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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 September 30, 2005
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 000-24890

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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o    No 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 November 4, 2005: 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	23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	61
Item 4.	Controls and Procedures	62
PART II – Other Information
Item 1.	Legal Proceedings	63
Item 6.	Exhibits	63
	Signatures	64

PART I – FINANCIAL INFORMATION
ITEM 1.    FINANCIAL STATEMENTS

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

			Three Months Ended September 30,						Nine Months Ended September 30,
			2005			2004			2005			2004
Operating Revenues
	Electric revenues		$	640		$	507		$	1,527		$	1,239
	Net gains (losses) from price risk management and energy trading			31			(4	)		60			(1	)
	Operation and maintenance services			6			6			18			19
		Total operating revenues		677			509			1,605			1,257
Operating Expenses
	Fuel			193			163			492			478
	Plant operations			96			90			346			316
	Plant operating leases			45			44			133			141
	Operation and maintenance services			5			5			17			17
	Depreciation and amortization			31			39			92			112
	Loss on lease termination, asset impairment and other charges			—			35			7			989
	Administrative and general			29			38			99			101
		Total operating expenses		399			414			1,186			2,154
	Operating income (loss)			278			95			419			(897	)
Other Income (Expense)
	Equity in income from unconsolidated affiliates			113			109			196			184
	Impairment loss on equity method investment			(55	)		—			(55	)		—
	Interest and other income			15			—			39			2
	Gain on sale of assets			—			—			—			43
	Loss on early extinguishment of debt			—			—			(4	)		—
	Interest expense			(73	)		(79	)		(222	)		(212	)
		Total other income (expense)		—			30			(46	)		17
	Income (loss) from continuing operations before income taxes and minority interest			278			125			373			(880	)
	Provision (benefit) for income taxes			106			38			129			(342	)
	Minority interest			—			—			—			(1	)
Income (Loss) From Continuing Operations				172			87			244			(539	)
	Income from operations of discontinued subsidiaries, net of tax (Note 6)			27			498			55			570
Net Income			$	199		$	585		$	299		$	31

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

1

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

			Three Months Ended September 30,						Nine Months Ended September 30,
			2005			2004			2005			2004
Net Income			$	199		$	585		$	299		$	31
Other comprehensive income (loss), net of tax:
	Foreign currency translation adjustments:
		Foreign currency translation adjustments, net of income tax expense of $0 for the three months and $1 for the nine months ended September 30, 2004, respectively		—			33			—			26
		Reclassification adjustment for sale of investment in a foreign subsidiary		—			(134	)		—			(134	)
	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 $(122) and $5 for the three months and $(165) and $(46) for the nine months ended September 30, 2005 and 2004, respectively		(167	)		(3	)		(221	)		(53	)
		Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $51 and $(19) for the three months and $56 and $(51) for the nine months ended September 30, 2005 and 2004, respectively		(72	)		27			(80	)		70
Other comprehensive loss				(239	)		(77	)		(301	)		(91	)
Comprehensive Income (Loss)			$	(40	)	$	508		$	(2	)	$	(60	)

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

2

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

			September 30, 2005		December 31, 2004
Assets
Current Assets
	Cash and cash equivalents		$	1,556	$	2,270
	Short-term investments			—		140
	Accounts receivable—trade			273		152
	Accounts receivable—affiliates			7		52
	Inventory			118		107
	Assets under price risk management and energy trading			116		41
	Margin and collateral deposits			726		42
	Prepaid expenses and other			26		88
		Total current assets		2,822		2,892
Investments in Unconsolidated Affiliates				430		454
Property, Plant and Equipment				3,527		3,493
	Less accumulated depreciation and amortization			800		709
		Net property, plant and equipment		2,727		2,784
Other Assets
	Deferred financing costs			42		47
	Long-term assets under price risk management and energy trading			94		90
	Restricted cash			70		155
	Rent payments in excess of levelized rent expense under plant operating leases			392		277
	Other long-term assets			56		18
		Total other assets		654		587
Assets of Discontinued Operations				1		111
Total Assets			$	6,634	$	6,828

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

3

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

			September 30, 2005			December 31, 2004
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	107		$	26
	Accounts payable and accrued liabilities			293			316
	Dividends payable			—			305
	Liabilities under price risk management and energy trading			597			31
	Interest payable			89			55
	Current maturities of long-term obligations			46			211
		Total current liabilities		1,132			944
Long-term obligations net of current maturities				3,309			3,507
Deferred taxes and tax credits				12			198
Long-term liabilities under price risk management and energy trading				88			—
Other long-term liabilities				463			492
Liabilities of discontinued operations				4			5
Total Liabilities				5,008			5,146
Commitments and Contingencies (Note 11)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding			64			64
	Additional paid-in capital			2,197			2,251
	Retained deficit			(351	)		(650	)
	Accumulated other comprehensive income (loss)			(284	)		17
Total Shareholder's Equity				1,626			1,682
Total Liabilities and Shareholder's Equity			$	6,634		$	6,828

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

4

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

			Nine Months Ended September 30,
			2005			2004
Cash Flows From Operating Activities
	Income (loss) from continuing operations, net		$	244		$	(539	)
	Adjustments to reconcile income (loss) to net cash used in operating activities:
		Equity in income from unconsolidated affiliates		(196	)		(184	)
		Distributions from unconsolidated affiliates		153			144
		Depreciation and amortization		97			112
		Minority interest		—			1
		Deferred taxes and tax credits		100			(332	)
		Gain on sale of assets		—			(43	)
		Loss on early extinguishment of debt		4			—
		Impairment charges		62			35
	Changes in operating assets and liabilities:
		Increase in margin and collateral deposits		(684	)		(42	)
		Increase in accounts receivable		(179	)		(208	)
		Decrease (increase) in inventory		(11	)		6
		Decrease in prepaid expenses and other		61			51
		Increase in rent payments in excess of levelized rent expense		(115	)		(59	)
		Increase in accounts payable and accrued liabilities		79			30
		Increase in interest payable		34			52
		Decrease in net assets under risk management		32			10
		Other operating—assets		(1	)		18
		Other operating—liabilities		(4	)		5
		Net cash used in operating activities		(324	)		(943	)
Cash Flows From Financing Activities
	Borrowings on long-term debt and lease swap agreements			165			1,795
	Payments on long-term debt agreements			(528	)		(852	)
	Cash dividends to parent			(360	)		(69	)
	Payments for price appreciation on stock options exercised			(13	)		(4	)
	Financing costs			(5	)		(35	)
		Net cash provided by (used in) financing activities		(741	)		835
Cash Flows From Investing Activities
	Capital expenditures			(41	)		(39	)
	Proceeds from sale of interest in projects			—			118
	Proceeds from sale of discontinued operations			124			739
	Sale of short-term investments, net			140			20
	Decrease in restricted cash			77			56
	Investments in other assets			—			(1	)
		Net cash provided by investing activities		300			893
Effect on cash from discontinued operations activities				50			55
Effect on cash from deconsolidation of subsidiary				—			(32	)
Net increase (decrease) in cash and cash equivalents				(715	)		808
Cash and cash equivalents at beginning of period				2,272			485
Cash and cash equivalents at end of period				1,557			1,293
Cash and cash equivalents classified as part of discontinued operations				(1	)		(137	)
Cash and cash equivalents of continuing operations			$	1,556		$	1,156

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

5

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2005
(Unaudited)

Note 1. General

        In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial position and results of operations for the periods covered by this report. The results of operations for the nine months ended September 30, 2005 are not necessarily indicative of the operating results for the full year.

        Edison Mission Energy (EME's) significant accounting policies are described in Note 2 to its Consolidated Financial Statements as of December 31, 2004 and 2003, included in EME's annual report on Form 10-K for the year ended December 31, 2004. EME follows the same accounting policies for interim reporting purposes. 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, 2004.

Margin and Collateral Deposits

        Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. Deposits with counterparties and brokers generally earn interest that approximates the Federal Funds Rate.

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.

Note 2. Inventory

        Inventory is stated at the lower of weighted average cost or market. Inventory at September 30, 2005 and December 31, 2004 consisted of the following:

	September 30, 2005		December 31, 2004
	(in millions)
Coal and fuel oil	$	75	$	65
Spare parts, materials and supplies		43		42
Total	$	118	$	107

Note 3. Agreement to Sell the Doga Project

        EME owns an 80% interest in a 180 MW gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. EME has entered into a Purchase Agreement, dated as of August 17, 2005, to sell its interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim Isletme ve Ticaret Limited Sirketi, which will acquire an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the Doga

6

project. Completion of the sale is subject to the satisfaction of a number of closing conditions, including obtaining the consent of a majority of the project's lenders. The sale is expected to close in the fourth quarter of 2005.

Note 4. Loss on Lease Termination, Impairment Losses and Other Charges

Impairment Loss on Equity Method Investment

        During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash flows. The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest. The March Point project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil) under a steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements purchased at current market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the third quarter of 2005, long-term natural gas prices increased substantially, thereby adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a $55 million charge during the third quarter of 2005.

Loss on Lease Termination, Asset Impairment and Other Charges

        On April 27, 2004, EME's subsidiary, Midwest Generation, LLC (Midwest Generation) terminated the Collins Station lease through a negotiated transaction with the lease equity investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax) due to termination of the lease and the planned decommissioning of the asset and disposition of excess inventory.

        Following the termination of the Collins Station lease, Midwest Generation announced plans on May 28, 2004 to permanently cease operations at the Collins Station by December 31, 2004 and decommission the plant. In September 2004, EME recorded a pre-tax impairment charge of $5 million resulting from the termination of the power purchase agreement effective September 30, 2004 for the two units at the Collins Station that remained under contract.

        In September 2004, management completed an analysis of future competitiveness in the expanded PJM Interconnection, LLC (PJM) marketplace of its eight remaining small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight small peaking units. As a result of the decision to decommission the units, projected future cash flows associated with the Illinois peaking units were less than the book value of the units, resulting in an impairment under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or the Disposal of Long-Lived Assets." During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million (approximately $18 million after tax).

7

Note 5. Accumulated Other Comprehensive Income (Loss)

        Accumulated other comprehensive income (loss), including discontinued operations, 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, 2004	$	18		$	(1	)	$	17
Current period change		(301	)		—			(301	)
Balance at September 30, 2005	$	(283	)	$	(1	)	$	(284	)

        Unrealized losses on cash flow hedges, net of tax, at September 30, 2005, include unrealized losses on commodity hedges primarily related to 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 these markets are greater than contract prices. The increase in the unrealized losses during the third quarter of 2005 resulted from a combination of new hedges for 2006 and 2007 and an increase in market prices for power driven largely from higher natural gas and oil prices. In addition, at September 30, 2005, EME reclassified a $9 million, after tax, unrealized gain from other comprehensive loss to earnings due to the impairment of its equity investment in the March Point project.

        As EME's hedged positions for continuing operations are realized, approximately $257 million, after tax, of the net unrealized losses on cash flow hedges at September 30, 2005 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.

        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 $32 million and $13 million during the third quarters of 2005 and 2004 and $35 million and $9 million during the nine months ended September 30, 2005 and 2004, 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 6. 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.

8

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.

MEC International B.V.

        On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) pursuant to a Purchase Agreement, dated July 29, 2004, by and between EME and IPM. The purchase agreement was entered into following a competitive bidding process. The sale of MECIBV included the sale of EME's interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV and related assets was $2.0 billion.

Contact Energy

        On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited pursuant to a Purchase Agreement, dated July 20, 2004. The purchase agreement was entered into following a competitive bidding process. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser. EME recorded an after-tax gain on sale of Contact Energy of $141 million during the third quarter of 2004.

Lakeland Project

        EME previously owned and operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the Lakeland project. The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased consolidating the activities of Lakeland Power Ltd. in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement. Accordingly, EME accounts for its ownership of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is distributed from this entity.

        As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination of the power sales agreement. On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings of their own in the United Kingdom (similar to bankruptcy proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received £112 million (approximately $210 million) from the TXU administrators, representing an interim payment of 97% of its accepted claim of £116 million (approximately $217 million).

        From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of £20 million (approximately $37 million) to EME on April 7, 2005 comprised of £7 million (approximately $13 million) for a secured loan which EME purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd., and £13 million (approximately $24 million) as a distribution to the EME subsidiary that owns the equity interest in Lakeland Power Ltd. The distribution was recognized in income during the

9

quarter ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay to EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with Lakeland Power Ltd.'s liquidation.

        EME estimates that the remaining net proceeds after tax (including taxes due in the United States) and net income resulting from the above payments will be approximately $64 million. The majority of the remaining proceeds are expected to be received in 2006, when Lakeland Power Ltd.'s liquidation is expected to be completed. Because the amounts required to settle outstanding claims and UK taxes have not been finalized and cannot be estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net income may vary materially from the above estimate.

Summarized Financial Information for Discontinued Operations

        In accordance with SFAS No. 144, all of the projects discussed above are classified as discontinued operations in the accompanying consolidated statements of income. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. Summarized results of discontinued operations are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions)
Total operating revenues	$	—		$	354		$	—		$	1,102
Income (loss) before income taxes and minority interest		(2	)		59			20			214
Benefit for income taxes		(29	)		(316	)		(30	)		(264	)
Minority interest		—			18			—			49
Income from operations of discontinued foreign subsidiaries		27			357			50			429
Gain on sale before income taxes		—			312			9			312
Gain on sale after income taxes		—			141			5			141

        During the quarter ended September 30, 2005, EME recorded tax adjustments of $28 million which resulted from completion of the 2004 federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004 and are included in "Benefit for income taxes" in the above table. During the quarter ended September 30, 2004, EME recorded a deferred income tax benefit of $327 million in accordance with Emerging Issues Task Force Issue No. 93-17, "Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation," (EITF 93-17). Under EITF 93-17, because the tax basis of the stock of EME's Dutch subsidiary, MECIBV, exceeded EME's book basis, an adjustment to deferred taxes was required during the third quarter of 2004.

        The assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets at September 30, 2005 and December 31, 2004. The carrying amount of

10

major asset and liability classifications for EME's international operations recorded as discontinued operations are as follows:

		September 30, 2005		December 31, 2004
		(in millions)
Cash and cash equivalents		$	1	$	2
Other current assets			—		2
	Total current assets		1		4
Investments in unconsolidated affiliates			—		107
Assets of discontinued operations		$	1	$	111
Accounts payable and accrued liabilities		$	—	$	1
	Total current liabilities		—		1
Deferred revenue			4		4
	Total long-term deferred liabilities		4		4
Liabilities of discontinued operations		$	4	$	5

Note 7. Restructuring Costs

        During the first quarter of 2005, EME initiated a review of its domestic organization to better align its resources with its domestic business requirements. Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional management structure. As a result of these changes, EME recorded charges of approximately $10 million (pre-tax) in the nine months ended September 30, 2005 for severance and related costs. These charges were included in administrative and general expense on EME's consolidated statement of income.

Note 8. Employee Benefit Plans

Pension Plans

        EME previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $12 million to its pension plans in 2005. As of September 30, 2005, $9 million in contributions have been made. EME anticipates meeting its original expectation by year-end 2005.

        Components of pension expense are:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions)
Service cost	$	5		$	4		$	14		$	12
Interest cost		2			2			6			6
Expected return on plan assets		(1	)		(1	)		(4	)		(3	)
Net amortization and deferral		—			—			1			—
Total expense	$	6		$	5		$	17		$	15

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Postretirement Benefits Other Than Pensions

        EME previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $1 million to its postretirement benefits other than pensions in 2005. As of September 30, 2005, $0.5 million in contributions have been made. EME anticipates meeting its original expectation by year-end 2005.

        Components of postretirement benefits other than pensions expense are:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005			2004
	(in millions)
Service cost	$	1	$	—	$	2		$	—
Interest cost		1		1		3			3
Amortization of unrecognized prior service costs		—		—		(1	)		—
Total expense	$	2	$	1	$	4		$	3

Note 9. Refinancing

EME Financing Developments

        On January 25, 2005, EME repaid the junior subordinated debentures and consequently repaid the cumulative monthly income preferred securities (MIPS) of $150 million. The junior subordinated debentures are described more fully in Note 10—Financial Instruments, included in EME's annual report on Form 10-K for the year ended December 31, 2004. In connection with the repayment of the junior subordinated debentures, EME recorded a $4 million loss on early extinguishment of debt during the first quarter of 2005.

Midwest Generation Financing Developments

        On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit facility had provided for a $700 million first priority secured institutional term loan due in 2011 and a $200 million first priority secured revolving credit, working capital facility due in 2009.

        The refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million revolving credit, working capital facility due in 2011. The previously existing $200 million working capital facility remains in place. Midwest Generation drew in full upon the new $300 million working capital facility at closing and used the proceeds to pay down an equivalent portion of the existing term loan. After giving effect to the paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity date of the repriced term loan remains 2011. The new working capital facility, together with the existing working capital facility, shares first lien priority with the repriced term loan. The new working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new working capital facility is 2011; however, the lenders can request to be fully repaid in 2010.

        On the day after the closing of the refinancing transaction, EME contributed $300 million in equity to Midwest Generation, and Midwest Generation used the proceeds of this equity contribution

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to repay the loans outstanding under the new working capital facility. Thus, after completion of the actions outlined herein, Midwest Generation had $343 million outstanding under its term loan and $500 million of working capital facilities available for working capital requirements, including credit support for hedging activities. As of September 30, 2005, approximately $170 million was utilized under these working capital facilities.

        Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributes to the equity contribution equals the amount thereof. Accordingly, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to the equity contribution made by EME in Midwest Generation on April 19, 2005 equals $300 million. However, Midwest Generation is required to make concurrently with each distribution an offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the portion thereof attributed to the equity contribution. Thus, Midwest Generation will not be required to offer to repay debt concurrently with a distribution so long as the portion of each distribution attributed to the April 19, 2005 equity contribution is at least one-third of such distribution.

Note 10. Income Taxes

        EME's income tax provision (benefit) from continuing operations was $129 million and $(342) million during the nine months ended September 30, 2005 and 2004, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes which was recorded as a reduction of income taxes during the second quarter of 2005. During the second quarter of 2004, EME recorded a tax benefit of $368 million primarily relating to the loss on the termination of the Collins Station lease, and during the first quarter of 2004, EME recorded a tax provision of $18 million relating to the sale of 100% of its stock in Edison Mission Energy Oil & Gas, which in turn held interests in Four Star Oil & Gas.

Note 11. Commitments and Contingencies

Contractual Obligations

Long-Term Debt

        EME's long-term debt maturities as of September 30, 2005 are (in millions):

October through December 2005	$	2
2006		47
2007		129
2008		416
2009		610

        These amounts have been updated primarily to reflect financing activities completed during the first nine months of 2005. See Note 9—Refinancing.

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Fuel Supply Contracts

        Midwest Generation and EME Homer City have entered into additional fuel purchase commitments with various third-party suppliers during the first nine months of 2005. These additional commitments are currently estimated to be $22 million for 2005, $114 million for 2006, $169 million for 2007, $44 million for 2008, and $62 million for 2009.

Coal Transportation Agreements

        Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers) which extend through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first nine months of 2005 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $33 million for 2005, $61 million for 2006, $117 million for 2007, $40 million for 2008, and $77 million for 2009.

Capital Improvements

        At September 30, 2005, EME's subsidiaries had firm commitments to spend on capital expenditures of approximately $4 million during the remainder of 2005 and approximately $5 million in 2006.

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, guarantee of debt and indemnifications.

Standby Letters of Credit

        At September 30, 2005, standby letters of credit aggregated $17 million and were scheduled to expire as follows: remainder of 2005—$3 million; 2006—$11 million; and 2007—$3 million.

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 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

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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 between 170 and 190 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at September 30, 2005. Midwest Generation had recorded a $68 million liability at September 30, 2005 related to this matter.

        The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Projecting 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 as specified in the Asset Purchase Agreement dated August 1, 1998. 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.

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

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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. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At September 30, 2005, EME had recorded a liability of $86 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 holds 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 September 30, 2005, EME had recorded a liability of $7 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 contracts. 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 contract. The obligations under the indemnification agreements as of September 30, 2005, if payment were required, would be $134 million. EME has not recorded a liability related to these indemnities.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

        A subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement. 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

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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

Legal Developments Affecting Sunrise Power Company

        Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also alleges a class action. One of the newly added parties removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants filed a responding pleading on May 6, 2005. Following a hearing on September 7, 2005, the court sustained defendants' demurrer regarding preemption and filed rate doctrine. The plaintiff has waived his right to appeal.

Regulatory Developments Affecting Doga Project

        On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement that each generator obtain a generation license. The effect of the regulation is still undetermined, as the new license provisions have not been specified. Doga complied with the new regulation's stipulation to apply for a new generation license by June 2, 2003. The license has not been issued yet.

        If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's cost of performing its obligations under its project documents, this may constitute a "risk event" under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

        On October 3, 2002, Doga (and several other power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of the new regulation on the grounds of the illegality and unconstitutionality of any new license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract. Doga's request for injunctive relief was rejected, and there are no further rights of appeal against that rejection.

        On June 21, 2005, a hearing regarding the merits of the case was held. Following the hearing, the Danistay rendered a decision upholding the contested provisions of the new regulation. Doga has filed

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an appeal with the General Council of the Administrative Chamber of the Danistay. EME cannot currently estimate when a decision on the appeal may be taken. As described more fully in Note 3—Agreement to Sell the Doga Project, EME has entered into a contract to sell its interest in the Doga project.

Income Taxes

        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.

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 in the United States and foreign regulatory authorities with jurisdiction over projects located outside the United States. 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 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 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. There can be no assurance the existence or extent of all contamination at EME's sites has been fully identified, or that activities at the Illinois Plants or any other facilities identified in

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the future may not result in additional environmental claims being asserted against EME and its subsidiaries or additional investigations or remedial actions being required. See "Note 15. 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, 2004 for a more complete discussion of EME's environmental contingencies.

Note 12. Supplemental Statements of Cash Flows Information

		Nine Months Ended September 30,
		2005			2004
		(in millions)
Cash paid
	Interest (net of amount capitalized)	$	180		$	190
	Income taxes (receipts)		(41	)		44
	Cash payments under plant operating leases		247			213
Non-cash activities from deconsolidation of variable interest entities
	Assets	$	—		$	133
	Liabilities		—			165

Note 13. Stock-based Compensation

        Edison International has three stock-based employee compensation plans, which are described more fully in Note 14—Stock Compensation Plans, included in EME's annual report on Form 10-K for the year ended December 31, 2004. EME accounts for those plans using the intrinsic value method. Upon grant, no stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income if EME had used the fair value accounting method.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions)
Net income, as reported	$	199		$	585		$	299		$	31
Add: stock-based compensation expense included in reported net income, net of related tax effects		5			1			12			4
Deduct: Total stock-based employee compensation expense determined under fair value based method, net of related tax effects		(5	)		(2	)		(13	)		(6	)
Pro forma net income	$	199		$	584		$	298		$	29

        See "Statement of Financial Accounting Standards No. 123(R)" included in Note 14 below for further discussion.

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Note 14. New Accounting Pronouncements

Statement of Financial Accounting Standards Interpretation No. 46(R)

        In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable interest entities. Under this Interpretation, 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. This Interpretation applies to variable interest entities created after January 31, 2003, and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003. This Interpretation became effective for special purpose entities as of December 31, 2003 and for all other entities as of March 31, 2004.

Deconsolidation of Variable Interest Entities

        In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga and Kwinana projects and, accordingly, deconsolidated these projects as of March 31, 2004. The Kwinana project was sold on December 16, 2004 as part of the sale of international operations to IPM and, accordingly, is included in discontinued operations. As described more fully in Note 3—Agreement to Sell the Doga Project, EME has entered into a contract to sell its interest in the Doga project.

Variable Interest Entities

        EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it had variable interests in variable interest entities as defined in this interpretation. The following table summarizes the variable interest entities held by continuing operations in which EME has a significant variable interest:

Variable Interest Entity	Location	Investment at September 30, 2005		Ownership Interest at September 30, 2005		Description
		(in millions)
Sunrise	Fellows, CA	$	122	50	%	Gas-fired facility
Watson	Carson, CA		98	49	%	Cogeneration facility
Sycamore	Bakersfield, CA		61	50	%	Cogeneration facility
Midway-Sunset	Fellows, CA		54	50	%	Cogeneration facility
Kern River	Bakersfield, CA		39	50	%	Cogeneration facility

        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.

FASB Staff Position FIN 46(R)-5

        In March 2005, the FASB issued Staff Position FIN 46(R)-5, "Implicit Variable Interests Under FIN 46" (FIN 46(R)-5). FIN 46(R)-5 states that a reporting entity should consider whether it holds an implicit variable interest in a variable interest entity or in a potential variable interest entity. If the aggregate of the explicit and implicit variable interests held by the reporting entity and its related

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parties would, if held by a single party, identify that party as the primary beneficiary, the party within the group most closely associated with the variable interest entity should be deemed the primary beneficiary. The guidance of FIN 46(R)-5 is effective for reporting periods beginning after March 3, 2005. FIN 46(R)-5 did not affect EME's accounting for variable interest entities.

Statement of Financial Accounting Standards No. 123(R) and Staff Accounting Bulletin No. 107

        In December 2004, the FASB reissued SFAS No. 123(R), "Share-Based Payment." This is a revision of SFAS No. 123, "Accounting for Stock-Based Compensation," and supersedes APB No. 25, "Accounting for Stock Issued to Employees." SFAS No. 123(R) establishes accounting standards for transactions in which an entity receives employee services in exchange for (a) equity instruments of the entity or (b) liabilities that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of equity instruments. The standard will require EME to recognize the grant-date fair value of Edison International stock options and equity based compensation issued to employees in the statement of income. The standard also requires that such transactions be accounted for using the fair value based method, thereby eliminating use of the intrinsic value method of accounting in APB No. 25, which was permitted under Statement 123, as originally issued. EME currently uses the intrinsic value accounting method for stock-based compensation. On April 14, 2005, the Securities and Exchange Commission (SEC) announced a delay in the effective date for the standard to fiscal years beginning after June 15, 2005. EME will implement the new standard effective January 1, 2006 by applying the modified prospective transition method. The difference in expense between the two accounting methods related to stock options granted is shown in Note 13—Stock-Based Compensation above. EME is assessing the impact of this accounting standard on its performance shares.

        In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107), which conveys the SEC staff's views on the interaction between SFAS No. 123(R) and certain SEC rules and regulations. SAB 107 also provides the SEC staff's views regarding the valuation of share-based payment arrangements for public companies. EME will apply the principles of SAB 107 in conjunction with its adoption of SFAS No. 123(R).

FASB Staff Position FAS 109-1

        In December 2004, the FASB issued FASB Staff Position FAS 109-1, "Application of FASB Statement No. 109, "Accounting for Income Taxes,' to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004." The primary objective of this Position is to provide guidance on the application of SFAS No. 109 to the provision within the American Jobs Creation Act of 2004 that provides a tax deduction on qualified production activities under the provisions of Internal Code Section 199 effective for tax years beginning after December 31, 2004. Under FAS 109-1, recognition of the tax deduction on qualified production activities, which include the production of electricity, is ordinarily reported in the year it is earned. The deduction is calculated, and the limitations to the deduction are applied at the consolidated income tax reporting level by the parent of the affiliated group (Edison International). The benefit of the deduction is then allocated among the members of the group in proportion to each member's respective amount, if any, of income from qualified production activities. EME will apply FAS 109-1 in computing income taxes as tax deductions related to qualified production activities are earned.

Statement of Financial Accounting Standard Interpretation No. 47

        In March 2005, the FASB issued Financial Accounting Standard Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47 clarifies that an entity is required to

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recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated even though uncertainty exists about the timing and (or) method of settlement. EME is required to adopt FIN 47 by the end of 2005. EME is currently assessing the impact of FIN 47 on its results of operations and financial condition.

Statement of Financial Accounting Standards No. 153

        In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions." SFAS No. 153 amends and clarifies that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, SFAS No. 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Beginning in the third quarter of 2005, SFAS No. 153 is applicable to nonmonetary asset exchanges. The adoption of this standard had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 154

        In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections" (SFAS No. 154), which replaces APB Opinion No. 20, "Accounting Changes," and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements." SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle, and applies to all voluntary changes in accounting principles, as well as changes required by an accounting pronouncement in the unusual instance it does not include specific transition provisions. Specifically, SFAS No. 154 requires retrospective application to prior periods' financial statements, unless it is impracticable to determine the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the effects of the change, the new accounting principle must be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and a corresponding adjustment must be made to the opening balance of retained earnings for that period. When it is impracticable to determine the cumulative effect of the change, the new principle must be applied as if it were adopted prospectively from the earliest date practicable. SFAS No. 154 is effective for all accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. This standard does not change the transition provisions of any existing pronouncements. EME does not expect the adoption of this standard will have a material impact on its consolidated financial statements.

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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 Edison Mission Energy's (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 report and elsewhere, 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:

•

the ability of EME to declare and pay dividends;

•

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 costs;

•

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, including new plants and technologies that may be developed in the future;

•

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

•

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.

Certain of the risk factors listed above are discussed in more detail in "Market Risk Exposures" below, and under "Risks Related to the Business" in the MD&A included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2004. Additional information about the risk factors listed above and other risks and uncertainties is contained throughout this MD&A. Readers are urged to read this entire quarterly report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect EME's business. The information contained in this report is subject to change without notice. Forward-looking statements speak only as of the date they are made and

23

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.

The MD&A of this Form 10-Q discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2004, and as compared to the third quarter and nine months ended September 30, 2004. 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, 2004.

        The MD&A presents a discussion of EME's financial results and analysis of its financial condition. It is presented in four major sections:

	Page
Management's Overview; Critical Accounting Estimates	24
Results of Operations	29
Liquidity and Capital Resources	42
Market Risk Exposures	51

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING ESTIMATES

Management's Overview

EME Restructuring Activities

        During 2004, EME sold most of its international operations. EME's international operations, except for the Doga project, are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. In the first quarter of 2005, EME completed the sale of two international projects:

•

EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to CBK Projects B.V., the purchasing entity designated by its partner, for $104 million.



•

EME sold its 25% equity interest in the Tri Energy project to IPM for approximately $20 million.

        EME entered into a purchase agreement, dated as of August 17, 2005, to sell its 80% interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim Isletme ve Ticaret Limited Sirketi, which will acquire an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the Doga project. Completion of the sale is subject to the satisfaction of a number of closing conditions, including obtaining the consent of a majority of the project's lenders. The sale is expected to close in the fourth quarter of 2005.

        In connection with the sale of its international operations in 2004, together with cash on hand, in January 2005, EME:

•

made distributions to Mission Energy Holding Company (MEHC) totaling $360 million, which were subsequently used primarily to repay the remaining $285 million portion of MEHC's term loan.

24

•

repaid its junior subordinated debentures and, consequently, repaid the monthly income preferred securities (MIPS) totaling $150 million.

        In April 2005, EME made an equity contribution of $300 million to Midwest Generation, which used the proceeds to repay indebtedness. See "Liquidity and Capital Resources—Midwest Generation Financing" for a discussion of the Midwest Generation financing.

        EME has also completed a review of its domestic organization to better align its resources with its domestic business requirements. Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional management structure. As a result of these changes, EME recorded charges of approximately $10 million (pre-tax) in the nine months ended September 30, 2005 for severance and related costs.

Business Development Plans

        Following the completion of restructuring activities described above, EME, together with its affiliate, Edison Capital, has established a joint business development effort for wind projects in addition to EME's development plans for thermal projects.

Wind Business Development

        EME's affiliate, Edison Capital, has an existing 196 MW portfolio of wind projects located in Iowa and Minnesota. In addition, a subsidiary of Edison Capital has entered into an agreement to acquire a 120 MW wind project in eastern New Mexico from a wind generation developer for $157 million. The acquisition of this project is subject to achieving commercial operations and other closing conditions, which are expected to be met in December 2005. EME and Edison Capital are considering transferring some or all of these projects to EME as part of EME's independent power generation portfolio and expanding significantly, through EME, further investments in wind projects throughout the U.S. In addition, EME is considering entering into agreements to purchase wind turbines to support these wind business development activities. Pursuit of new renewable energy investments depends upon economic and regulatory conditions and may be affected by government policies supporting renewable energy. In August 2005, federal incentives for new wind projects, referred to as production tax credits, were extended for new wind projects installed by December 31, 2007 under a comprehensive federal energy bill, named the "Energy Policy Act of 2005."

Thermal Business Development

        EME continues to review opportunities to develop or acquire additions to its power generation portfolio. As part of this activity, EME has begun the process of obtaining permits for two sites in Southern California for peaker plants and has responded to several requests for proposals to build or acquire generation. Pursuit of new thermal projects in California and elsewhere depends on a range of factors outside the control of EME, and, accordingly, there is no assurance that these efforts will result in the actual development or acquisition of additional generation capacity.

Expiration of the Exelon Power Purchase Agreements

        The five-year power purchase agreements between Midwest Generation and Exelon Generation Company expired on December 31, 2004 and, accordingly, beginning January 1, 2005, all the output from the Illinois Plants is considered merchant generation. In 2004, approximately 53% of the energy and capacity sales from the Illinois Plants were to Exelon Generation under the power purchase agreements.

25

        The Exelon Generation power purchase agreement for coal-fired units was structured to provide significant capacity payments and lower energy payments which were primarily designed to reimburse the cost of production. The agreement also provided for substantial capacity payments during the summer months. The Illinois Plants continue to derive revenue from sales of capacity and energy. In the current wholesale energy market, energy prices are substantially higher than the energy prices previously set forth in the agreement, but capacity payments are, and are expected to remain for some time, substantially lower. As a result, the composition of EME's revenues was significantly different in the first nine months of 2005 compared to 2004. EME's merchant generation is subject to significant volatility as described further in "Market Risk Exposures—Commodity Price Risk."

Wholesale Energy Prices in Illinois

        Wholesale energy prices at the Northern Illinois Hub (related to the Illinois Plants) have increased substantially in 2005 from the comparable market prices in 2004 driven largely by increases in the market price of natural gas and oil. The average market price during the nine months ended September 30, 2005 at the Northern Illinois Hub (related to the Illinois Plants) increased to $44.26 per MWh, compared to the average market prices "Into ComEd" and at the Northern Illinois Hub of $29.36 per MWh during the nine months ended September 30, 2004.

Energy Trading Activities

        EME seeks to generate profit by utilizing the commercial platform of its subsidiary, Edison Mission Marketing & Trading, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. Edison Mission Marketing & Trading 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 $84 million and $125 million for the third quarter and nine months ended September 30, 2005, respectively. Volatile market conditions during the first nine months of 2005, driven by increased prices for natural gas and oil and warmer summer temperatures, have created favorable conditions for Edison Mission Marketing & Trading's trading strategies in 2005 compared to 2004. This trading activity is limited by the risk management policies of EME, including a limit on value at risk. During the first nine months of 2005, the maximum value at risk associated with trading of over-the-counter products and exchange-traded products was $1.9 million, using a 95% confidence interval and assuming a one-day holding period. As of September 30, 2005, the collateral required to support Edison Mission Marketing & Trading's transactions was approximately $90 million. EME's management pays particular attention to the risk management of these activities, because income from them will vary substantially from period to period depending on market conditions.

Overview of EME's 2005 Financial Performance from Continuing Operations

        EME's financial performance in the third quarter and nine months ended September 30, 2005 improved over the third quarter and nine months ended September 30, 2004 with a number of important items affecting performance:

•

An increase in earnings from the Illinois Plants primarily attributable to:



•

An increase in the average energy price of merchant generation related to the coal-fired units to $53.85 per MWh and $45.12 per MWh during the third quarter and nine months ended September 30, 2005, respectively, from $32.96 per MWh and $30.98 per MWh during the third quarter and nine months ended September 30, 2004, respectively. During the third quarter and nine months ended September 30, 2004, 53% and 56% of generation from the

26

Illinois Plants was merchant, respectively. The remaining 2004 generation was sold under the power purchase agreements with Exelon Generation which provided for higher capacity payments and lower payments for energy (with an average energy price of $17.18/MWh for the nine months ended September 30, 2004).

•

Generation during the third quarter and nine months ended September 30, 2005 was 8,137 GWh and 22,366 GWh, respectively, compared to 8,300 GWh and 22,178 GWh during the third quarter and nine months ended September 30, 2004, respectively. In 2004, a portion of Midwest Generation's power was sold under the power purchase agreement for coal-fired units with Exelon Generation. The unplanned outage rate at Midwest Generation was higher than last year due to higher planned maintenance, operational difficulties in returning Midwest Generation's Will County Units 1 and 2 to service this year, higher incidents of boiler outages and de-rating at the Joliet Station due to temperature limits at the nearby river used for cooling water discharge.



•

The second quarter of 2004 included a $954 million (pre-tax) loss on termination of the lease related to the Collins Station and the return of its ownership to EME and related inventory reserves. Management concluded that the Collins Station was not economically competitive in the marketplace given the generation overcapacity in the region and ceased operations effective September 30, 2004. EME recorded a $7 million (pre-tax) loss in the third quarter of 2004 related to the impairment of the Collins Station plant assets and related inventory reserves.



•

The third quarter of 2004 included a charge of $29 million (pre-tax) related to impairment of six small peaking units in Illinois. In September 2004, management completed an analysis of future competitiveness in the expanded PJM Interconnection, LLC (PJM) marketplace of its eight small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight units. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less than the book value of the units resulting in an impairment.



•

An increase in earnings from the Homer City facilities primarily attributable to:



•

An increase in the average energy price of merchant generation to $45.45 per MWh and $44.17 per MWh in the third quarter and nine months ended September 30, 2005, respectively, from $35.99 per MWh and $36.36 per MWh during the third quarter and nine months ended September 30, 2004, respectively.



•

An increase in generation to 4,060 GWh and 10,697 GWh during the third quarter and nine months ended September 30, 2005, respectively, compared to 3,562 GWh and 9,937 GWh during the third quarter and nine months ended September 30, 2004, respectively. During the third quarter of 2004, temporary fuel supply interruptions were managed through a reduction of off-peak generation and spot purchases of higher priced coal.

        Partially offset by:

•

An increase in coal costs driven by an increase in Northern Appalachia coal prices which has been attributed to greater demand from domestic power producers and increased international shipments of coal to Asia. See "Market Risk Exposures—Commodity Price Risk—Coal Price and Transportation Risk," and "Liquidity and Capital Resources—Contractual Obligations—Fuel Supply Dispute."



•

An increase in the cost of sulfur dioxide (SO2) emission allowances which has been attributed to reduced numbers of both allowance sellers and prior vintage allowances.

27

•

During the third quarter of 2005, EME recorded a $55 million charge to fully impair its equity investment in the March Point project due to the adverse impact on cash flows from increases in long-term natural gas prices. For further discussion, see "Impairment Loss on Equity Method Investment" in "Results of Continuing Operations—Earnings from Unconsolidated Affiliates."



•

The 2004 results included a pre-tax gain of $47 million from the sale of the company owning EME's interests in Four Star Oil & Gas Company, partially offset by a $4 million loss on the sale of the company holding EME's interest in the Brooklyn Navy Yard project recorded during the first quarter of 2004.



•

During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes which were recorded as a reduction of income taxes during the second quarter of 2005.

Critical Accounting Estimates

        For a discussion of EME's critical accounting estimates, refer to "Critical Accounting Estimates" on page 38 of EME's annual report on Form 10-K for the year ended December 31, 2004.

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RESULTS OF OPERATIONS

Introduction

        This section discusses operating results for the third quarters and nine months of 2005 and 2004. Continuing operations include EME's Illinois Plants and Homer City facilities, energy trading, 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. It is organized under the following headings:

	Page
Net Income Summary	29
Results of Continuing Operations	30
Results of Discontinued Operations	40
New Accounting Pronouncements	41
Proposed Accounting Pronouncements	41

Net Income Summary

        Net income is comprised of the following components:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(in millions)
Income (loss) from continuing operations	$	172	$	87	$	244	$	(539	)
Income from discontinued operations		27		498		55		570
Net income	$	199	$	585	$	299	$	31

29

        EME's income (loss) from continuing operations for the third quarters and nine months ended September 30, 2005 and 2004 is comprised of:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(in millions)
Income (loss) from Continuing Operations		$	172		$	87		$	244		$	(539	)
Discrete Items (after tax)
	Loss on lease termination, asset impairment and other charges (see "—Results of Continuing Operations—Earnings from Consolidated Operations—Illinois Plants")		—			(22	)		—			(608	)
	Impairment loss on equity method investment (see "—Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Impairment Loss on Equity Method Investment")		(34	)		—			(34	)		—
	Gain on sale of assets (see "—Results of Continuing Operations—Gain on Sale of Assets")		—			—			—			29
	Other		—			—			—			(2	)
Income from Continuing Operations (excluding discrete items)		$	206		$	109		$	278		$	42

        The increase in the third quarter income from continuing operations, excluding discrete items, was primarily attributable to higher energy trading income and higher wholesale energy prices at the Illinois Plants and Homer City facilities. The year-to-date increase in income from continuing operations, excluding discrete items, was primarily due to higher wholesale energy prices at the Illinois Plants and Homer City facilities, higher energy trading income and resolution of a tax dispute.

Results of Continuing Operations

Overview

        EME operates in one line of business, electric power generation. Operating revenues are primarily derived from the sale of power generated from the Illinois Plants and 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.

30

        The following section provides a summary of the operating results for the third quarters and nine months ended September 30, 2005 and 2004 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Three Months Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(in millions)
Income (Loss) before Taxes and Minority Interest (Earnings/Losses)(1)
	Consolidated operations
	Illinois Plants	$	187		$	98		$	297		$	(850	)
	Homer City		33			26			83			61
	Energy Trading(2)		84			4			125			6
	Doga		—			—			—			6
	Other		(2	)		—			(4	)		(1	)
	Unconsolidated affiliates
	Big 4 projects		73			72			134			122
	Sunrise		29			28			31			29
	March Point		5			(1	)		9			6
	Impairment loss on equity method investment		(55	)		—			(55	)		—
	Doga		(2	)		2			3			3
	Other		5			5			10			9
			357			234			633			(609	)
	Corporate interest expense		(67	)		(69	)		(203	)		(210	)
	Corporate and regional administrative and general		(26	)		(37	)		(85	)		(101	)
	Gain on sale of assets		—			—			—			43
	Loss on early extinguishment of debt		—			—			(4	)		—
	Corporate interest income and other, net		14			(3	)		32			(3	)
	Income (Loss) from Continuing Operations Before Income Taxes and Minority Interest	$	278		$	125		$	373		$	(880	)

(1)

Income before taxes of Doga represents both EME's 80% ownership interest and the ownership interests of minority interest holders on a calendar year basis. The interests of minority shareholders in the after-tax earnings of Doga are reflected in a separate line item in the consolidated statements of income.

(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 regional administrative and general expenses.

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Earnings from Consolidated Operations

Illinois Plants

			Three Months Ended September 30,						Nine Months Ended September 30,
			2005			2004			2005			2004
			(in millions)
Operating Revenues
	Energy revenues		$	438		$	195		$	1,009		$	549
	Capacity revenues			10			171			24			267
	Other revenues			3			5			6			9
	Net losses from price risk management			(33	)		(3	)		(44	)		—
	Total operating revenues			418			368			995			825
Operating Expenses
	Fuel			107			102			279			302
	Plant operations			75			75			266			244
	Plant operating leases			19			19			56			66
	Depreciation and amortization			25			33			75			90
	Loss on lease termination, asset impairment and other charges			—			35			7			989
	Administrative and general			1			2			10			—
	Total operating expenses			227			266			693			1,691
Operating Income (Loss)				191			102			302			(866	)
Other Income (Expense)
	Interest income from note receivable from EME			28			28			85			85
	Interest expense and other			(32	)		(32	)		(90	)		(69	)
	Total other income (expense)			(4	)		(4	)		(5	)		16
Income (Loss) Before Taxes			$	187		$	98		$	297		$	(850	)
Statistics – Coal-Fired Generation(1)
	Generation (in GWh):
		Merchant		8,137			4,408			22,366			12,417
		Power purchase agreement		—			3,892			—			9,761
		Total coal-fired generation		8,137			8,300			22,366			22,178
	Equivalent availability(2)			87.9%			91.9%			76.8%			81.8%
	Forced outage rate(3)			9.4%			5.0%			9.0%			6.5%
	Average energy price/MWh:
		Merchant	$	53.85		$	32.96		$	45.12		$	30.98
		Power purchase agreement	$	—		$	16.56		$	—		$	17.18
		Total coal-fired generation(4)	$	53.85		$	25.27		$	45.12		$	24.90

(1)

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

(2)

The availability factor is determined by 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.

(3)

Midwest Generation refers to unplanned maintenance as a forced outage.

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(4)

The average energy price in prior year periods represents an average, weighted by generation, of energy prices earned by the merchant coal plants and energy prices earned under the power purchase agreements with Exelon Generation. Due to the structure of the power purchase agreements with Exelon Generation (with higher capacity prices and lower energy prices), the composite data in 2004 is not directly comparable to 2005 merchant energy prices.

        Earnings (losses) from the Illinois Plants were $187 million and $297 million during the three and nine months ended September 30, 2005, respectively, compared to $98 million and $(850) million for the comparable periods in the prior year. Discrete items affecting the income (loss) of the Illinois Plants include:

•

$954 million loss recorded during the second quarter of 2004 and $7 million loss recorded during the third quarter of 2004 related to the loss on the termination of the Collins Station lease, asset impairment, and related inventory reserves. Management concluded that the Collins Station was not economically competitive in the marketplace given generation overcapacity and ceased operations effective September 30, 2004.



•

$29 million loss recorded during the third quarter of 2004 related to the impairment of six of the eight small peaking units in Illinois. In September 2004, management completed an analysis of future competitiveness of its eight small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight units. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less than the book value of the units, resulting in an impairment charge under SFAS No. 144.

        Earnings from the Illinois Plants, excluding the above discrete items, were $133 million and $139 million during the three and nine months ended September 30, 2004, respectively, compared to $187 million and $297 million for the three and nine months ended September 30, 2005, respectively. The increase in the third quarter of 2005 earnings of $54 million was primarily attributable to higher energy revenues resulting from increased average energy prices. Earnings for the nine-month period ended September 30, 2005 increased $158 million due to the following factors:

•

substantially higher energy revenues resulting from increased average energy prices;



•

lower fuel costs attributable to the cessation of operations at the Collins Station effective September 30, 2004; and



•

lower plant operating lease costs due to the termination of the Collins Station lease in April 2004.

        Partially offset by:

•

lower capacity revenues resulting from the expiration of the power purchase agreements with Exelon Generation;



•

higher plant operation costs due to higher planned maintenance;



•

higher coal costs attributable to increased generation and higher coal prices primarily due to price escalation under coal and transportation agreements;



•

higher interest expense primarily attributable to higher interest rates on the fixed rate debt issued in April 2004; and



•

asset impairment charge of $7 million recorded during the second quarter of 2005 primarily associated with re-scoping a capital program related to coal dust mitigation.

        Losses from price risk management activities increased $30 million and $44 million for the third quarter and nine months ended September 30, 2005, respectively, compared to the corresponding periods of 2004. The 2005 increases were primarily due to significantly greater losses in 2005 on

33

futures, swaps and power contracts compared to gains on power contracts recorded during the third quarter of 2004. These price risk management contracts were entered into to hedge the price risk related to projected sales of power through 2007 (sometimes referred to as economic hedges). However, as such contracts did not qualify for hedge accounting under SFAS No. 133, these positions are accounted for at fair value with changes in fair value recorded through earnings. Losses on these contracts are a result of increased power prices. While these positions reflect a current loss, the market price of power has increased, which will result in higher revenue recorded in future periods if power prices do not change. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

        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. Midwest Generation recorded net losses of approximately $0.5 million and $5 million for the third quarters of 2005 and 2004, respectively, and $0.2 million for both the nine months ended September 30, 2005 and 2004, representing the amount of cash flow hedges' ineffectiveness. The ineffective portion of the cash flow hedges was primarily attributable to changes in the difference between energy prices at the delivery points set forth in the hedge contracts and the energy prices at the delivery points where power generated by the Illinois Plants is delivered into the transmission system. In addition, Midwest Generation recognized losses in 2004 on the ineffective portion of forward contracts that expired during the period.

        The earnings (losses) of the Illinois Plants included interest income of $28 million for both the third quarters of 2005 and 2004 and $85 million for both the nine months ended September 30, 2005 and 2004, 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 by EME for accounting purposes.

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Homer City

		Three Months Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(in millions)
Operating Revenues
	Energy revenues	$	185		$	130		$	473		$	363
	Capacity revenues		5			6			14			22
	Net losses from price risk management		(22	)		(6	)		(26	)		(13	)
	Total operating revenues		168			130			461			372
Operating Expenses
	Fuel		84			60			208			155
	Plant operations		21			14			80			69
	Plant operating leases		25			25			76			76
	Depreciation and amortization		4			4			12			12
	Administrative and general		3			1			7			1
	Total operating expenses		137			104			383			313
Operating Income			31			26			78			59
Other Income (Expense)
	Interest and other income		2			1			6			3
	Interest expense		—			(1	)		(1	)		(1	)
	Total other income (expense)		2			—			5			2
Income Before Taxes		$	33		$	26		$	83		$	61
Statistics
	Generation (in GWh)		4,060			3,562			10,697			9,937
	Equivalent availability(1)		98.7%			91.7%			88.0%			82.9%
	Forced outage rate(2)		0.2%			1.4%			3.6%			5.6%
	Average energy price/MWh	$	45.45		$	35.99		$	44.17		$	36.36

(1)

The availability factor is determined by 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.

(2)

Homer City refers to unplanned maintenance as a forced outage.

        Earnings from Homer City increased $7 million and $22 million for the third quarter and nine months ended September 30, 2005, respectively, compared to the corresponding periods of 2004. The 2005 increases were primarily attributable to higher energy revenues in 2005 due to increased generation and higher average energy prices as compared to 2004. During the first quarter of 2004, an unplanned outage at Unit 1 contributed to lower generation and higher maintenance costs. During the third quarter of 2004, coal deliveries under contracts with four fuel suppliers to Homer City were temporarily interrupted. As a result of these interruptions, Homer City reduced generation during off-peak periods when power prices were lower and purchased coal from alternative suppliers at spot prices, which were substantially higher than the contract prices from these four fuel suppliers. Partially offsetting this increase were higher fuel costs attributable to higher fuel consumption, higher coal prices and higher priced SO2 emission allowances. Included in fuel costs was $22 million and $10 million during the third quarters of 2005 and 2004, respectively, and $51 million and $24 million during the nine months ended September 30, 2005 and 2004, respectively, related to the net cost of emission

35

allowances. See "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for more information regarding the price of SO2 allowances.

        The average energy price earned by Homer City during the third quarter and nine months ended September 30, 2005 was $45.45/MWh and $44.17/MWh compared to the average real-time market price at the Homer City busbar for the same periods of $62.56/MWh and $50.54/MWh. Homer City's average energy price was lower than the average real-time market price due to: (1) hedge contracts having been entered into in prior periods when market prices were lower, and (2) the differential in market prices at the PJM West Hub versus the Homer City busbar having increased (referred to as a widening of the basis between these PJM locations). Homer City hedges its energy price risk at PJM West Hub and retains the risk that the basis between PJM West Hub and Homer City widens. See "Market Risk Exposures—Commodity Price Risk—Basis Risk."

        Losses from price risk management activities increased $16 million and $13 million for the third quarter and nine months ended September 30, 2005, respectively, compared to the corresponding periods of 2004. The 2005 increases were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. Homer City recorded net losses of approximately $32 million and $9 million during the third quarters of 2005 and 2004, respectively, and $35 million and $9 million during the nine months ended September 30, 2005 and 2004, respectively, representing the amount of cash flow hedges' ineffectiveness. The ineffective losses from Homer City were primarily attributable to an increase in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the Homer City busbar). In addition, Homer City recognized ineffective gains (losses) related to forward contracts that expired during the respective periods. Partially offsetting the ineffective losses were gains in 2005 primarily related to futures contracts that did not qualify for hedge accounting under SFAS No. 133. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

Seasonal Disclosure

        Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Illinois Plants and the Homer City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power (driven in part from higher natural gas and oil prices), this historical trend may not be applicable to quarterly revenue in the future.

Energy Trading

        EME seeks to generate profit by utilizing the commercial platform of its subsidiary, Edison Mission Marketing & Trading, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. Edison Mission Marketing & Trading 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 $84 million and $125 million for the third quarter and nine months ended September 30, 2005, respectively. Volatile market conditions during the first nine months of 2005, driven by increased prices for natural gas and oil and warmer summer temperatures, have created favorable conditions for Edison Mission Marketing & Trading's trading strategies in 2005 compared to 2004.

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Earnings from Unconsolidated Affiliates

Big 4 Projects

        Earnings from the Big 4 projects increased $1 million and $12 million for the third quarter and nine months ended September 30, 2005, compared to the corresponding periods of 2004. The 2005 increases in earnings were primarily due to higher energy prices in 2005 compared to 2004. The impact of the higher energy prices in 2005 was partially offset by lower earnings from the Kern River project during the third quarter and nine months ended September 30, 2005, compared to the corresponding periods of 2004 resulting from the expiration of the project's long-term power purchase and steam supply agreements in August 2005. See "Expiration of Power Purchase Agreement and Steam Supply Agreement" below for more information.

        The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $2 million and $3 million for the third quarters of 2005 and 2004, respectively. For the nine months ended September 30, 2005 and 2004, earnings included interest expense from Edison Mission Energy Funding of $7 million and $10 million, respectively.

Expiration of Power Purchase Agreement and Steam Supply Agreement—

        EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Kern River project. The Kern River project's long-term power purchase agreement with Southern California Edison Company (SCE) and its steam supply agreement with Texaco Exploration and Production Inc. (TEPI) both expired on August 9, 2005.

        Kern River Cogeneration entered into a Reformed Standard Offer No. 1 As-Available Energy and Capacity Power Purchase Agreement (RSO#1) with SCE, effective August 10, 2005. As of September 30, 2005, Kern River Cogeneration was negotiating a bilateral agreement with SCE which is expected to be completed in late 2005, subject to California Public Utilities Commission approval. Kern River Cogeneration also entered into a new Steam Purchase and Sale Agreement with Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc., effective August 10, 2005. Due to lower volumes and pricing, revenues under the new agreements are expected to be lower than revenues under the expired agreements.

Sunrise

        Earnings from the Sunrise project increased $1 million and $2 million for the third quarter and nine months ended September 30, 2005, compared to the corresponding periods of 2004. The 2005 increases primarily resulted from higher energy revenues attributable to increased dispatch.

March Point

        Earnings from March Point increased $6 million and $3 million for the third quarter and nine months ended September 30, 2005, respectively, compared to the corresponding periods of 2004. The 2005 increases in earnings were primarily due to mark-to-market gains on fuel contracts entered into by March Point, which are derivatives that do not qualify as cash flow hedges under SFAS No. 133.

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Impairment Loss on Equity Method Investment

        During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash flows. The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest. The March Point project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil) under a steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements purchased at current market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the third quarter of 2005, long-term natural gas prices increased substantially, thereby adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a $55 million charge during the third quarter of 2005.

Doga

        In accordance with Statement of Financial Accounting Standards Interpretation No. 46(R), "Consolidation of Variable Interest Entities," EME determined that it was not the primary beneficiary of the Doga project and, accordingly, deconsolidated this project as of March 31, 2004. Revenues included in EME's consolidated statements of income from the Doga project were $29 million for the nine months ended September 30, 2004, representing revenues from the first quarter of 2004. Earnings from the Doga project were $6 million for the nine months ended September 30, 2004, representing earnings from the first quarter of 2004. Beginning April 1, 2004, EME recorded its interest in the Doga project on the equity method basis of accounting. Earnings (losses) from the Doga project were $(2) million and $3 million for the third quarter and nine months ended September 30, 2005, respectively, compared to $2 million and $3 million for the third quarter and nine months ended September 30, 2004, respectively.

        On August 17, 2005, EME entered into a purchase agreement to sell its 80% interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim Isletme ve Ticaret Limited Sirketi, which will acquire an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the Doga project. Completion of the sale is subject to the satisfaction of a number of closing conditions, including obtaining the consent of a majority of the project's lenders. The sale is expected to close in the fourth quarter of 2005.

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.

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Corporate Interest Expense

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(in millions)
Interest expense to third parties	$	39	$	41	$	118	$	125
Interest expense to Midwest Generation		28		28		85		85
Total corporate interest expense	$	67	$	69	$	203	$	210

Corporate and Regional Administrative and General Expenses

        Administrative and general expenses decreased $11 million and $16 million for the third quarter and nine months ended September 30, 2005, respectively, compared to the corresponding periods of 2004. The decreases were primarily due to decreased use of third-party consultants. Partially offsetting the year-to-date decrease was higher costs incurred in 2005 to implement EME's restructuring plan described under "Management's Overview."

Gain on Sale of Assets

        Gain on sale of assets in 2004 consisted of a $47 million gain related to the sale of 100% of EME's stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, and a $4 million loss related to the sale of EME's interest in Brooklyn Navy Yard Cogeneration Partners, L.P. recorded during the first quarter of 2004.

Loss on Early Extinguishment of Debt

        Loss on early extinguishment of debt was $4 million in the first nine months of 2005. Extinguishment of debt consisted of a $4 million loss related to the early repayment of EME's junior subordinated debentures recorded during the first quarter of 2005.

Corporate Interest Income and Other, Net

        Corporate interest income and other (net) increased $17 million and $35 million for the third quarter and nine months ended September 30, 2005, respectively, compared to the corresponding periods of 2004. The increases were primarily attributable to higher interest income resulting from higher average cash balances during the first nine months of 2005, compared with the corresponding period of 2004.

Income Taxes

        EME's income tax provision (benefit) from continuing operations was $129 million and $(342) million during the nine months ended September 30, 2005 and 2004, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes which was recorded as a reduction of income taxes during the second quarter of 2005. During the second quarter of 2004, EME recorded a tax benefit of $368 million primarily relating to the loss on the termination of

39

the Collins Station lease, and during the first quarter of 2004, EME recorded a tax provision of $18 million relating to the sale of 100% of its stock in Edison Mission Energy Oil & Gas, which in turn held interests in Four Star Oil & Gas.

Results of Discontinued Operations

        Income from discontinued operations, net of tax, was $27 million and $498 million during the third quarters of 2005 and 2004, respectively, and $55 million and $570 million during the first nine months of 2005 and 2004, respectively. During the first nine months of 2005, EME completed the following sales:

•

On January 10, 2005, EME sold its 50% equity interest in the CBK hydroelectric power project located in the Philippines 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. During the first nine months of 2004, EME completed the following sale:

•

On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser. The after-tax gain on the sale of Contact Energy was $141 million.

        During the quarter ended September 30, 2005, EME recorded a tax benefit adjustment of $28 million which resulted from completion of the 2004 federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004. During the third quarter ended September 30, 2004, EME recorded a deferred income tax benefit of $327 million in accordance with Emerging Issues Task Force Issue No. 93-17, "Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation," (EITF 93-17). Under EITF 93-17, because the tax basis of the stock of EME's Dutch subsidiary, MEC International B.V., exceeded EME's book basis, an adjustment to deferred taxes was required during the third quarter of 2004.

        During the third quarter of 2004, EME reclassified its international activities which were then under contracts for sale as discontinued operations. Subsequently, EME completed the sale of these operations, except for the Doga project, which was no longer under a contract for sale. While EME continued to seek to sell its ownership interest in this project, there was no assurance that such efforts would result in a sale during the twelve-month period prescribed under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." As a result, EME reclassified the Doga project to continuing operations during the fourth quarter of 2004, and, accordingly, it is reflected as part of continuing operations for all periods presented.

Previously Reported Discontinued Operations

Lakeland Project

        EME previously owned and operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the Lakeland project. The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant

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pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased consolidating the activities of Lakeland Power Ltd. in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement. Accordingly, EME accounts for its ownership of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is distributed from this entity.

        As previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination of the power sales agreement. On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings of their own in the United Kingdom (similar to bankruptcy proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received £112 million (approximately $210 million) from the TXU administrators, representing an interim payment of 97% of its accepted claim of £116 million (approximately $217 million).

        From the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of £20 million (approximately $37 million) to EME on April 7, 2005 comprised of £7 million (approximately $13 million) for a secured loan which EME purchased from Lakeland Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd., and £13 million (approximately $24 million) as a distribution to the EME subsidiary that owns the equity interest in Lakeland Power Ltd. The distribution was recognized in income during the quarter ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay to EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with Lakeland Power Ltd.'s liquidation.

        EME estimates that the remaining net proceeds after tax (including taxes due in the United States) and net income resulting from the above payments will be approximately $64 million. The majority of the remaining proceeds are expected to be received in 2006, when Lakeland Power Ltd.'s liquidation is expected to be completed. Because the amounts required to settle outstanding claims and UK taxes have not been finalized and cannot be estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net income may vary materially from the above estimate.

New Accounting Pronouncements

        For a discussion of new accounting pronouncements affecting Edison Mission Energy, see "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 14. New Accounting Pronouncements."

Proposed Accounting Pronouncements

Statement of Financial Accounting Standard Interpretation, "Accounting for Uncertain Tax Positions"

        On July 14, 2005, the FASB published an exposure draft of a proposed interpretation, "Accounting for Uncertain Tax Positions." The exposure draft seeks to reduce the diversity in practice associated with recognition and measurement in the accounting for income taxes. It would apply to all tax positions accounted for in accordance with FASB Statement No. 109, "Accounting for Income Taxes." The exposure draft requires that a tax position meet a "probable recognition threshold" for the benefit of the uncertain tax position to be recognized in the financial statements. The exposure draft contains guidance with respect to the measurement of the benefit that is recognized for an uncertain tax position, when that benefit should be derecognized, and other matters. The comment period for the exposure draft ended on September 12, 2005; the earliest the guidance would be implemented is December 31, 2005. EME is currently assessing the potential impact of the proposed interpretation on its results of operations and financial condition.

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LIQUIDITY AND CAPITAL RESOURCES

Introduction

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

	Page
EME's Liquidity	42
Midwest Generation Financing	42
Capital Expenditures	43
EME's Historical Consolidated Cash Flow	43
EME's Credit Ratings	44
Margin, Collateral Deposits and Other Credit Support for Energy Contracts	45
EME's Liquidity as a Holding Company	46
Dividend Restrictions in Major Financings	47
Contractual Obligations	48
Off-Balance Sheet Transactions	49
Environmental Matters and Regulations	49

        For a complete discussion of these issues, read this quarterly report in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2004.

EME's Liquidity

        At September 30, 2005, EME and its subsidiaries had cash and cash equivalents of $1.6 billion and EME had available the full amount of borrowing capacity under a $98 million corporate credit facility. EME's consolidated debt at September 30, 2005 was $3.4 billion. In addition, EME's subsidiaries had $5.0 billion of long-term lease obligations that are due over periods ranging up to 30 years.

Midwest Generation Financing

        On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit facility had provided for a $700 million first priority secured institutional term loan due in 2011 and a $200 million first priority secured revolving credit, working capital facility due in 2009.

        The refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million revolving credit, working capital facility due in 2011. The previously existing $200 million working capital facility remains in place. Midwest Generation drew in full upon the new $300 million working capital facility at closing and used the proceeds to pay down an equivalent portion of the existing term loan. After giving effect to the paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity date of the repriced term loan remains 2011. The new working capital facility, together with the existing working capital facility, shares first lien priority with the repriced term loan. The new working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new working capital facility is 2011; however, the lenders can request to be fully repaid in 2010.

        On the day after the closing of the refinancing transaction, EME contributed $300 million in equity to Midwest Generation, and Midwest Generation used the proceeds of this equity contribution to repay the loans outstanding under the new working capital facility. Thus, after completion of the

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actions outlined herein, Midwest Generation had $343 million outstanding under its term loan and $500 million of working capital facilities available for working capital requirements, including credit support for hedging activities. As of September 30, 2005, approximately $170 million was utilized under these working capital facilities.

        Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributes to the equity contribution equals the amount thereof. Accordingly, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to the equity contribution made by EME in Midwest Generation on April 19, 2005 equals $300 million. However, Midwest Generation is required to make concurrently with each distribution an offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the portion thereof attributed to the equity contribution. Thus, Midwest Generation will not be required to offer to repay debt concurrently with a distribution so long as the portion of each distribution attributed to the April 19, 2005 equity contribution is at least one-third of such distribution.

Capital Expenditures

        The estimated capital and construction expenditures of EME's subsidiaries are $14 million for the final quarter of 2005 and $63 million and $49 million for 2006 and 2007, respectively. Non-environmental expenditures relate to 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 $4 million for the final quarter of 2005, $8 million for 2006 and $6 million for 2007. The environmental expenditures relate to environmental projects such as selective catalytic reduction system improvements at the Homer City facilities.

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

        Cash used in operating activities decreased $619 million in the first nine months of 2005, compared to the first nine months of 2004. The 2005 decrease was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and tax-allocation payments received by EME from Edison International of approximately $52 million during the first nine months of 2005, compared to approximately $43 million paid to Edison International during the first nine months of 2004. For further discussion of the tax-allocation payments, see "—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." Also contributing to the decrease were larger distributions from unconsolidated affiliates in 2005, primarily attributable to the Big 4 projects, and operating income in 2005 versus an operating loss in 2004. Partially offsetting these decreases was $684 million in required margin and collateral deposits in 2005 for EME's price risk management and trading activities, compared to $42 million in 2004. This increase in margin and collateral deposits resulted from an increase in forward market prices.

Consolidated Cash Flows from Financing Activities

        Cash used in financing activities increased $1.6 billion in the first nine months of 2005, compared to the first nine months of 2004. The 2005 increase was primarily attributable to dividend payments

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made to MEHC of $360 million during 2005, compared to $69 million during 2004. The increase was also due to the repayment of EME's junior subordinated debentures of $150 million in January 2005 and a $302 million repayment in April 2005 related to Midwest Generation's existing term loan. Net borrowings in 2004 consisted of the $1 billion secured notes and $700 million term loan facility received by Midwest Generation in April 2004 partially offset by the repayment of $693 million related to Edison Mission Midwest Holdings' credit facility and $28 million related to the Coal and Capex facility in April 2004.

Consolidated Cash Flows from Investing Activities

        Cash provided by investing activities decreased $593 million in the first nine months of 2005, compared to the first nine months of 2004. The 2005 decrease was primarily attributable to proceeds of $739 million received in 2004 from the sale of Contact Energy. Proceeds of $124 million received in 2005 from the sale of EME's 25% investment in the Tri Energy project and EME's 50% investment in the CBK project were comparable to proceeds of $118 million received in 2004 from the sale of EME's stock of Edison Mission Energy Oil & Gas and the sale of EME's 50% partnership interest in the Brooklyn Navy Yard project. Partially offsetting the 2005 decrease were net sales of auction rate securities of $140 million in 2005, compared to $20 million in 2004.

EME's Credit Ratings

Overview

        Credit ratings for EME and its subsidiaries, Midwest Generation, LLC and Edison Mission Marketing & Trading, are as follows:

		Moody's Rating	S&P Rating
EME		B1	B+
Midwest Generation, LLC:
	First priority senior secured rating	Ba3	BB-
	Second priority senior secured rating	B1	B
Edison Mission Marketing & Trading		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 EME being required to make equity contributions or provide additional financial support to its subsidiaries.

        The credit ratings of EME are below investment grade and, accordingly, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties for its price risk management and trading activities related to accounts payable and unrealized losses.

Credit Rating of Edison Mission Marketing & Trading

        The Homer City sale-leaseback documents restrict EME Homer City Generation L.P.'s (EME Homer City's) ability to enter into trading activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities if Edison Mission

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Marketing & Trading 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 Edison Mission Marketing & Trading, 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 Edison Mission Marketing & Trading; or (2) Edison Mission Marketing & Trading 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 Edison Mission Marketing & Trading 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 energy contracts (including forward contracts, transmission contracts and futures contracts), EME's subsidiary, Edison Mission Marketing & Trading, has entered into agreements to support the risk of nonperformance. At September 30, 2005, Edison Mission Marketing & Trading had deposited $516 million in cash with brokers in margin accounts in support of futures contracts and had deposited $210 million with counterparties in support of forward energy and transmission contracts. These margin and collateral deposits are used in support of EME's price risk management and energy trading activities. The margin and collateral deposits generally earn interest at a rate that approximates the Federal Funds Rate. In addition, EME has issued letters of credit of $6 million in support of commodity contracts at September 30, 2005.

        Margin and collateral deposits increased substantially during the third quarter of 2005 due to higher wholesale energy prices and increased megawatt hours hedged. Future cash collateral requirements may be higher than the margin and collateral requirements at September 30, 2005, if wholesale energy prices increase further. Using the amount of energy contracts outstanding at September 30, 2005, EME estimates that margin and collateral requirements could increase by approximately $300 million using a 95% confidence interval and an internal model estimate using historical volatility.

        Midwest Generation has $500 million in credit facilities to support margin requirements specifically related to contracts entered into by Edison Mission Marketing & Trading related to the Illinois Plants. At September 30, 2005, Midwest Generation has borrowed $165 million under these credit facilities to finance margin advances to Edison Mission Marketing & Trading of $316 million. The balance of the margining advances by Midwest Generation was provided through cash on hand. In addition, EME has cash on hand and a $98 million working capital facility to provide credit support to subsidiaries. See "EME's Liquidity" for further discussion.

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EME's Liquidity as a Holding Company

Overview

        At September 30, 2005, EME had corporate cash and cash equivalents of $1.3 billion to meet liquidity needs. See "—EME's Liquidity." EME had no borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at September 30, 2005. 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."

        EME's secured corporate credit facility provides credit available in the form of cash advances or letters of credit. In addition to the interest payments, EME pays a commitment fee of 0.50% on the unutilized portion of the facility. EME has agreed to maintain a minimum interest coverage ratio and a minimum recourse debt to recourse capital ratio (as such ratios are defined in the credit agreement). At September 30, 2005, EME met both these ratio tests.

        As security for its obligations under its new 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 will be deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

        At September 30, 2005, EME also had available $88 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.

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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.

		Nine Months Ended September 30,
		2005		2004
		(in millions)
Distributions from Consolidated Operating Projects:
	Edison Mission Midwest Holdings (Illinois Plants)(1)	$	171	$	—
	EME Homer City Generation L.P. (Homer City facilities)(2)		62		61
	Holding companies of other consolidated generating projects		1		—
Distributions from Unconsolidated Operating Projects:
	Edison Mission Energy Funding Corp. (Big 4 Projects)(3)		93		80
	Sunrise Power Company		5		5
	Holding company for Doga project		17		15
	Holding companies for Westside projects		13		13
	Holding companies of other unconsolidated operating projects		5		1
Total Distributions		$	367	$	175

(1)

On October 24, 2005, EME received a $160 million distribution from Midwest Generation.

(2)

On October 3, 2005, EME received a $24 million distribution from Homer City.

(3)

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.

Intercompany Tax-Allocation Agreement

        EME is included in the consolidated federal and combined state income tax returns of Edison International and is 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 and timing of tax-allocation payments is 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 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.

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

47

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 September 30, 2005:

Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation, LLC (Illinois Plants)	Interest Coverage Ratio	Greater than or equal to 1.25 to 1	2.35 to 1
Midwest Generation, LLC (Illinois Plants)	Secured Leverage Ratio	Less than or equal to 8.75 to 1	3.06 to 1
EME Homer City Generation L.P. (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	3.03 to 1
Edison Mission Energy Funding Corp. (Big 4 Projects)	Debt Service Coverage Ratio	Greater than or equal to 1.25 to 1	3.14 to 1

        For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" on page 65 of EME's annual report on Form 10-K for the year ended December 31, 2004.

Contractual Obligations

Fuel Supply Contracts

        Midwest Generation and EME Homer City have entered into additional fuel purchase commitments with various third-party suppliers during the first nine months of 2005. These additional commitments are currently estimated to be $22 million for 2005, $114 million for 2006, $169 million for 2007, $44 million for 2008, and $62 million for 2009.

Coal Transportation Agreements

        Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers) which extend through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first nine months of 2005 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $33 million for 2005, $61 million for 2006, $117 million for 2007, $40 million for 2008, and $77 million for 2009.

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Fuel Supply Dispute

        Beginning in 2004, EME Homer City experienced interruptions of supply under two agreements with Unionvale Coal Company and Genesis, Inc. Unionvale and Genesis claimed that alleged geologic conditions at the Genesis No. 17 Mine in Pennsylvania, which is one source of coal under these multi-source coal contracts, constituted force majeure and excused contract performance. These two agreements together provide for the delivery to EME Homer City of approximately 20% of EME Homer City's clean coal requirements in 2005 and 2006, and approximately 10% in 2007. Claims arising from these matters have been resolved in a confidential settlement, and the lawsuit has been dismissed. EME Homer City has awarded contracts to alternate suppliers, and adjusted its inventory strategies to reflect and offset the delivery shortfall for 2005.

Off-Balance Sheet Transactions

        For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 74 of EME's annual report on Form 10-K for the year ended December 31, 2004. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report.

Environmental Matters and Regulations

        For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" on page 77 of EME's annual report on Form 10-K for the year ended December 31, 2004 and the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as follows:

        On May 12, 2005, the Clean Air Interstate Rule (CAIR) was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address ozone attainment issues by reducing regional NOx and SO2 emissions. The CAIR reduces the current SO2 (i.e., Clean Air Act Title IV Phase II) emissions allowance cap in 2010 and 2015 by 50% and 65%, respectively. Regional NOx emissions are required to be reduced in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The CAIR has been challenged in court by state, environmental and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation. EME is reviewing the impact of the rule on its business plan. Given the uncertainty of the requirements that will need to be implemented and the options available to meet the NOx and SO2 reductions fleetwide, EME at this time cannot accurately estimate the cost to meet these obligations.

        The Clean Air Mercury Rule (CAMR), published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual nationwide cap is 38 tons and emissions will be reduced primarily by taking advantage of "co-benefit" reductions; that is, mercury reductions achieved by reducing sulfur dioxide and nitrogen oxides emissions under the CAIR. In the second phase, due in 2018, coal-fired power plants will be subject to a second annual cap, which will reduce emissions nationwide to 15 tons upon full implementation. States may join the trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's suggested cap-and-trade program. Any program adopted by a state must be approved by the US EPA.

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        Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired electric generating units were required to be regulated pursuant to Section 112 of the federal Clean Air Act. Litigation has already been filed challenging the US EPA's rescission action and claiming that the agency should have imposed technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR following its publication in the Federal Register. As a result of these challenges, the CAMR rules may change in terms of substance and timetables.

        To the extent that Illinois and Pennsylvania implement US EPA's CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, then EME may have the option to purchase mercury emission allowances, to install control equipment (or otherwise to alter operations so as to reduce mercury emissions), or some combination thereof. If EME were to implement environmental control technology at its Homer City facilities instead of purchasing allowances to comply with the CAMR and other Clean Air Act developments described in "Environmental Matters and Regulations—Federal—United States of America" on page 79 of EME's annual report on Form 10-K for the year ended December 31, 2004, it currently estimates capital expenditures for such improvements to be approximately $350 million to $400 million in the 2006-2010 timeframe. However, because the mercury state implementation plans are not due until October 31, 2006 and such plans may not adopt the CAMR's cap-and-trade program, and because EME cannot predict the outcome of the legal challenge to the CAMR and the US EPA's decision not to regulate mercury emissions pursuant to Section 112 of the federal Clean Air Act, the full impact of this regulation currently cannot be assessed. EME's approach to meeting these obligations will continue to be based upon an ongoing assessment of the federal requirements and market conditions.

50

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 uncontracted generating plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, transmission rights, and interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures. See "Management's Overview; Critical Accounting Estimates" and "Liquidity and Capital Resources—EME's Credit Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its counterparties.

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

	Page
Commodity Price Risk	51
Credit Risk	58
Interest Rate Risk	59
Fair Value of Financial Instruments	60
Regulatory Matters	61

        For a complete discussion of these issues, read this quarterly report in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2004.

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 costs;



•

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;



•

transmission congestion in and to each market area and the resulting differences in prices between delivery points;



•

the market structure rules to be established for each market area and regulatory developments affecting the market areas;



•

the cost and availability of emission credits or allowances;



•

the availability, reliability and operation of nuclear generating plants, where applicable, and the extended operation of nuclear generating plants beyond their presently expected dates of decommissioning;



•

weather conditions prevailing in surrounding areas from time to time; and



•

the rate of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

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

Energy Price Risk—Introduction

        Electric power generated at EME's merchant plants is generally sold into the PJM market.

        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 tolerance, 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 the 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 a "value at risk" analysis in its daily business 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 Edison Mission Marketing & Trading. 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 spot market sales. Second, EME's ability to enter into hedging transactions depends upon its, Midwest Generation's and Edison Mission Marketing & Trading'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 such hedging transactions entered into by Edison Mission Marketing & Trading under an energy services agreement between Midwest Generation and Edison Mission Marketing & Trading. Utilization of this credit facility in support of such hedging transactions is expected to provide

52

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 Edison Mission Marketing & Trading. See "—Credit Risk," below.

Energy Price Risk Affecting Sales from the Illinois Plants

Pre-2005 Merchant Sales

        Energy generated at the Illinois Plants was historically sold under three power purchase agreements between Midwest Generation and Exelon Generation Company, under which Exelon Generation was obligated to make capacity payments for the plants under contract and energy payments for the energy produced by these plants and taken by Exelon Generation. The power purchase agreements began on December 15, 1999. The capacity payments provided the units under contract with revenue for fixed charges, and the energy payments compensated those units for all, or a portion of, variable costs of production. The three power purchase agreements with Exelon Generation had all been terminated by December 31, 2004.

        To the extent that energy and capacity from the Illinois Plants was not sold under the power purchase agreements with Exelon Generation, it was sold on a wholesale basis through a combination of bilateral agreements, forward energy sales and spot market sales. Approximately 43% of the energy and capacity sales from the Illinois Plants in the first nine months of 2004 were made on a wholesale basis outside of the power purchase agreements.

        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, which linked eastern PJM and the Northern Illinois control areas of the PJM system and improved access from the Illinois Plants into the broader PJM market. Further, on April 1, 2005, the Midwest Independent Transmission System Operator (MISO) commenced operation, linking the MISO footprint, including Illinois, Wisconsin, Indiana, Michigan, and Ohio, in a locational marginal pricing system similar to that of PJM.

        Since the initial expansion 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 MISO, at the Cinergy Hub in MISO. Because of proximity, the Midwest Generation assets 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.

        Following the expansion of the PJM system described above, sales into the expanded PJM, the primary market currently available to the Illinois Plants, replaced sales previously made as bilateral sales and spot sales "Into ComEd" and "Into AEP." See "Regulatory Matters" in EME's annual report on Form 10-K for the year ended December 31, 2004 for a more detailed discussion of developments regarding Commonwealth Edison's joining PJM, and "—Basis Risk" below for a discussion of locational marginal pricing.

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2005 Merchant Sales

        During 2005, electric power generated at the Illinois Plants has generally been sold into the PJM market. The PJM pool has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in the new expanded western PJM control area and are physically connected to high-voltage transmission lines serving this market.

        The following table depicts the average historical market prices for energy per megawatt-hour during the first nine months of 2005 and 2004.

	2005(1)		2004
January	$	38.36	$	27.88	(2)
February		34.92		29.98	(2)
March		45.75		30.66	(2)
April		38.98		27.88	(2)
May		33.60		34.05	(1)
June		42.45		28.58	(1)
July		50.87		30.92	(1)
August		60.09		26.31	(1)
September		53.30		27.98	(1)
Nine-Month Average	$	44.26	$	29.36

(1)

Represents average historical market prices for energy as quoted for sales into the Northern Illinois Hub. Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.

(2)

Represents average historical market prices for energy for "Into ComEd." Energy prices were determined by obtaining broker quotes and other public price sources for "Into ComEd" delivery points. See discussion under "—Pre-2005 Merchant Sales" above for further discussion regarding the replacement of sales "Into ComEd" with sales into the expanded 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 is affected by weather and economic growth, plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

        The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at September 30, 2005:

		24-Hour Northern Illinois Hub Forward Energy Prices*
2005
	October	$	47.40
	November		49.98
	December		55.85
2006 Calendar "strip"(1)		$	52.74
2007 Calendar "strip"(1)		$	47.61

(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.

54

        The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at September 30, 2005:

	2005		2006		2007
Megawatt hours		4,835,118		14,193,014		6,804,000
Average price/MWh(1)	$	35.34	$	43.02	$	42.24

(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 September 30, 2005 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 short-term markets, which establish 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 New York Independent System Operator (NYISO) markets.

        The following table depicts the average historical market prices for energy per megawatt-hour in PJM during the first nine months of 2005 and 2004:

	Historical Energy Prices* 24-Hour PJM
	Homer City				West Hub
	2005		2004		2005		2004
January	$	45.82	$	51.12	$	49.53	$	55.01
February		39.40		47.19		42.05		44.22
March		47.42		39.54		49.97		39.21
April		44.27		43.01		44.55		42.81
May		43.67		44.68		43.64		48.04
June		46.63		36.72		53.72		38.05
July		54.63		40.09		66.34		43.64
August		66.39		34.76		82.83		38.59
September		66.67		40.62		76.82		41.96
Nine-Month Average	$	50.54	$	41.97	$	56.61	$	43.50

*

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 is affected by weather and economic growth, 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.

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        The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at September 30, 2005:

		24-Hour PJM West Hub Forward Energy Prices*
2005
	October	$	69.90
	November		74.49
	December		80.80
2006 Calendar "strip"(1)		$	72.01
2007 Calendar "strip"(1)		$	62.18

(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 September 30, 2005:

	2005		2006		2007
Megawatt hours		2,215,125		8,525,200		3,618,000
Average price/MWh(1)	$	43.14	$	53.24	$	60.68

(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 September 30, 2005 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, there is not a liquid market for entering into these contracts at the individual plant busbars. A liquid market does exist for a settlement point known as the PJM West Hub in the case of Homer City 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 such forward contracts with reference to PJM spot prices at the busbar of the plant involved, plus,



•

sales to third parties at the price under such hedging contracts at designated settlement points (generally the PJM West Hub for Homer City and the Northern Illinois Hub for the Illinois Plants) less the cost of power at spot prices at the same designated settlement points.

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        Under the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly 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 raised or lowered 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 past 12 months, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (the primary trading hub in PJM for the Homer City facilities) by an average of 9%. The monthly average difference during this period ranged from zero to 20%, which occurred in August 2005. For comparison, the same difference during 2004 was 4%. By contrast to the Homer City facilities, during the past 12 months, transmission congestion in PJM has not resulted in prices at the Northern Illinois Hub being significantly different from 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 participated in purchasing financial transmission rights in PJM, and may continue to do so in the future. A financial transmission right is a financial instrument that entitles the holder thereof to receive actual spot prices at one point of delivery and pay prices at another point of delivery that are pegged to prices at the first point of delivery, plus or minus a fixed amount. Accordingly, EME's price risk management activities include using financial transmission rights alone or in combination with forward 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 tons of coal annually, obtained from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements typically ranging from one year to six years in length. The following table summarizes the percent of expected coal requirements for the next five years that are under contract at September 30, 2005.

	Percent of Coal Requirements Under Contract
	2005(1)	2006	2007	2008	2009
Illinois Plants	111%	100%	91%	32%	32%
Homer City facilities(2)	101%	78%	78%	21%	15%

(1)

The percentage in 2005 is calculated based on coal supply and expected generation requirements for a full year.

(2)

Adjusted for expected deliveries under an executed agreement to settle outstanding contract disputes. See "—Liquidity and Capital Resources—Contractual Obligations—Fuel Supply Dispute" for more information regarding fuel supply interruptions and the dispute with two suppliers.

        EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachia coal, which is purchased for the Homer City facilities, increased considerably since 2004. In January 2004, prices of Northern Appalachia coal (with 13,000 British Thermal units (Btu) content and <3.0 SO2 MMBtu content) were below $40 per ton and increased to more than $60 per ton during 2004. On September 30, 2005, the Energy Information Administration reported the price of Northern Appalachia coal at $54.00 per ton. The overall increase in the Northern Appalachia coal price has been largely attributed to greater demand from domestic power producers and increased international

57

shipments of coal to Asia. Prices of Powder River Basin (PRB) coal (with 8,800 Btu content and 0.8 SO2 MMBtu content), which is purchased for the Illinois Plants, have recently increased due to curtailment of coal shipments for the remainder of 2005 due to increased PRB coal demand from the other regions (east), rail constraints (discussed below) and higher prices for SO2 allowances. On September 30, 2005, the Energy Information Administration reported the price of $12.79 per ton, which compares to 2004 prices generally below $7 per ton.

        During the first nine months of 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 repairs to these rail lines and have advised their customers, including EME, that shipments will be curtailed by 15% to 20% during 2005. Through September 30, 2005, EME received approximately 87% of expected shipments and expects to receive shipments of approximately 80% to 85% during the fourth quarter of 2005. Rail maintenance will continue as long as weather permits. EME continues to work with its transportation provider to minimize any disruption of planned shipments. 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

        Under the federal Acid Rain Program (which requires electric generating stations to hold sulfur dioxide allowances) and Illinois and Pennsylvania regulations implementing the federal NOx SIP Call requirement, 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 US EPA Acid Rain Program, increased substantially during 2004 and the first nine months of 2005. The average price of purchased SO2 allowances increased to $765 per ton during the nine months ended September 30, 2005 from $281 per ton during the nine months ended September 30, 2004. The increase in the price of SO2 allowances has been attributed to reduced numbers of both allowance sellers and prior vintage allowances.

        See "Liquidity and Capital Resources—Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions.

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 such counterparty defaulted.

        To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other

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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 September 30, 2005, the amount of exposure, broken down by the credit ratings of EME's counterparties, was as follows:

S&P Credit Rating	September 30, 2005
	(in millions)
A or higher	$	2
A-		148
BBB+		64
BBB		3
BBB-		1
Below investment grade		—
Total	$	218

        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 from a supplier in the event of default. 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.

        For the nine months ended September 30, 2004, one customer accounted for 14% and a second customer, Exelon Generation, accounted for 40% of EME's consolidated operating revenues. For more information on Exelon Generation, see "Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants—Pre-2005 Merchant Sales."

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 total long-term obligations (including current portion) was $3.8 billion at September 30, 2005, compared to the carrying value of $3.4 billion.

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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):

		September 30, 2005			December 31, 2004
Commodity price:
	Electricity	$	(582	)	$	10

        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, the valuation method and the related fair value of EME's commodity price risk management assets and liabilities as of September 30, 2005 (in millions):

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(582	)	$	(501	)	$	(81	)	$	—	$	—

Energy Trading Derivative Financial Instruments

        The fair value of the commodity financial instruments related to energy trading activities as of September 30, 2005 and December 31, 2004, are set forth below (in millions):

	September 30, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities
Electricity	$	186	$	79	$	125	$	36

        The change in the fair value of trading contracts for the nine months ended September 30, 2005, was as follows (in millions):

Fair value of trading contracts at January 1, 2005	$	89
Net gains from energy trading activities		130
Amount realized from energy trading activities		(130	)
Other changes in fair value		18
Fair value of trading contracts at September 30, 2005	$	107

        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

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following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of September 30, 2005) (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	18	$	18	$	—	$	—	$	—
Prices based on models and other valuation methods		89		2		9		7		71
Total	$	107	$	20	$	9	$	7	$	71

Regulatory Matters

        For a discussion of EME's regulatory matters, refer to "Overview of Domestic Facilities—Illinois Power Markets" on page 5 of EME's annual report on Form 10-K for the year ended December 31, 2004 and "Regulatory Matters" on page 16 of EME's annual report on Form 10-K for the year ended December 31, 2004. There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing of EME's annual report, except as follows:

Opening of MISO Market

        The MISO's day-ahead and real-time locational marginal pricing markets commenced operation on April 1, 2005. Since that time, the wholesale electricity trading community has opted to trade a product delivered at the Cinergy Hub as defined by MISO rather than at the "Into Cinergy" location that was used previously. EME anticipates that the opening of the MISO market will lead to increased liquidity in the Midwest electricity markets because locational marginal pricing provides a liquid and credible cash index against which the trading community can settle contracts.

Passage of Comprehensive Energy Legislation by Congress

        A comprehensive energy bill was passed by the House and Senate in July 2005 and was signed into law by the President on August 8, 2005. Known as "EPAct 2005," this comprehensive legislation includes provisions for the repeal of the Public Utility Holding Company Act (PUHCA), for amendments to the Public Utility Regulatory Policies Act of 1978 (PURPA), for the introduction of new regulations regarding "Transmission Operation Improvements," for Transmission Rate Reform, for incentives for various generation technologies and for the extension through December 31, 2007 of production tax credits for wind and other specified types of generation. A number of these provisions will require implementing regulations to be promulgated by the Federal Energy Regulatory Commission (FERC). EME is currently assessing the potential impact of this legislation and the likely regulations.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 86 of EME's annual report on Form 10-K for the year ended December 31, 2004. Refer to "Market Risk Exposures" in Item 2 of this report for an update to that disclosure.

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ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

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PART II – OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

        For a discussion of EME's legal proceedings, refer to "Legal Proceedings" on page 23 of EME's annual report on Form 10-K for the year ended December 31, 2004. There have been no significant developments with respect to EME's legal proceedings specifically affecting EME since the filing of EME's annual report, except as follows:

Legal Developments Affecting Sunrise Power Company

        Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also alleges a class action. One of the newly added parties removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants filed a responding pleading on May 6, 2005. Following a hearing on September 7, 2005, the court sustained defendants' demurrer regarding preemption and filed rate doctrine. The plaintiff has waived his right to appeal.

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 (REGISTRANT)
By:	/s/  W. JAMES SCILACCI W. James Scilacci Senior Vice President and Chief Financial Officer
Date:	November 4, 2005

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QuickLinks

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions, Unaudited)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED 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 SEPTEMBER 30, 2005 (Unaudited)

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4. CONTROLS AND PROCEDURES

PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
ITEM 6. EXHIBITS

SIGNATURES