, 2005 included in EME's annual report on Form 10-K for the year ended December 31, 2005. EME had previously reported these amounts on a combined basis in its quarterly report on Form 10-Q for the quarter ended March 31, 2005.

Note 2. Inventory

        Inventory is stated at the lower of weighted average cost or market. Inventory at March 31, 2006 and December 31, 2005 consisted of the following:

	March 31, 2006		December 31, 2005
	(in millions)
Coal and fuel oil	$	117	$	77
Spare parts, materials and supplies		44		43
Total	$	161	$	120

7

        Inventory increased at March 31, 2006 from December 31, 2005 primarily due to lower generation at the Homer City facilities as a result of an unplanned outage and to planned inventory management for summer peak periods at the Illinois Plants.

Note 3. Short-term Investments

Held-to-Maturity Securities

        At March 31, 2006 and December 31, 2005, EME had marketable debt securities that were classified as held-to-maturity and carried at amortized cost plus accrued interest which approximated their fair value.

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

	March 31, 2006		December 31, 2005
	(in millions)
Commercial paper	$	171	$	99
Certificates of deposit		43		34
Treasury bills		10		—
Time deposits		—		50
Corporate bonds		4		—
Total	$	228	$	183

Note 4. Accumulated Other Comprehensive Income (Loss)

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

	Unrealized Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance at December 31, 2005	$	(210	)	$	(1	)	$	(211	)
Current period change		155			—			155
Balance at March 31, 2006	$	(55	)	$	(1	)	$	(56	)

        Unrealized losses on cash flow hedges, net of tax, at March 31, 2006, include unrealized losses on commodity hedges primarily related to Midwest Generation, LLC (Midwest Generation) and EME Homer City Generation L.P. (EME Homer City) futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in the relevant markets are greater than the contract prices. The decrease in the unrealized losses during the first quarter of 2006 resulted from a decrease in market prices for power driven largely by lower natural gas prices.

        As EME's hedged positions for continuing operations are realized, approximately $54 million, after tax, of the net unrealized losses on cash flow hedges at March 31, 2006 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, 2007.

8

        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 $11 million and $4 million during the first quarters of 2006 and 2005, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in net gains from price risk management and energy trading in EME's consolidated income statements.

Note 5. Acquisitions and Consolidations

Acquisitions

        On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. to acquire a 99.9% interest in the Wildorado Wind Project, which owns a 161 MW wind farm located in the panhandle of northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights, title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the project retained by Cielo. During the first quarter of 2006, construction started on the project with turbine deliveries scheduled to begin in November 2006 and commercial operations expected in April 2007.

        The total purchase price was $29 million. As of March 31, 2006, a cash payment of $18 million was made towards the purchase price. Total project costs of the Wildorado wind project are estimated to be approximately $270 million. The acquisition was accounted for utilizing the purchase method. The fair value of the Wildorado wind project was equal to the purchase price and as a result, the total purchase price was allocated to property, plant and equipment in EME's consolidated balance sheet.

Consolidations

Variable Interest Entities

        In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). FIN 46R defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. Under FIN 46R, the primary beneficiary is the variable interest holder that absorbs a majority of expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met.

        EME completed a review of the application of FIN 46R 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, 2006, 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 $315 million as of March 31, 2006.

9

Note 6. Divestitures

Dispositions

        On March 7, 2006, EME completed the sale of a 25% 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.

Discontinued Operations

Tri Energy Project

        On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project pursuant to a Purchase Agreement, dated December 15, 2004, by and between EME and a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million. EME recorded an impairment charge of approximately $5 million during the fourth quarter of 2004 related to the planned disposition of this investment. The sale of this investment had no significant effect on net income in the first quarter of 2005.

CBK Project

        On January 10, 2005, EME sold its 50% equity interest in the CBK project pursuant to a Purchase Agreement, dated November 5, 2004, by and between EME and Corporacion IMPSA S.A. Proceeds from the sale were approximately $104 million. EME recorded a pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.

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 its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim against the TXU subsidiary for damages from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £18 million (approximately $31 million) in February 2006, £43 million (approximately $75 million) in March 2006, and £9 million (approximately $16 million) in April 2006. For the first quarter of 2006, the after-tax income attributable to the Lakeland project was $73 million. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method, with earnings being recognized as cash is distributed from the project.

10

Summarized Financial Information for Discontinued Operations

        In accordance with SFAS No. 144, all the projects discussed above are classified as discontinued operations in the accompanying consolidated statements of income. Summarized results of discontinued operations are as follows:

	Three Months Ended March 31,
	2006		2005
	(in millions)
Total operating revenues	$	—	$	—
Income before income taxes and minority interest		111		—
Provision (benefit) for income taxes		38		(2	)
Minority interest		—		—
Income from operations of discontinued foreign subsidiaries		73		2
Gain on sale before income taxes		—		9
Gain on sale after income taxes		—		5

        Assets of $1 million and liabilities of $4 million associated with the discontinued operations are included on the consolidated balance sheet at December 31, 2005 in other long-term assets and other long-term liabilities, respectively.

Note 7. Employee Benefit Plans

Pension Plans

        EME previously disclosed in its financial statements for the year ended December 31, 2005 that it expected to contribute $14 million to its pension plans in 2006. As of March 31, 2006, $4 million in contributions have been made. EME continues to expect to contribute $14 million to its pension plans in 2006.

        Components of pension expense are:

	Three Months Ended March 31,
	2006			2005
	(in millions)
Service cost	$	5		$	5
Interest cost		2			2
Expected return on plan assets		(2	)		(1	)
Total expense	$	5		$	6

Postretirement Benefits Other Than Pensions

        EME previously disclosed in its financial statements for the year ended December 31, 2005 that it expected to contribute $1 million to its postretirement benefits other than pensions in 2006. As of March 31, 2006, $0.3 million in contributions have been made. EME continues to expect to contribute $1 million to its postretirement benefits other than pensions in 2006.

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        Components of postretirement benefits expense are:

	Three Months Ended March 31,
	2006		2005
	(in millions)
Service cost	$	1	$	1
Interest cost		1		1
Amortization of unrecognized prior service costs		—		(1	)
Total expense	$	2	$	1

Note 8. Commitments and Contingencies

Capital Improvements

        At March 31, 2006, EME's subsidiaries had firm commitments to spend approximately $163 million during the remainder of 2006 and $35 million in 2007 on capital and construction expenditures. The majority of these expenditures relate to the construction of the Wildorado wind project. Also included are expenditures for boiler header replacement, dust collection and mitigation system and various other projects. These expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations.

Commercial Commitments

Introduction

        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, standby letters of credit, guarantees of debt and indemnifications.

Turbine Commitments

        At March 31, 2006, in connection with wind projects in development, EME had entered into agreements with turbine vendors securing 105 turbines for $115 million in 2006 and $78 million in 2007. In addition, EME has options to acquire an additional 180 turbines for delivery in 2007. In April 2006, EME issued a notice to proceed to acquire 80 of these additional turbines.

Standby Letters of Credit

        At March 31, 2006, standby letters of credit aggregated $39 million and were scheduled to expire as follows: $36 million in 2006 and $3 million in 2007.

Guarantees and Indemnities

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

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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 take all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

        Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company 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 existing asbestos claims and 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, 2006. Midwest Generation had recorded a $66 million liability at March 31, 2006 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. 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. Payments would be triggered under this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.

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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. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. The right of first refusal matter has been submitted to arbitration, with hearings having been conducted during February 2006. It is expected that a decision of the arbitration panel will be rendered in the coming months. 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, 2006, EME had recorded a liability of $119 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.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

        On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which held a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through January 2007. At March 31, 2006, EME had recorded a liability of $4 million related to this indemnity.

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, 2006, if payment were required, would be $116 million. EME has not recorded a liability related to these indemnities.

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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. This agreement runs through 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

MISO Revenue Sufficiency Guarantee Charges

        On April 25, 2006, the FERC issued an order regarding the MISO's "Revenue Sufficiency Guarantee" charges (RSG charges). The MISO's business practice manuals and other instructions to market participants have stated, since the implementation of market operations in April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO's tariff concerning that issue and in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges, and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO's tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. Edison Mission Marketing & Trading (EMMT) made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, it is likely that the FERC's April 25 order will be challenged by the MISO and other parties, including EMMT, and the eventual outcome of these proceedings is unclear. The FERC's order also requires the MISO to modify its tariff on a prospective basis to impose RSG charges on virtual supply offers. At this time, it is not possible to predict how the prospective effect of the order will affect the nature and operation of the MISO markets.

Tax Matters

        EME is, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions it takes in connection with the filing of its tax returns. Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in EME's opinion, it is unlikely that the resolution of any such matters will have a material adverse effect upon EME's financial condition or results of operations.

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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

        EME and its subsidiaries are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which EME conducts its business, and may also cause it to make substantial additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not be materially adversely affected as a result.

        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 the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent that the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $3 million at March 31, 2006 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 16. Commitments and Contingencies—Environmental Matters and Regulations" in EME's financial statements included in its annual report on Form 10-K for the year ended December 31, 2005 for a more complete discussion of EME's environmental contingencies.

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Note 9. Supplemental Statements of Cash Flows Information

		Three Months Ended March 31,
		2006		2005
		(in millions)
Cash paid
	Interest (net of amount capitalized)	$	34	$	40
	Income taxes		5		21
	Cash payments under plant operating leases		92		49
Details of assets acquired
	Fair value of assets acquired	$	29	$	—
	Liabilities assumed		—		—

        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 10. Stock Compensation Plans

Stock Options

        Under various plans, EME may grant stock options at exercise prices equal to the average of high and low price at the grant date and other awards related to or with a value derived from Edison International common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the vesting period, except for awards granted to retirement-eligible participants, as discussed in Note 1—General—Stock-Based Compensation. Stock-based compensation expense associated with stock options was $2 million for the three months ended March 31, 2006. Under prior accounting rules, there was no comparable expense recognized for the same period in 2005. See Note 1—General—Stock-Based Compensation, for further discussion.

        Beginning with awards made in 2003, stock options accrue dividend equivalents for the first five years of the option term. Unless transferred to non-qualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

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        The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in he following table.

	Three Months Ended March 31,
	2006	2005
Expected terms (in years)	9 to 10	9 to 10
Risk-free interest rate	4.3%	4.2%-4.3%
Expected dividend yield	2.4%	2.9%-3.1%
Weighted-average expected dividend yield	2.4%	3.1%
Expected volatility	16.2%	18.7%-19.6%
Weighted-average volatility	16.2%	19.6%

        The expected term of options granted is based on the actual remaining contractual term of the options. The risk-free interest rate for periods within the contractual life of the option is based on a 52-week historical average of the 10-year semi-annual coupon U.S. Treasury note. In 2006, expected volatility is based on the historical volatility of Edison International's common stock for the recent 36 months. Prior to January 1, 2006, expected volatility was based on the median of the most recent 36 months historical volatility of peer companies because Edison International's historical volatility was impacted by the California energy crisis.

        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	Aggregate Intrinsic Value
Outstanding at December 31, 2005	3,626,365		$	22.06
Granted	388,142			44.30
Transferred to affiliate	(298,647	)		21.83
Forfeited	(16,602	)		29.22
Exercised	(288,064	)		18.46
Outstanding at March 31, 2006	3,411,194		$	24.88
Vested and expected to vest at March 31, 2006	3,264,585		$	24.66	7.13	$	60,676,635
Exercisable at March 31, 2006	1,650,114		$	20.40	5.96	$	37,693,495

        The weighted-average grant-date fair value of options granted during the quarters ended March 31, 2006 and 2005 was $14.47 and $11.70, respectively. The total intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005 was $8 million and $3 million, respectively. At March 31, 2006, there was $14 million of total unrecognized compensation cost related to stock options net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately 2 years.

        Cash received from options exercised for the quarters ended March 31, 2006 and 2005 was $6 million and $3 million, respectively. The estimated tax benefit from options exercised was $3 million and $1 million for the quarters ended March 31, 2006 and 2005, respectively.

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Performance Shares

        A target number of contingent performance shares were awarded to executives in January 2004, January 2005 and March 2006, and vest at the end of December 2006, 2007 and 2008, respectively. Dividend equivalents associated with these performance shares accumulate without interest and will be payable in cash following the end of the performance period when the performance shares are paid, although Edison International has discretion to pay certain dividend equivalents in Edison International common stock. The vesting of Edison International's performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International's common stock performance relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International's ranking among these companies. Dividend equivalents will be adjusted to correlate to the actual number of performance shares paid. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the vesting period based on the fair values determined, except for awards granted to retirement-eligible participants, as discussed in "Stock-Based Compensation" in Note 1—General—Stock-Based Compensation. Stock-based compensation expense associated with performance shares was $0.4 million and $4 million for the three months ended March 31, 2006 and 2005, respectively.

        The performance shares' fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires various assumptions. Assumptions specifically related to Edison International's stock-based performance shares are noted in the following table.

	Three Months Ended March 31,
	2006	2005
Risk-free interest rate	4.1% and 4.2%	2.7	%
Expected volatility	16.2% and 17.2%	27.7	%

        The risk-free interest rate is based on a 52-week historical average of the three-year semi-annual coupon U.S. Treasury note and is used as proxy for the expected return for the specified group of companies. Volatility is based on the historical volatility of Edison International's common stock for the recent 36 months. Historical volatility for each company in the specified group is obtained from data published by Bloomberg.

        The total intrinsic value of performance shares settled during the quarters ended March 31, 2006 and 2005, was $21 million and $8 million, respectively, which included cash paid to settle the performance shares classified as liability awards of $8 million and $4 million for the three months ended March 31, 2006 and 2005, respectively. At March 31, 2006, there was $3 million (based on the March 31, 2006 fair value of performance shares classified as liability awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately 2 years.

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        A summary of the status of Edison International nonvested performance shares granted to EME employees and classified as equity awards is as follows:

	Performance Shares		Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2005	67,530		$	38.63
Granted	15,899			53.24
Forfeited	(1,266	)		39.36
Nonvested at March 31, 2006	82,163		$	41.45

        The weighted-average grant-date fair value of performance shares classified as equity awards granted during the quarter ended March 31, 2005 was $46.09.

        A summary of the status of Edison International nonvested performance shares granted to EME employees and classified as liability awards (the current portion is reflected in the caption "Accrued liabilities" and the long-term portion is reflected in "Other long-term liabilities" on the consolidated balance sheets) is as follows:

	Performance Shares		Weighted-Average Fair Value
Nonvested at December 31, 2005	67,547
Granted	15,917
Forfeited	(1,267	)
Nonvested at March 31, 2006	82,197		$	95.10

Note 11. New Accounting Pronouncements

Statement of Financial Accounting Standards No. 151

        In November 2004, the FASB issued SFAS No. 151, "Inventory Costs." SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current- period charges. Further, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. Unallocated overheads must be recognized as an expense in the period in which they are incurred. SFAS No. 151 is effective for inventory costs incurred beginning in the first quarter of 2006. The adoption of this standard had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 123(R)

        A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. EME implemented the new standard in the first quarter of 2006 and applied the modified prospective transition method. Under the modified prospective method, the new accounting standard was applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not restated under this method. The new accounting standard resulted in the recognition of expense for all stock-based compensation awards. Prior to January 1, 2006, EME used the intrinsic value method of accounting, which resulted in no recognition of expense for Edison International stock options.

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        Prior to adoption of the new accounting standard, EME presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under the caption "Other operating—liabilities" in the consolidated statements of cash flows. The new accounting standard requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $3 million excess tax benefit is classified as a financing cash inflow in 2006.

        Due to the adoption of this new accounting standard, EME recorded a cumulative effect adjustment that increased net income by approximately $0.4 million, net of tax, for the three months ended March 31, 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

FASB Staff Position FIN 46(R)-6

        In April 2006, the FASB issued Staff Position FIN 46(R)-6, "Determining Variability to be Considered in Applying FIN 46(R)." FIN 46(R)-6 states that the variability to be considered in applying FIN 46(R) shall be based on an analysis of the design of the entity following a two-step process. The first step is to analyze the nature of the risks in the entity. The second step would be to determine the purpose(s) for which the entity was created and determine the variability (created by the risks identified in Step 1) the entity is designed to create and pass along to its interest holders. The guidance in this FASB Staff Position is effective prospectively beginning on the first day of the first reporting period beginning after June 15, 2006. Early application as well as retrospective application is permitted, but not required. EME is currently evaluating the impact of this FASB Staff Position.

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

•

supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;

•

the cost and availability of 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 and environmental regulations that could require additional expenditures or otherwise affect EME's cost and manner of doing business;

•

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;

•

operating risks, including equipment failure, availability, heat rate and output;

•

effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events; and

•

the continued participation by EME and its subsidiaries in tax-allocation and payment agreements with their affiliates.

Additional information about risks and uncertainties is contained throughout this MD&A. Readers are urged to read this entire quarterly report on Form 10-Q and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are

22

made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2005, and as compared to the first quarter ended March 31, 2005. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2005.

        This MD&A is presented in four sections:

	Page
Management's Overview; Critical Accounting Estimates	23
Results of Operations	25
Liquidity and Capital Resources	34
Market Risk Exposures	41

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING ESTIMATES

Management's Overview

Results of Operations

        Net income is comprised of the following components:

	Three Months Ended March 31,
	2006		2005
	(in millions)
Income from continuing operations	$	73	$	55
Income from discontinued operations		73		7
Net Income	$	146	$	62

        EME's increase in income from continuing operations in the first quarter of 2006 was primarily attributable to higher earnings at the Illinois Plants, driven by higher wholesale energy prices, and higher interest and other income. Partially offsetting these increases was lower earnings at the Homer City facilities due to a transformer failure related to Unit 3 that increased the forced outage rate during the quarter to 23% from 7% in the first quarter of 2005. Homer City revised its outage plan for Unit 3 to accelerate into the period February through April 2006 44 days of outage time that was originally scheduled for early 2007. Unit 3 returned to service on May 5, 2006.

        EME's income from discontinued operations during the first quarter of 2006 primarily related to distributions authorized by the liquidators of the Lakeland power project. Together with $16 million received in April 2006, EME has received a total of $122 million of distributions in 2006 from the settlement of a 2001 claim for termination of a power contract by a subsidiary of TXU Europe Group plc. The activities of the Lakeland liquidator are near completion and substantially all the distributions from the Lakeland project have been made.

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Wind Business Development

        EME has undertaken a number of key activities in 2006 with respect to wind projects, including the following:

•

In January 2006, EME purchased the development rights for the Wildorado wind project for $29 million. This project started construction on April 24, 2006. Project completion is scheduled for April 2007, with total project costs estimated to be $270 million. Upon completion, power from the project will be sold under a twenty-year power purchase agreement with Southwestern Public Service.



•

In March 2006, EME sold 25% of its ownership interest in the San Juan Mesa wind project to a third party for $43 million.



•

In April 2006, EME received, as a capital contribution from its parent, a 196 MW portfolio of wind projects located in Iowa and Minnesota. These projects were previously owned by EME's affiliate, Edison Capital.

Financing Plans

        EME has engaged investment and commercial banks to undertake a refinancing of indebtedness. If effected, EME anticipates that the refinancing will include the following:

•

A private placement of up to $1.0 billion of new senior notes, the proceeds of which will be used, together with cash on hand, to purchase any or all of EME's outstanding 10% senior notes due 2008 and 9.875% senior notes due 2011.



•

The replacement of EME's existing $98 million secured corporate credit facility with a new secured corporate credit facility providing for $500 million in revolving loan and letter of credit capacity to be used to repay existing debt and/or to provide liquidity and credit support for the hedging and trading activities of EME and its subsidiaries.

        To effect its refinancing, EME will offer to purchase the outstanding senior notes referred to above. In connection with its offer, EME will solicit consents to amendments to the terms of the outstanding senior notes, including amendments necessary to permit EME to increase the size of its secured corporate credit facility. EME expects to pay a premium using its existing cash on hand to purchase the outstanding senior notes that are tendered and accepted for purchase. Its offer to purchase these outstanding senior notes will be conditioned upon the successful issuance of its new senior notes.

        The refinancing is expected to improve EME's liquidity, to extend the maturity dates of EME's indebtedness, to reduce annual interest costs, and to improve the operating flexibility of the covenants associated with EME's outstanding debt. Completion of this refinancing, if effected, will result in a significant charge against income for early retirement of the outstanding senior notes. There is no assurance that this or any other refinancing will be completed on the terms outlined above or at all.

Critical Accounting Estimates

        For a discussion of EME's critical accounting estimates, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates" of EME's annual report on Form 10-K for the year ended December 31, 2005.

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RESULTS OF OPERATIONS

Introduction

        This section discusses operating results for the first quarters of 2006 and 2005. Continuing operations include EME's Illinois Plants and Homer City facilities, energy trading, the San Juan Mesa wind project, equity investments in power projects primarily located in California, corporate interest expense and general and administrative expenses. Discontinued operations include all of EME's international operations, except the Doga project. This section is organized under the following headings:

	Page
Results of Continuing Operations	25
Results of Discontinued Operations	32
New Accounting Pronouncements	33
Proposed Accounting Pronouncements	33

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. Equity in income from unconsolidated affiliates relates to energy projects accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

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

25

        The following section provides a summary of the operating results for the first quarters of 2006 and 2005 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Three Months Ended March 31,
		2006			2005
		(in millions)
Project Earnings (Losses)(1)
	Consolidated operations
	Illinois Plants	$	127		$	92
	Homer City		(2	)		42
	Energy Trading(2)		30			22
	San Juan Mesa		3			—
	Other		—			(1	)
	Unconsolidated affiliates
	Big 4 projects		23			21
	Sunrise		(2	)		(3	)
	March Point		—			8
	Doga		—			4
	Other		—			2
			179			187
	Corporate interest expense		(66	)		(68	)
	Corporate and regional administrative and general		(24	)		(33	)
	Gain on sale of assets		4			—
	Loss on early extinguishment of debt		—			(4	)
	Corporate interest income and other expense, net		27			7
		$	120		$	89

(1)

Project earnings are equal to income from continuing operations before income taxes, except for production tax credits. Accordingly, project earnings for the San Juan Mesa wind project include $3 million of production tax credits for the three months ended March 31, 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 generally accepted accounting principles (GAAP), production tax credits generated by the San Juan Mesa wind project are recorded as a reduction in income taxes. Accordingly, project earnings (losses) represent a non-GAAP financial measure. 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 total project earnings as shown above with income from continuing operations before income taxes under GAAP:

	Three Months Ended March 31,
	2006			2005
	(in millions)
Project earnings	$	120		$	89
Production tax credits		(3	)		—
Income from continuing operations before income taxes	$	117		$	89

(2)

Income from energy trading represents the gains recognized from price volatility associated with the purchase and sale of contracts for electricity, fuels and transmission. The indirect cost of energy trading is included in administrative and general expenses.

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Earnings from Consolidated Operations

Illinois Plants

			Three Months Ended March 31,
			2006			2005
			(in millions)
Operating Revenues
	Energy revenues		$	338		$	327
	Capacity revenues			6			6
	Other revenues			2			2
	Net losses from price risk management			—			(10	)
	Total operating revenues			346			325
Operating Expenses
	Fuel			94			99
	Gain on sale of emission allowances(1)			(6	)		—
	Plant operations			81			84
	Plant operating leases			19			18
	Depreciation and amortization			25			25
	Administrative and general			5			5
	Total operating expenses			218			231
Operating Income				128			94
Other Income (Expense)
	Interest income from note receivable from EME			28			28
	Interest expense and other			(29	)		(30	)
	Total other income (expense)			(1	)		(2	)
Income Before Taxes			$	127		$	92
Statistics
	Gross margin(2)		$	250		$	224
	Coal-Fired Generation(3)
		Generation (in GWh)		7,244			8,394
		Equivalent availability(4)		86.8%			80.2%
		Capacity factor(5)		59.8%			69.2%
		Load factor(6)		68.8%			86.3%
		Forced outage rate(7)		2.8%			8.0%
	Average energy price/MWh		$	46.69		$	38.94
	Average fuel costs/MWh		$	12.92		$	11.85

(1)

EME recorded $6 million of intercompany profit during the first quarter of 2006 on emission allowances sold by the Illinois Plants to the Homer City facilities in the fourth quarter of 2005 but not used by the Homer City facilities until the first quarter of 2006.

(2)

Gross margin is equal to the sum of energy revenues, capacity revenues and net losses from price risk management less fuel expenses.

(3)

This table summarizes key performance measures related to coal-fired generation, which represents the majority of the operations of the Illinois Plants.

(4)

The equivalent availability factor is defined as the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period.

27

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.

(5)

The capacity factor is defined as the actual number of megawatt-hours generated by the coal plants divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period.

(6)

The load factor is determined by dividing capacity factor by the equivalent availability factor.

(7)

Midwest Generation refers to unplanned maintenance as a forced outage.

        Earnings from the Illinois Plants were $127 million during the first quarter of 2006, compared to $92 million during the first quarter of 2005. The increase in the first quarter earnings of $35 million was primarily due to higher gross margin and recognition of income from the sale of emission allowances to the Homer City facilities. Although generation in the first quarter of 2006 was lower than the first quarter of 2005, gross margin increased 12% primarily due to a 20% increase in average energy prices.

        Included in gross margin are losses from price risk management activities, which decreased $10 million for the first quarter of 2006, compared to the first quarter of 2005. The 2005 losses were primarily due to significant price increases in 2005 on power contracts that did not qualify for hedge accounting under SFAS No. 133. The 2006 losses included $1 million related to the first quarter hedge contracts which related to activities reported as energy revenues mostly offset by $1 million of unrealized gains related to the remainder of 2006 and 2007 hedge contracts. 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 2006 and 2005 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.

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Homer City

		Three Months Ended March 31,
		2006			2005
		(in millions)
Operating Revenues
	Energy revenues	$	134		$	155
	Capacity revenues		3			4
	Net losses from price risk management		(14	)		(2	)
	Total operating revenues		123			157
Operating Expenses
	Fuel(1)		61			64
	Gain on sale of emission allowances(2)		—			—
	Plant operations		35			22
	Plant operating leases		25			25
	Depreciation and amortization		4			4
	Administrative and general		1			2
	Total operating expenses		126			117
Operating Income (Loss)			(3	)		40
Other Income (Expense)
	Interest and other income		1			2
	Interest expense		—			—
	Total other income (expense)		1			2
Income (Loss) Before Taxes		$	(2	)	$	42
Statistics
	Gross margin(3)	$	62		$	93
	Generation (in GWh)		2,521			3,534
	Equivalent availability(4)		71.8%			88.1%
	Capacity factor(5)		61.9%			86.8%
	Load factor(6)		86.3%			98.6%
	Forced outage rate(7)		23.4%			7.3%
	Average energy price/MWh	$	53.03		$	43.78
	Average fuel costs/MWh	$	23.93		$	18.03

(1)

Included in fuel costs were $12 million and $15 million during the quarters ended March 31, 2006 and 2005, 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 NOx emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $6 million in the first quarter of 2006. EME eliminated the intercompany transaction for emission allowances sold but not yet used by the Illinois Plants at March 31, 2006.

(3)

Gross margin is equal to the sum of energy revenues, capacity revenues and net losses from price risk management less fuel expenses.

(4)

The equivalent availability factor is defined as the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) 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.

29

(5)

The capacity factor is defined as the actual number of megawatt-hours generated by the coal plants divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period.

(6)

The load factor is determined by dividing capacity factor by the equivalent availability factor.

(7)

Homer City refers to unplanned maintenance as a forced outage.

        Earnings from Homer City decreased $44 million for the first quarter of 2006, compared to the first quarter of 2005. The 2006 decrease is primarily attributable to lower gross margin and higher plant operating costs in 2006 due to an unplanned outage at Unit 3. Homer City is generally classified as a baseload plant, which means the amount of generation is largely based on the availability of the plant. Accordingly, the Unit 3 outage reduced the amount of expected generation during the first quarter of 2006.

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. Homer City has adjusted its previously planned outage schedules for Unit 3 and the other Homer City units in order to minimize to the extent practicable overall outage activities for all units through the first half of 2007. Although it had been anticipated that with the adjustment of outage schedules generation for the year as a whole would not be significantly affected, difficulties in transporting the new transformer to the site resulted in a longer outage than originally planned for the transformer repair. Taking into consideration the impact of the outage, generation for the year is currently expected to be approximately 13 TWh. The actual financial impact and generation levels in 2006 will depend on the effect of market conditions upon the dispatch of the plant and on prevailing power prices during the balance of the year.

        The main transformer failure will result in claims under Homer City's property and business interruption insurance policies. At March 31, 2006, Homer City has recorded a $3 million receivable related to the property insurance coverage. No receivable has been recorded at March 31, 2006 for the business interruption insurance coverage as the potential recovery could not be reasonably estimated.

Price Risk Management—

        Included in gross margin are losses from price risk management activities which increased $12 million for the first quarter of 2006, compared to the first quarter of 2005. The 2006 increase is primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. Homer City recorded losses of approximately $11 million and $4 million during the first quarters of 2006 and 2005, respectively, representing the amount of cash flow hedges' ineffectiveness. The 2006 ineffective losses from Homer City are related to the remainder of 2006 and 2007 hedge contracts and were 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). Also included in losses from price risk management activities are economic hedges that did not qualify for hedge accounting under SFAS No. 133 of $(3) million and $2 million in the first quarters of 2006 and 2005, respectively. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

Energy Trading

        EME seeks to generate profit by utilizing the commercial platform of its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the

30

merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission primarily in the eastern power grid using products available over the counter, through exchanges and from independent system operators. Earnings from energy trading activities were $30 million and $22 million for the first quarters ended March 31, 2006 and 2005, respectively. The increase in earnings from energy trading activities was primarily due to increased congestion at specific delivery points in the eastern power grid in which EMMT purchased financial transmission rights. See "Market Risk Exposures—Regulatory Matters—MISO Revenue Sufficiency Guarantee Charge" for information regarding potential refund exposure related to virtual supply offers made by EMMT in MISO after April 1, 2005.

San Juan Mesa

        EME's earnings from the San Juan Mesa wind project were $3 million for the first quarter of 2006, with no earnings recorded in 2005 due to the acquisition of the San Juan Mesa wind project on December 27, 2005.

        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.

Earnings from Unconsolidated Affiliates

Big 4 Projects

        Earnings from the Big 4 projects increased $2 million for the first quarter of 2006, compared to the first quarter of 2005. The increase in earnings was primarily due to higher steam and energy prices in 2006 over 2005. The impact of the higher steam and energy prices in 2006 was partially offset by lower earnings from the Kern River project during the first quarter in 2006, compared to the first quarter of 2005, resulting from the expiration of the project's long-term power purchase and steam supply agreements in August 2005.

        The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $2 million and $3 million for the first quarters of 2006 and 2005, respectively.

March Point

        EME's share of earnings from its ownership interest in March Point was $8 million for the first quarter of 2005 resulting, in part, from mark-to-market gains related to gas purchase contracts. During the third quarter of 2005, EME recorded an impairment charge related to its March Point investment which resulted in suspension of equity accounting. Accordingly, no earnings were recorded during the first quarter of 2006.

Doga

        Earnings from the Doga project decreased $4 million for the first quarter of 2006, compared to the first quarter of 2005. The first quarter decrease in earnings was primarily attributable to lower generation and higher major maintenance costs due to a plant outage.

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Seasonal Disclosure

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

Corporate Interest Expense

	Three Months Ended March 31,
	2006		2005
	(in millions)
Interest expense to third parties	$	38	$	40
Interest expense to Midwest Generation		28		28
Total corporate interest expense	$	66	$	68

Corporate and Regional Administrative and General Expenses

        Administrative and general expenses decreased $9 million for the first quarter of 2006, compared to the first quarter of 2005. The 2006 decrease was primarily due to $7 million of costs incurred during the first quarter of 2005 for severance and related costs in connection with EME restructuring activities.

Loss on Early Extinguishment of Debt

        Loss on early extinguishment of debt was $4 million in the first quarter of 2005 consisting of a $4 million loss related to the early repayment of junior subordinated debentures.

Corporate Interest Income and Other, Net

        Corporate interest income and other (net) increased $20 million for the first quarter of 2006, compared to the first quarter of 2005. The 2006 increase was attributable to higher interest income and an $8 million gain related to receipt of shares from Mirant Corporation from settlement of a claim.

Income Taxes

        EME's income tax provision from continuing operations was $44 million and $34 million during the first quarters of 2006 and 2005, 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."

Results of Discontinued Operations

        Income from discontinued operations, net of tax, was $73 million and $7 million during the first quarters of 2006 and 2005, respectively. The 2006 increase is largely attributable to distributions

32

received from the Lakeland project, discussed below. During the first quarter of 2005, EME completed the following sales:

•

On January 10, 2005, EME sold its 50% equity interest in the CBK hydroelectric power project to CBK Projects B.V. Proceeds from the sale were approximately $104 million.



•

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project to IPM. Proceeds from the sale were approximately $20 million.

        The aggregate after-tax gain on the sale of the aforementioned projects was $5 million.

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 its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim for damages resulting from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £18 million (approximately $31 million) in February 2006, and £43 million (approximately $75 million) in March 2006, and £9 million (approximately $16 million) in April 2006. For the first quarter of 2006, the after-tax income attributable to the Lakeland project was $73 million. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method, with earnings being recognized as cash is distributed from the project.

New Accounting Pronouncements

        For a discussion of new accounting pronouncements affecting EME, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 11. New Accounting Pronouncements."

Proposed Accounting Pronouncements

        In July 2005, the FASB published an exposure draft of a proposed interpretation that seeks to clarify the accounting for uncertain tax positions. An enterprise would be required 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. The proposed effective date is January 1, 2007. The FASB is expected to issue a final interpretation in the second quarter of 2006. EME is currently assessing the potential impact of the proposed interpretation on its results of operations and financial condition.

33

LIQUIDITY AND CAPITAL RESOURCES

Introduction

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

	Page
EME's Liquidity	34
Capital Expenditures	34
EME's Historical Consolidated Cash Flow	35
Credit Ratings	36
Margin, Collateral Deposits and Other Credit Support for Energy Contracts	36
EME's Liquidity as a Holding Company	37
Dividend Restrictions in Major Financings	39
Off-Balance Sheet Transactions	40
Environmental Matters and Regulations	40

        For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2005.

EME's Liquidity

        At March 31, 2006, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.5 billion and EME had available the full amount of borrowing capacity under its $98 million corporate credit facility. EME's consolidated debt at March 31, 2006 was $3.2 billion. In addition, EME's subsidiaries had $4.5 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 29 years.

Capital Expenditures

        The estimated capital and construction expenditures of EME's subsidiaries are $317 million for the remaining three quarters of 2006 and $232 million and $28 million for 2007 and 2008, respectively. The non-environmental portion of these expenditures relates to the construction of the Wildorado wind project, purchases of turbines, upgrades to dust collection/mitigation systems and the coal handling system, ash removal improvements and various other projects. EME plans to finance these expenditures with existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the estimated expenditures are environmental expenditures of $5 million for the remaining three quarters of 2006, $12 million for 2007 and $6 million for 2008. The environmental expenditures relate to environmental projects such as selective catalytic reduction system improvements at the Homer City facilities and projects at the Illinois Plants. EME's subsidiaries may also make substantial additional capital expenditures as described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations—Federal-United States of America—Mercury Regulation" of EME's annual report on Form 10-K for the year ended December 31, 2005. As part of these expenditures, EME Homer City is in the process of engaging a third party to commence preliminary engineering and advance procurements for pollution control equipment to be installed in 2009. A decision regarding whether to proceed with installation of this equipment is expected to be made later this year.

34

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

        Cash provided by operating activities from continuing operations increased $342 million in the first quarter of 2006, compared to the first quarter of 2005. The 2006 increase was primarily attributable to a decrease of $109 million in required margin and collateral deposits in 2006 for EME's price risk management and trading activities, compared to an increase of $76 million in 2005. This change resulted from a decrease in forward market prices at March 31, 2006 as compared to December 31, 2005. In addition, there was a decrease of $152 million in accounts receivable in 2006, compared to an increase of $53 million in 2005. The 2006 decrease was largely due to a decrease in EME's accounts receivable due from PJM at March 31, 2006 as compared to December 31, 2005. The decrease in accounts receivable resulted from lower monthly revenue in March 2006 compared to December 2005 primarily due to lower generation.

        Cash provided by operating activities from discontinued operations increased $72 million in the first quarter of 2006, compared to the first quarter of 2005. The 2006 increase reflects distributions received in 2006 that were authorized by the liquidators of 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 $357 million in the first quarter of 2006, compared to the first quarter of 2005. The 2006 decrease was primarily due to dividend payments made to MEHC of $360 million and the repayment of the junior subordinated debentures of $150 million during the first quarter of 2005. Partially offsetting these decreases was a repayment of $170 million on Midwest Generation's $500 million working capital facility and a $12 million dividend payment to MEHC during the first quarter of 2006.

Consolidated Cash Flows from Investing Activities

        Cash used in investing activities from continuing operations increased $385 million in the first quarter of 2006, compared to the first quarter of 2005. The 2006 increase was primarily due to net purchases of marketable securities of $45 million in the first quarter of 2006, compared to net sales of marketable securities of $140 million in the first quarter of 2005. In addition, EME paid $18 million towards the purchase price of the Wildorado wind project during the first quarter of 2006, incurred higher capital expenditures in 2006 and received lower proceeds from sales of projects. In 2005, EME received proceeds of $124 million from the sale of its 25% investment in the Tri Energy project and its 50% investment in the CBK project compared to proceeds of $43 million in March 2006 from the sale of 25% of its ownership interest in the San Juan Mesa wind project.

35

Credit Ratings

Overview

        Credit ratings for EME and its subsidiaries, Midwest Generation and EMMT, are as follows:

		Moody's Rating	S&P Rating
EME		B1	B+
Midwest Generation:
	First priority senior secured rating	Ba3	BB-
	Second priority senior secured rating	B1	B
EMMT		Not Rated	B+

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

        EME does not have any "rating triggers" contained in subsidiary financings that would result in it 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 Standard & Poor's 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, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback owner participant has not indicated that it intends to revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between EMMT and EME Homer City that had been entered into while the consent was still in effect. 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 price risk management 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

36

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 price risk management and trading activities. At March 31, 2006, EMMT had deposited $411 million in cash with brokers in margin accounts in support of futures contracts and had deposited $178 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $21 million in support of commodity contracts at March 31, 2006.

        Margin and collateral deposits increased during the past year due to higher wholesale energy prices and increased megawatt hours hedged under contracts requiring margin and collateral. Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2006, if wholesale energy prices increase further or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of March 31, 2006 could increase by approximately $290 million using a 95% confidence level during the next twelve months.

        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, 2006, Midwest Generation had available the full amount of borrowing capacity under this credit facility. As of March 31, 2006, Midwest Generation had $224 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and a $98 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, 2006, 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."

        As security for its obligations under EME's corporate credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects are deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

        At March 31, 2006, EME also had available $66 million under Midwest Generation EME, LLC's $100 million letter of credit facility with Citibank, N.A., as Issuing Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation EME is required to deposit cash in a bank account in order to cash collateralize any letters of credit that may be outstanding under the facility. The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings, which in turn owns 100% of Midwest Generation, LLC.

37

EME Homer City Interim Funding Arrangements

        During March 2006, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $9 million to EME Homer City under the subordinated revolving loan agreement in place between Edison Mission Finance and EME Homer City. The funds were used to assist EME Homer City with a cash shortfall resulting from reduced revenues and higher maintenance expenses caused by the Unit 3 outage. For similar reasons, at the end of March 2006 and April 2006, EMMT made advance payments to EME Homer City in the amounts of $43.5 million and $20 million, respectively, against future deliveries of power to it under its trading arrangements with EME Homer City. The proceeds of the subordinated loans were deposited in EME Homer City's operating account and the prepayment by EMMT was deposited in EME Homer City's revenue account. It is currently anticipated that a substantial portion of the advance payments will be applied against amounts invoiced to EMMT within the next 12 months.

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,
		2006		2005
		(in millions)
Distributions from Consolidated Operating Projects:
	Edison Mission Midwest Holdings (Illinois Plants)(1)	$	185	$	62
	EME Homer City Generation L.P. (Homer City facilities)		—		24
Distributions from Unconsolidated Operating Projects:
	Edison Mission Energy Funding Corp. (Big 4 Projects)(2)		40		29
	Holding companies for Westside projects		2		3
	Holding companies of other unconsolidated operating projects		—		3
Total Distributions		$	227	$	121

(1)

Subsequent to March 31, 2006, Edison Mission Midwest Holdings made an additional distribution of $196 million.

(2)

The Big 4 projects are comprised 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.

38

Intercompany Tax-Allocation Agreement

        EME is 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 EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME 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 EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives 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 EME's tax losses or the tax losses of EME in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME paid tax-allocation payments to Edison International of $28 million and $20 million during the first quarters of 2006 and 2005, respectively.

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, 2006:

Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation, LLC (Illinois Plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	6.58 to 1
Midwest Generation, LLC (Illinois Plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	1.75 to 1
EME Homer City Generation L.P. (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.37 to 1(1)

(1)

The senior rent service coverage ratio is determined by dividing net operating cash flow by senior rent. Net operating cash flow represents revenues less operating expenses as defined in the sale-leaseback documents. Revenue during the twelve months ended March 31, 2006 includes $43.5 million from an advance payment from EMMT on March 31, 2006 against future deliveries of power to it under its trading arrangements with EME Homer City.

        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

39

Restrictions in Major Financings" of EME's annual report on Form 10-K for the year ended December 31, 2005.

Off-Balance Sheet Transactions

        For a discussion of EME's off-balance sheet transactions, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Transactions" of EME's annual report on Form 10-K for the year ended December 31, 2005. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report.

Environmental Matters and Regulations

        For a discussion of EME's environmental matters, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations" of EME's annual report on Form 10-K for the year ended December 31, 2005 and the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as follows:

State—Illinois

Air Quality

        On March 14, 2006, the Illinois Environmental Protection Agency submitted a proposed rule to the Illinois Pollution Control Board (PCB) for adoption. The proposed rule requires a reduction of mercury emissions from coal-fired power plants by 90% averaged across company-owned Illinois stations and a minimum reduction of 75% for individual generating units by July 1, 2009. A 90% reduction at each station would be required by 2013. The PCB has scheduled hearings for June and August 2006.

40

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	41
Credit Risk	48
Interest Rate Risk	50
Fair Value of Financial Instruments	50
Regulatory Matters	51

        For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2005.

Commodity Price Risk

General 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

41

•

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 from unit to unit.

        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. Hedge transactions are also entered into as forward sales to utilities and power marketing companies.

        The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether 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, Midwest Generation's and EMMT'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

42

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, negotiated by EMMT with customers through a combination of bilateral agreements, forward energy sales and spot market sales. As discussed further below, power generated at the Illinois Plants is generally sold into the PJM market.

        Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants were direct "wholesale customers" and broker arranged "over-the-counter customers." Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, linking eastern PJM and the Northern Illinois control areas of the PJM system and allowing the Illinois Plants to be dispatched into the broader PJM market. Further, on April 1, 2005, the MISO commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region, in the MISO, where there is a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM.

        Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing and is no longer required to arrange and pay separately for transmission when making sales to wholesale buyers within the PJM system. Hedging transactions related to the generation of the Illinois units are entered into at the Northern Illinois Hub in PJM, the AEP/Dayton Hub in PJM and, with the advent of the MISO, at the Cinergy Hub in the MISO. Because of proximity, the Illinois Plants are primarily hedged with transactions at the Northern Illinois Hub, but from time to time may be hedged in limited amounts at the AEP/Dayton Hub and the Cinergy Hub. These trading hubs have been the most liquid locations for these 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.

        The PJM pool 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.

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        The following table depicts the average historical market prices for energy per megawatt-hour during the first three months of 2006 and 2005.

	24-Hour Northern Illinois Hub Historical Energy Prices*
	2006		2005
January	$	42.27	$	38.36
February		42.66		34.92
March		42.50		45.75
Quarterly Average	$	42.48	$	39.68

*

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, 2006:

		24-Hour Northern Illinois Hub Forward Energy Prices*
2006
	April	$	40.42
	May		40.21
	June		43.94
	July		52.82
	August		54.92
	September		43.06
	October		40.28
	November		42.61
	December		52.26
2007 Calendar "strip"(1)		$	48.61

(1)

Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.

*

Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.

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        The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at March 31, 2006:

	2006		2007
Megawatt hours		13,166,940		15,030,000
Average price/MWh(1)	$	47.60	$	49.22

(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 during the day 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, 2006 is not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

Energy Price Risk Affecting Sales from the Homer City Facilities

        Electric power generated at the Homer City facilities is generally sold into the PJM market. The PJM pool 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 in PJM during the first three months of 2006 and 2005:

	Historical Energy Prices* 24-Hour PJM
	Homer City				West Hub
	2006		2005		2006		2005
January	$	48.67	$	45.82	$	54.57	$	49.53
February		49.54		39.40		56.39		42.05
March		53.26		47.42		58.30		49.97
Quarterly Average	$	50.49	$	44.21	$	56.42	$	47.18

*

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.

45

        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, 2006:

		24-Hour PJM West Hub Forward Energy Prices*
2006
	April	$	51.67
	May		51.99
	June		57.21
	July		68.87
	August		70.85
	September		56.44
	October		54.40
	November		57.26
	December		66.63
2007 Calendar "strip"(1)		$	66.79

(1)

Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.

*

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.

        The following table summarizes Homer City's hedge position at March 31, 2006:

	2006		2007
Megawatt hours		6,622,400		7,590,000
Average price/MWh(1)	$	53.54	$	64.33

(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 during the day 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, 2006 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 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 known as the PJM West Hub in the case of the Homer City facilities and for a settlement point known as the Northern Illinois Hub in the case of the Illinois Plants. EME's price risk management 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,

46

•

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 the PJM 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 by EME as "basis risk." During the three months ended March 31, 2006, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (EME Homer City's primary trading hub) by an average of 11%, compared to 6% during the three months ended March 31, 2005. The monthly average difference during the twelve months ended March 31, 2006 ranged from zero to 20%, which occurred in August 2005. 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 the settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME has purchased 8.4 TWh of financial transmission rights and basis swaps in PJM for Homer City during the period April 1, 2006 through May 31, 2007, and may continue to purchase financial transmission rights and basis swaps in the future. 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 price risk management activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal Price and Transportation Risk

        The Illinois Plants use approximately 18 million to 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of Wyoming. In addition, the Homer City facilities use approximately 5 million to 6 million tons of coal annually, obtained from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements with terms ranging from one year to eight years. The following table summarizes the percent of expected coal requirements for the next five years that were under contract at March 31, 2006.

	Percent of Coal Requirements Under Contract
	2006(1)	2007	2008	2009	2010
Illinois Plants	104%	95%	33%	33%	33%
Homer City facilities	102%	90%	36%	15%	0%

(1)

The percentage in 2006 is calculated based on coal supply and expected generation requirements for a full year.

        EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which is purchased for the Homer City facilities, increased considerably during 2005. The price of NAPP coal (with 13,000 British Thermal units (Btu) per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) fluctuated between $44 per ton and $57 per ton during 2005, with a price of $45 per ton at March 17, 2006, as reported by the Energy Information

47

Administration. The 2005 overall increase in the NAPP coal price was largely attributed to greater demand from domestic power producers and increased international shipments of coal to Asia. During the first quarter of 2006, the price of NAPP coal remained constant at $45 per ton. Prices of Powder River Basin (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, significantly increased in 2005 due to the curtailment of coal shipments during 2005 due to increased PRB coal demand from other regions (east), rail constraints (discussed below), higher oil and natural gas prices and higher prices for SO2 allowances. On March 17, 2006, the Energy Information Administration reported the price of coal to be $14.40 per ton, which compares to 2005 prices that ranged from $6.20 per ton to $18.48 per ton. The price of coal decreased during the first quarter of 2006 from 2005 year-end prices due to lower prices for SO2 allowances and mild weather during the first quarter of 2006.

        During 2005, the rail lines that bring coal from the PRB to EME's Illinois Plants were damaged from derailments caused by heavy rains. The railroads are in the process of making necessary repairs to the remaining PRB joint line. Repairs are expected to continue through most of 2006. Based on communication with the transportation provider, EME expects to continue receiving a sufficient amount of coal to generate power at historical levels while these repairs are being completed.

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 NOx SIP Call requirement. Under these programs, 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. 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.

        The price of emission allowances, particularly SO2 allowances issued through the federal Acid Rain Program decreased during the first quarter of 2006 from 2005 year-end prices. The average price of purchased SO2 allowances decreased to $928 per ton during the first quarter of 2006 from $1,219 per ton during 2005. The decrease in the price of SO2 allowances during the first quarter of 2006 from 2005 year-end prices has been attributed to lower loads in January 2006 and a decline in natural gas prices. The price of SO2 allowances, determined by obtaining broker quotes and information from other public sources, was $675 per ton as of April 28, 2006.

        For a discussion of environmental regulations related to emissions, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations" of EME's annual report on Form 10-K for the year ended December 31, 2005.

Credit Risk

        In conducting EME's price risk management 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.

48

        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.

        EME measures credit risk exposure from counterparties of its merchant energy activities 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 price risk management 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, 2006, the amount of exposure, broken down by the credit ratings of EME's counterparties, was as follows:

S&P Credit Rating	March 31, 2006
	(in millions)
A or higher	$	54
A-		58
BBB+		51
BBB		62
BBB-		1
Below investment grade		5
Total	$	231

        EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term 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 markets or transact capacity on a bilateral basis. Sales into the PJM pool accounted for approximately 77% of EME's consolidated operating revenues for the three months ended March 31,

49

2006. Moody's Investors Service rates PJM's senior unsecured debt Aa3. PJM, an independent system operator with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all members based upon a predetermined formula. At March 31, 2006, EME's account receivable due from PJM was $68 million.

Interest Rate Risk

        Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated long-term obligations (including current portion) was $3.5 billion at March 31, 2006, compared to the carrying value of $3.2 billion.

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, 2006			December 31, 2005
Commodity price:
	Electricity	$	(165	)	$	(434	)

        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 following table summarizes the maturities and the related fair value, based on actively traded prices, of EME's commodity price risk management assets and liabilities as of March 31, 2006 (in millions):

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(165	)	$	(139	)	$	(26	)	$	—	$	—

Energy Trading Derivative Financial Instruments

        The fair value of the commodity financial instruments related to energy trading activities as of March 31, 2006 and December 31, 2005, are set forth below (in millions):

	March 31, 2006				December 31, 2005
	Assets		Liabilities		Assets		Liabilities
Electricity	$	138	$	28	$	127	$	27
Other		1		1		1		—
Total	$	139	$	29	$	128	$	27

50

        The change in the fair value of trading contracts for the quarter ended March 31, 2006, was as follows (in millions):

Fair value of trading contracts at January 1, 2006	$	101
Net gains from energy trading activities		32
Amount realized from energy trading activities		(22	)
Other changes in fair value		(1	)
Fair value of trading contracts at March 31, 2006	$	110

        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, 2006) (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	23	$	20	$	3	$	—	$	—
Prices based on models and other valuation methods		87		1		11		16		59
Total	$	110	$	21	$	14	$	16	$	59

Regulatory Matters

        For a discussion of EME's regulatory matters, refer to "Item 1. Business—Regulatory Matters" of EME's annual report on Form 10-K for the year ended December 31, 2005. There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing of EME's annual report on Form 10-K for the year ended December 31, 2005, except as follows:

PJM Reliability Pricing Model

        On August 31, 2005, PJM filed under sections 205 and 206 of the Federal Power Act a proposal for a reliability pricing model (RPM) to replace its existing capacity construct. The proposal offers RPM as a new capacity construct to address the deficiencies in PJM's current structure in a comprehensive and integrated manner. On April 20, 2006, the FERC issued an Initial Order on RPM, finding that as a result of a combination of factors, PJM's existing capacity construct is unjust and unreasonable as a long-term capacity solution, because it fails to set prices adequate to ensure energy resources to meet its reliability responsibilities. Although the FERC did not find that the RPM proposal, as filed by PJM, is the just and reasonable replacement for the current capacity construct because some elements of the proposal need further development and elaboration, it did find that certain elements of the RPM proposal, with some adjustment and clarification, may form the basis for a just and reasonable capacity market. Accordingly, in the order the FERC provided guidance on PJM's RPM proposal, as well as other features that need to be included in a just and reasonable capacity market, and established further proceedings to resolve these issues.

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MISO Revenue Sufficiency Guarantee Charges

        On April 25, 2006, the FERC issued an order regarding the MISO's "Revenue Sufficiency Guarantee" charges (RSG charges). The MISO's business practice manuals and other instructions to market participants have stated, since the implementation of market operations in April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO's tariff concerning that issue and in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges, and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO's tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. EMMT made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, it is likely that the FERC's April 25 order will be challenged by the MISO and other parties, including EMMT, and the eventual outcome of these proceedings is unclear. The FERC's order also requires the MISO to modify its tariff on a prospective basis to impose RSG charges on virtual supply offers. At this time, it is not possible to predict how the prospective effect of the order will affect the nature and operation of the MISO markets.

FERC Order Regarding PJM Marginal Losses

        On May 1, 2006, the FERC issued an order in response to a complaint filed by Pepco Holdings, Inc. against PJM regarding marginal losses for transmission. The FERC concluded that PJM has violated its tariff by not implementing marginal losses and further directed PJM to implement marginal losses by October 2, 2006. Implementation of marginal losses will adjust the algorithm that calculates locational marginal prices to include a marginal loss component in addition to the already included congestion component. This may have an adverse impact on sellers in the Western PJM region. At this time, it is not possible to predict how the prospective effect of the order will affect the prices at which EME Homer City and Midwest Generation will be able to sell their power. In addition, PJM is still in the process of determining if it is technically feasible to implement marginal losses by October 2, 2006.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures" of EME's annual report on Form 10-K for the year ended December 31, 2005. 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

        EME's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of EME's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended

52

(the "Exchange Act")) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, EME's disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

        There were no changes in EME's internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the first fiscal quarter of 2006 that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

        No material legal proceedings are presently pending against EME.

ITEM 1A. RISK FACTORS

        For a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial condition, or future results, refer to "Item 1A. Risk Factors" of EME's annual report on Form 10-K for the year ended December 31, 2005. The risks described in EME's annual report on Form 10-K are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.

ITEM 6. EXHIBITS

Exhibit No.	Description
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.

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SIGNATURES

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

EDISON MISSION ENERGY
By:	/s/  W. JAMES SCILACCI W. James Scilacci Senior Vice President and Chief Financial Officer
Date:	May 8, 2006

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TABLE OF CONTENTS
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2006 (Unaudited)
SIGNATURES

EX-31.1

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Exhibit 31.1

CERTIFICATIONS

I, Theodore F. Craver, Jr., certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Edison Mission Energy (the "quarterly report");

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

(b)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and

(c)

Disclosed in this quarterly report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:    May 8, 2006 /s/ Theodore F. Craver, Jr. Theodore F. Craver, Jr.
Chairman of the Board, President and
Chief Executive Officer

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CERTIFICATIONS

EX-31.2

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Exhibit 31.2

CERTIFICATIONS

I, W. James Scilacci, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Edison Mission Energy (the "quarterly report");

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

(b)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and

(c)

Disclosed in this quarterly report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:    May 8, 2006 /s/ W. James Scilacci W. James Scilacci
Senior Vice President and Chief
Financial Officer

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CERTIFICATIONS

EX-32

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Exhibit 32

STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350,
AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 (the "Quarterly Report") of Edison Mission Energy (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his knowledge and belief, that:

1.

The Quarterly Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

2.

The information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Theodore F. Craver, Jr. Theodore F. Craver, Jr.
Chief Executive Officer
Edison Mission Energy

/s/ W. James Scilacci W. James Scilacci
Chief Financial Officer
Edison Mission Energy

This statement accompanies the Quarterly Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to Edison Mission Energy and will be retained by Edison Mission Energy and furnished to the Securities and Exchange Commission or its staff upon request.

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STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350, AS ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002