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

Form 10-Q

ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2002

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

        Number of shares outstanding of the registrant's Common Stock as of May 8, 2002: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

Item		Page
PART I—Financial Information
1.	Financial Statements	1
2.	Management's Discussion and Analysis of Results of Operations and Financial Condition	18
3.	Quantitative and Qualitative Disclosures About Market Risk	44
PART II—Other Information
1.	Legal Proceedings	45
6.	Exhibits and Reports on Form 8-K	46
	Signatures	47

PART I—FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands)

			Three Months Ended March 31,
			2002			2001
			(Unaudited)
Operating Revenues
	Electric revenues		$	526,263		$	474,002
	Equity in income from energy projects			45,034			64,190
	Equity in income from oil and gas investments			7,540			20,450
	Net gains (losses) from energy trading and price risk management			21,366			17,354
	Operation and maintenance services			9,534			10,305
		Total operating revenues		609,737			586,301
Operating Expenses
	Fuel			213,471			195,191
	Plant operations			186,713			141,197
	Plant operating leases			52,029			35,396
	Operation and maintenance services			7,102			7,441
	Depreciation and amortization			59,749			61,357
	Long-term incentive compensation			1,670			(3,714	)
	Administrative and general			43,402			35,976
		Total operating expenses		564,136			472,844
Operating income				45,601			113,457
Other Income (Expense)
	Interest and other income			10,440			11,854
	Interest expense			(114,007	)		(126,552	)
	Dividends on preferred securities			(5,136	)		(6,290	)
		Total other income (expense)		(108,703	)		(120,988	)
	Loss from continuing operations before income taxes and minority interest			(63,102	)		(7,531	)
	Provision (benefit) for income taxes			(32,791	)		2,779
	Minority interest			(5,366	)		(513	)
Loss From Continuing Operations				(35,677	)		(10,823	)
	Income (loss) from operations of discontinued foreign subsidiary, net of tax (Note 4)			(162	)		19,040
Income (Loss) Before Accounting Change				(35,839	)		8,217
	Cumulative effect of change in accounting, net of tax			—			250
Net Income (Loss)			$	(35,839	)	$	8,467

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 thousands)

			Three Months Ended March 31,
			2002			2001
			(Unaudited)
Net Income (Loss)			$	(35,839	)	$	8,467
Other comprehensive income (expense), net of tax:
	Foreign currency translation adjustments:
		Foreign currency translation adjustments, net of income tax expense (benefit) of $867 and $(2,349) in 2002 and 2001, respectively		15,859			(96,645	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Cumulative effect of change in accounting for derivatives, net of income tax benefit of $110.9 million		—			(230,239	)
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $11.5 million and $(17.4) million in 2002 and 2001, respectively		38,085			(38,711	)
		Reclassification adjustments included in net income (loss), net of income tax benefit of $0.4 million and $15.6 million in 2002 and 2001, respectively		706			28,271
Other comprehensive income (expense)				54,650			(337,324	)
Comprehensive Income (Loss)			$	18,811		$	(328,857	)

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

2

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

			March 31, 2002		December 31, 2001
			(Unaudited)
Assets
Current Assets
	Cash and cash equivalents		$	368,586	$	372,139
	Accounts receivable—trade, net of allowance of $12,942 and $14,603 in 2002 and 2001, respectively			274,874		312,728
	Accounts receivable—affiliates			233,092		234,203
	Assets under energy trading and price risk management			177,206		64,729
	Inventory			180,041		167,406
	Prepaid expenses and other			80,515		83,085
		Total current assets		1,314,314		1,234,290
Investments
	Energy projects			1,594,227		1,799,242
	Oil and gas			33,621		30,698
		Total investments		1,627,848		1,829,940
Property, Plant and Equipment				7,138,169		6,917,980
	Less accumulated depreciation and amortization			756,028		680,417
		Net property, plant and equipment		6,382,141		6,237,563
Other Assets
	Long-term receivables			264,557		264,784
	Goodwill			647,750		631,735
	Deferred financing costs			78,421		84,780
	Long-term assets under energy trading and price risk management			12,368		2,998
	Restricted cash and other			205,994		290,325
		Total other assets		1,209,090		1,274,622
Assets of Discontinued Operations				78,654		153,610
Total Assets			$	10,612,047	$	10,730,025

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

3

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

			March 31, 2002			December 31, 2001
			(Unaudited)
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	11,479		$	11,964
	Accounts payable and accrued liabilities			375,270			423,287
	Liabilities under energy trading and price risk management			41,985			22,381
	Interest payable			85,735			87,308
	Short-term obligations			95,269			168,241
	Current portion of long-term incentive compensation			4,366			6,170
	Current maturities of long-term obligations			193,074			190,295
		Total current liabilities		807,178			909,646
Long-Term Obligations Net of Current Maturities				5,765,366			5,749,460
Long-Term Deferred Liabilities
	Deferred taxes and tax credits			912,023			936,300
	Deferred revenue			441,734			427,485
	Long-term incentive compensation			36,712			39,331
	Long-term liabilities under energy trading and price risk management			149,233			170,506
	Other			245,147			266,742
		Total long-term deferred liabilities		1,784,849			1,840,364
Liabilities of Discontinued Operations				37,253			55,845
Total Liabilities				8,394,646			8,555,315
Minority Interest				361,302			344,092
Preferred Securities of Subsidiaries
	Company-obligated mandatorily redeemable security of partnership holding solely parent debentures			150,000			150,000
	Subject to mandatory redemption			110,125			103,950
	Total preferred securities of subsidiaries			260,125			253,950
Commitments and Contingencies (Note 6)
Shareholder's Equity
	Common stock, no par value; 10,000 shares authorized; 100 shares issued and outstanding			64,130			64,130
	Additional paid-in capital			2,631,917			2,631,326
	Retained deficit			(852,902	)		(816,968	)
	Accumulated other comprehensive loss			(247,171	)		(301,820	)
Total Shareholder's Equity				1,595,974			1,576,668
Total Liabilities and Shareholder's Equity			$	10,612,047		$	10,730,025

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

4

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

				Three Months Ended March 31,
				2002			2001
				(Unaudited)
Cash Flows From Operating Activities
	Loss from continuing operations, after accounting change, net			$	(35,677	)	$	(10,573	)
	Adjustments to reconcile loss to net cash provided by (used in) operating activities:
		Equity in income from energy projects			(45,034	)		(64,190	)
		Equity in income from oil and gas investments			(7,540	)		(20,450	)
		Distributions from energy projects			135,629			5,175
		Dividends from oil and gas			4,324			29,296
		Depreciation and amortization			59,749			61,357
		Amortization of discount on short-term obligations			—			1,106
		Deferred taxes and tax credits			(38,555	)		(5,429	)
		Cumulative effect of change in accounting, net of tax			—			(250	)
	Changes in operating assets and liabilities:
		Decrease in accounts receivable			38,926			107,321
		Increase in inventory			(12,635	)		(13,756	)
		Decrease in prepaid expenses and other			21,588			18,454
		Decrease in accounts payable and accrued liabilities			(72,624	)		(304,860	)
		Increase (decrease) in interest payable			(1,573	)		4,527
		Increase (decrease) in long-term incentive compensation			822			(6,682	)
		Decrease (increase) in assets under risk management, net			(22,114	)		34,395
	Other operating, net				(6,818	)		(6,285	)
					18,468			(170,844	)
	Operating cash flow from discontinued operations				(7,202	)		32,610
			Net cash provided by (used in) operating activities		11,266			(138,234	)
Cash Flows From Financing Activities
	Borrowing on long-term obligations				88,706			930,020
	Payments on long-term obligations				(37,955	)		(849,604	)
	Short-term financing, net				(81,292	)		144,765
	Cash dividends to parent				—			(32,500	)
	Funds provided to discontinued operations				—			(21,080	)
					(30,541	)		171,601
	Financing cash flow from discontinued operations				—			(280,201	)
			Net cash used in financing activities		(30,541	)		(108,600	)
Cash Flows From Investing Activities
	Investments in and loans to energy projects				1,224			(148,222	)
	Purchase of common stock of acquired companies				—			(20,000	)
	Purchase of power sales agreement				(80,084	)		—
	Capital expenditures				(133,229	)		(75,016	)
	Proceeds from return of capital and loan repayments				83,606			—
	Proceeds from sale of assets				43,986			—
	Decrease in restricted cash				88,814			9,127
	Investments in other assets				573			—
	Other, net				(6,037	)		8,980
					(1,147	)		(225,131	)
	Investing cash flow from discontinued operations				—			(4,089	)
			Net cash used in investing activities		(1,147	)		(229,220	)
Effect of exchange rate changes on cash					2,885			(36,275	)
Net decrease in cash and cash equivalents					(17,537	)		(512,329	)
Cash and cash equivalents at beginning of period					434,249			962,865
Cash and cash equivalents at end of period					416,712			450,536
Cash and cash equivalents classified as part of discontinued operations					(48,126	)		(101,600	)
Cash and cash equivalents of continuing operations				$	368,586		$	348,936

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

5

EDISON MISSION ENERGY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2002

NOTE 1.    GENERAL

        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 three months ended March 31, 2002 are not necessarily indicative of the operating results for the full year.

        Our significant accounting policies are described in Note 2 to our Consolidated Financial Statements as of December 31, 2001 and 2000, included in our 2001 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 1, 2002. We follow the same accounting policies for interim reporting purposes. This quarterly report should be read in connection with such financial statements.

        Certain prior period amounts have been reclassified to conform to the current period financial statement presentation.

NOTE 2.    INVENTORY

        Inventory is stated at the lower of weighted average cost or market. Inventory at March 31, 2002 and December 31, 2001 consisted of the following:

	March 31, 2002		December 31, 2001
	(Unaudited)
	(in millions)
Coal and fuel oil	$	120.9	$	110.1
Spare parts, materials and supplies		59.1		57.3
Total	$	180.0	$	167.4

NOTE 3.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

        Accumulated other comprehensive loss consisted of the following (in millions):

	Currency Translation Adjustments			Unrealized Gains (Losses) on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2001	$	(133.4	)	$	(168.4	)	$	(301.8	)
Current period change		15.8			38.8			54.6
Balance at March 31, 2002 (Unaudited)	$	(117.6	)	$	(129.6	)	$	(247.2	)

        Unrealized gains (losses) on cash flow hedges included the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 62% of our accumulated other comprehensive loss at March 31, 2002 related to unrealized losses on the cash flow hedge resulting from this contract. These losses arise from current forecasts of future electricity prices in these markets being greater than our contract prices. Although the contract prices are below the current market prices, we believe that these contract prices meet our profit objectives and insulate us

6

from fluctuations in market prices. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify as a cash flow hedge, future changes in the forecast of market prices for contract volumes included in this agreement will cause increases or decreases in our other comprehensive income without significantly affecting our net income. In addition to this contract, unrealized gains (losses) on cash flow hedges included our share of interest rate swaps of our unconsolidated affiliates and the Loy Yang B project.

        As our hedged positions are realized, approximately $0.4 million, after tax, of the net unrealized losses on cash flow hedges will be reclassified into earnings during the next twelve months. Management expects that these net unrealized losses will be offset when the hedged items are recognized in earnings. The maximum period over which a cash flow hedge is designated, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 15 years.

NOTE 4.    DISCONTINUED OPERATIONS

        On December 21, 2001, Edison First Power Limited completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. The sale was the result of a competitive bidding process. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. The results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements in accordance with SFAS No. 144. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.

        Effective January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges under SFAS No. 133. We could not conclude, based on information available at January 1, 2001, that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

        Summarized results of discontinued operations are as follows:

	Three Months Ended March 31,
	2002			2001
	(Unaudited)
	(in millions)
Total operating revenues	$	0.6		$	183.8
Income (loss) before income taxes		(0.2	)		11.6
Income (loss) before accounting change		(0.2	)		13.2
Cumulative effect of change in accounting, net of income tax expense of $2.5 million for 2001		—			5.8
Income (loss) from operations of discontinued foreign subsidiary		(0.2	)		19.0

7

        The following summarizes the balance sheet information of the discontinued operations (in millions):

		March 31, 2002		December 31, 2001
		(Unaudited)
Cash and cash equivalents		$	48.1	$	62.1
Accounts receivable—trade, net of allowance of $1.8 million and $1.4 million in 2002 and 2001, respectively			29.8		88.4
Other current assets			0.7		1.5
	Total current assets		78.6		152.0
Other assets			—		1.6
	Total long-term assets		—		1.6
Assets of discontinued operations		$	78.6	$	153.6
Accounts payable and accrued liabilities		$	35.8	$	51.6
Interest payable			1.4		4.2
	Total current liabilities		37.2		55.8
Liabilities of discontinued operations		$	37.2	$	55.8

NOTE 5.    RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

Non-Trading Derivative Financial Instruments

        The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and instrument type:

			March 31, 2002			December 31, 2001
			(Unaudited)
			(in millions)
Derivatives:
	Interest rate:
		Interest rate swap/cap agreements	$	(21.9	)	$	(35.8	)
		Interest rate options		0.3			(1.0	)
	Commodity price:
		Forwards		49.2			63.8
		Futures		(7.0	)		(8.4	)
		Options		—			0.4
		Swaps		(119.9	)		(137.6	)
	Foreign currency forward exchange agreements			(0.5	)		(0.6	)
	Cross currency interest rate swaps			16.8			27.6

        In assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions based on the market conditions and associated risks existing at each balance

8

sheet date. The fair value of commodity price contracts takes in account quoted marked prices, time value of money, volatility of the underlying commodities and other factors.

        The fair value of the electricity rate swap agreements (included under commodity price-swaps) entered into by the Loy Yang B plant has been estimated by discounting the future net cash flows resulting from the difference between the average aggregate contract price per MW and a forecasted market price per MW multiplied by the number of MW remaining to be sold under the contract.

Energy Trading

        On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our operations beyond the traditional marketing of our electric power to include trading of electricity and fuels. In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchases contracts and manage our exposure through a value at risk analysis as described further below. We also conduct price risk management activities with third parties not related to our power plants or investments in energy projects, including the restructuring of power sales and power supply agreements.

        The fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of March 31, 2002 and December 31, 2001, which include energy commodities, are set forth below (in millions):

	March 31, 2002				December 31, 2001
	Assets		Liabilities		Assets		Liabilities
	(Unaudited)
Forward contracts	$	98.3	$	4.8	$	4.6	$	2.9
Futures contracts		—		—		0.1		0.1
Option contracts		0.5		0.2		—		—
Swap agreements		10.4		10.5		0.2		—
Total	$	109.2	$	15.5	$	4.9	$	3.0

        Quoted market prices are used to determine the fair value of the financial instruments related to trading activities, except for the power sales agreement with an unaffiliated electric utility that we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We 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.

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NOTE 6.    COMMITMENTS AND CONTINGENCIES

Commercial Commitments

        The following table summarizes our consolidated commercial commitments as of March 31, 2002. Details regarding these commercial commitments are discussed in the sections following the table.

	Amount of Commitments Per Period in U.S.$
Commercial Commitments													Total Amounts Committed
	2002		2003		2004		2005		2006		Thereafter
	(in millions)
Standby letters of credit	$	37.7	$	3.4	$	26.7	$	—	$	—	$	0.5	$	68.3
Firm commitment for asset purchase		3.3		—		—		—		—		—		3.3
Firm commitments to contribute project equity		67.8		64.3		—		—		—		—		132.1
Environmental improvements at our project subsidiaries		38.6		—		—		—		—		—		38.6
Total Commercial Commitments	$	147.4	$	67.7	$	26.7	$	—	$	—	$	0.5	$	242.3

Credit Support for Trading and Price Risk Management Activities

        Our domestic trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc. As part of obtaining an investment grade rating for this subsidiary, we have entered into a support agreement, which commits us to contribute up to $300 million in equity to Edison Mission Marketing & Trading, if needed, to meet cash requirements. An investment grade rating is an important benchmark used by third parties when deciding whether or not to enter into master contracts and trades with Edison Mission Marketing & Trading. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. Currently we provide a parent company guaranty by Edison Mission Energy to support Edison Mission Marketing & Trading's contracts. If we do not maintain an investment grade rating or if other events adversely affect our financial position, a third party could request us to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against us for any losses.

        Our trading and price risk management activity has been adversely affected by a number of factors, including the bankruptcy filing of Enron, increased concern regarding the liquidity of independent power companies, decrease in market prices in U.S. wholesale energy markets, and risk factors related to our business, which have limited our trading and price risk management activities. It is not certain that market conditions or risks related to our business will change to allow us to be able to conduct trading and price risk management activities in a manner favorable to us.

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Firm Commitment for Asset Purchase

Project	Local Currency	U.S. Currency
		(in millions)
Italian Wind(i)	7 billion Italian Lira	$	3.3

(i)

The Italian Wind projects are a series of power projects that are in operation or under development in Italy. Our wholly-owned subsidiary owns a 50% interest. Purchase payments will continue through 2002, and the amount will depend on the number of projects that are ultimately developed.

Firm Commitments to Contribute Project Equity

Project	U.S. Currency
	(in millions)
CBK(i)	$	45.3
Sunrise(ii)	$	86.8

(i)

CBK is a 728 MW hydroelectric power project under construction in the Philippines. At March 31, 2002, 336 megawatts have been commissioned and are operational. Our wholly-owned subsidiary owns a 50% interest. Equity is to be contributed through December 2003 commencing after full draw down of the project's debt facility, which is currently scheduled for late 2002. This equity commitment could be accelerated if our credit rating were to fall below investment grade. We were notified that the contractor responsible for engineering, procurement, and construction of the project required an adjustment in the construction payment schedule in order to meet its obligations to major suppliers and subcontractors. The project lenders and sponsors agreed on an adjustment to the loan drawdown schedule, including a one-time special draw in December 2001 to cover amounts owing to suppliers and subcontractors for work already completed. The agreement with the project's lenders required that 50% of the special draw amount be funded by the project sponsors (our share of which was $10 million).

(ii)

The Sunrise project consists of two phases, with Phase I, a simple-cycle gas-fired facility (320 MW) that commenced commercial operation in June 2001, and Phase II, conversion to a combined-cycle gas-fired facility (560 MW) currently scheduled to be completed in July 2003. Our wholly-owned subsidiary owns a 50% interest. Equity will be contributed to fund the construction of Phase II. The amount set forth in the above table assumes the partners will contribute equity for the entire construction cost. The project intends to obtain project financing for a portion of the capital costs, which if obtained would reduce our equity contribution obligation. Project financing is subject to a number of uncertainties, including the matters related to the power purchase agreement with the California Department of Water Resources. See "—Contingencies—Regulatory Developments Affecting Sunrise Power Company."

        Firm commitments to contribute project equity could be accelerated due to events of default as defined in the non-recourse project financing facilities.

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Contingencies

Paiton

        Our wholly-owned subsidiary owns a 40% interest in PT Paiton Energy, which owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia, which is referred to as the Paiton project. Under the terms of a long-term power purchase agreement between Paiton Energy and PT PLN, the state-owned electric utility company, PT PLN is required to pay for capacity and fixed operating costs since each unit and the plant have achieved commercial operation.

        PT PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN ($456 million at December 31, 2001) and the settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the terms of the power purchase agreement from 2029 to 2040. Paiton Energy and PT PLN are continuing negotiations on an amendment to the power purchase agreement that will include the agreed commercial terms in the Binding Term Sheet, with the aim of concluding those negotiations by June 30, 2002. The Binding Term Sheet serves as the basis under which PT PLN will pay Paiton Energy beginning January 1, 2002. The Binding Term Sheet will expire on June 30, 2002 unless extended by mutual agreement. Previously, PT PLN and Paiton Energy entered into a Phase I Agreement (covering January 1 to June 30, 2001), a Phase II Agreement (covering July 1 to September 30, 2001) and a Phase III Agreement (covering October 1 to December 31, 2001). PT PLN has made all payments to Paiton Energy as required under these agreements, which are superseded by the Binding Term Sheet. Paiton Energy is continuing to generate electricity to meet the power demand in the region. PT PLN has paid invoices for the months of January and February 2002, as well as the restructure settlement payments due for those months. Paiton Energy believes that PT PLN will continue to make payments for electricity under the Binding Term Sheet while negotiations on the amendment to the power purchase agreement continue. Although completion of negotiations may be delayed beyond June 30, 2002, Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful.

        Our investment in the Paiton project increased to $510.9 million at March 31, 2002 from $492.1 million at December 31, 2001. The increase in the investment account resulted from our subsidiary recording its proportionate share of net income from Paiton Energy as well as its proportionate share of other comprehensive income. Our investment in the Paiton project will increase (decrease) from earnings (losses) from Paiton Energy and decrease by cash distributions. Assuming Paiton Energy remains profitable, we expect the investment account will increase during the next several years as earnings are expected to exceed cash distributions.

        Under the Binding Term Sheet, past due accounts receivable due under the original power purchase agreement are to be compensated through a restructure settlement payment in the amount of US$4 million per month for a period of 30 years. If the power purchase agreement amendment is not completed within reasonable time frames acceptable to Paiton Energy, the parties would be entitled to revert back to the terms and conditions of the original power purchase agreement in order to pursue arbitration in the international courts.

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        Paiton Energy and PT PLN are currently negotiating an amendment to the power purchase agreement which will incorporate the terms and conditions of the Binding Term Sheet into the power purchase agreement. Entering into this agreement has been approved by the project lenders. Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior debt which takes into account the revised payment terms contained in the Binding Term Sheet. The outcome of these negotiations is uncertain at the present time. However, we believe that we will ultimately recover our investment in the project.

Brooklyn Navy Yard

        Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the power plant would be accounted for as an addition to the power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of up to $10 million over an initial amount, including legal fees, payable from its management and royalty fees. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations. We are currently offering our interest in the Brooklyn Navy Yard project for sale.

ISAB

        In connection with the financing of the ISAB project, we have guaranteed for the benefit of the banks financing the construction of the ISAB project our subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $39 million. The amount of payment under the obligation is contingent upon the outcome of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. On April 19, 2002, the arbitration tribunal issued a partial award on liability dismissing 11 of the contractor's 15 original claims. The tribunal found there was a legal and factual basis for a "slight extension" of the guaranteed completion date and a "slight indemnification" of the contractor in relation to two other relatively minor claims. Certain additional claims are still to be heard by the tribunal on a date to be agreed by the parties or as otherwise directed by the tribunal.

Regulatory Developments Affecting Sunrise Power Company

        Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission against all sellers of long-term

13

contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. Sunrise filed a motion to dismiss with the Federal Energy Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion, and both the California Public Utilities Commission and the California Electricity Oversight Board have filed responses to the motions of Sunrise and other defendants. On April 25, 2002, the Federal Energy Regulatory Commission denied Sunrise's motion to dismiss the complaints and set hearings on the contracts executed prior to June 20, 2001, but was silent as to what, if any, actions it intended to take with respect to contracts, including the Sunrise contract, executed after that date. Sunrise has filed a motion seeking confirmation from the Federal Energy Regulatory Commission that it does not intend to review contracts executed after June 20, 2001 or, in the alternative, requesting a rehearing regarding the denial of its motion to dismiss.

        On May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Los Angeles Superior Court against the California Department of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the consultants involved in the negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all of the contracts entered into in 2001, as well as all of the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with a copy of the complaint.

Indemnities

Subsidiary Indemnification Agreements

        Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these indemnification agreements as of March 31, 2002, if payment were required, would be $226.2 million. We have no reason to believe that the projects will either terminate their performance or reduce their electric power producing capability during the term of the power contracts.

Other Indemnities

        In support of the business of our subsidiaries, we have, from time to time, entered into guarantees and indemnity agreements with respect to our subsidiaries' obligations such as debt service, fuel supply or the delivery of power, and have also entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We have also, from time to time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have indemnified the previous owners of the Illinois Plants, the Homer

14

City facilities and the EcoEléctrica facilities for specified liabilities, including environmental liabilities, incurred as a result of their prior ownership of the plants. We do not believe these indemnification obligations will have a material impact on us.

Tax Indemnity Agreements

        In connection with the sale-leaseback transactions that we have entered into related to the Collins Station, Powerton and Joliet plants in Illinois and the Homer City facilities in Pennsylvania, we have entered into tax indemnity agreements. Under these tax indemnity agreements, we have agreed to indemnify the equity investors in the sale-leaseback transactions for specified adverse tax consequences. The potential indemnity obligations under these tax indemnity agreements could be significant. However, we believe it is not likely that an event requiring material tax indemnification will occur under any of these agreements.

Additional Gas-Fired Generation

        Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago. The acquisition documents require that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected Network (generally referred to as MAIN) region and the improved reliability of power generation in the Chicago area, we have undertaken preliminary discussions with Exelon Generation regarding alternatives to construction of 500 MW of capacity which we do not believe is needed at this time. If we were to install this additional capacity, we estimate that the cost could be as much as $320 million.

Contingent Obligations to Contribute Project Equity

Project	Local Currency	U.S. Currency
		(in millions)
Paiton(i)	—	$	5.3
ISAB (ii)	86 billion Italian Lira	$	38.6

(i)

Contingent obligations to contribute additional project equity will be based on events principally related to insufficient cash flow to cover interest on project debt and operating expenses, project cost overruns during the plant construction, specified partner obligations or events of default. Our obligation to contribute contingent equity will not exceed $141 million, of which $136 million has been contributed as of March 31, 2002.

For more information on the Paiton project, see "—Paiton" above.

(ii)

ISAB is a 512 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. Our wholly-owned subsidiary owns a 49% interest. Commercial operations commenced in April 2000. Contingent obligations to contribute additional equity to the project relate specifically

15

to an agreement to provide equity assurances to the project's lenders depending on the outcome of the contractor claim arbitration.

For more information on the ISAB project, see "—ISAB" above.

        We are not aware of any other significant contingent obligations or obligations to contribute project equity.

Environmental

        We believe that we are in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that we would be able to recover increased costs from our customers or that our financial position and results of operations would not be materially affected.

NOTE 7.    BUSINESS SEGMENTS

        We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific, and Europe and Middle East. Our plants are located in different geographic areas, which mitigate the effects of regional markets, economic downturns or unusual weather conditions.

Three Months Ended	Americas			Asia Pacific		Europe and Middle East		Corporate/ Other			Total
						(Unaudited) (in millions)
March 31, 2002
Operating revenues	$	303.4		$	154.2	$	152.1	$	—		$	609.7
Operating income (loss)		(19.5	)		54.7		51.4		(41.0	)		45.6
Total assets	$	4,783.1		$	3,209.2	$	2,024.0	$	595.7		$	10,612.0
March 31, 2001
Operating revenues	$	408.7		$	48.8	$	127.9	$	0.9		$	586.3
Operating income (loss)		74.8			25.6		41.4		(28.4	)		113.4
Total assets	$	6,605.7		$	2,159.3	$	4,859.0	$	485.3		$	14,109.3

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NOTE 8.    INVESTMENTS

        The following table presents summarized financial information of the significant subsidiary investments in energy projects accounted for by the equity method. The significant subsidiary investments include the Cogeneration Group. The Cogeneration Group consists of Kern River Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, of which we own 50 percent, 50 percent and 49 percent interests, respectively.

	Three Months Ended March 31,
	2002		2001
	(Unaudited) (in millions)
Operating revenues	$	108.3	$	376.2
Operating income		5.5		79.9
Net income		8.4		79.9

        The following table presents summarized financial information of the significant subsidiary investment in oil and gas accounted for by the equity method. The significant subsidiary is Four Star Oil & Gas Company, of which we own 37 percent.

	Three Months Ended March 31,
	2002		2001
	(Unaudited) (in millions)
Operating revenues	$	56.7	$	112.2
Operating income		27.5		86.7
Net income		17.5		56.8

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

The following discussion contains forward-looking statements. These statements are based on our current plans and expectations and involve risks and uncertainties which could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. Unless otherwise indicated, the information presented in this section is with respect to Edison Mission Energy and our consolidated subsidiaries.

The Management's Discussion and Analysis of Results of Operations and Financial Condition of this Form 10-Q should be read along with the Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001. This Management's Discussion and Analysis of Results of Operations and Financial Condition refers to specified portions of Edison Mission Energy's Management's Discussion and Analysis of Results of Operations and Financial Condition for the year ended December 31, 2001.

General

        We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States.

        As of March 31, 2002, we owned interests in 28 domestic and 49 international operating power projects with an aggregate generating capacity of 23,605 MW, of which our share was 18,854 MW. At that date, one domestic and six international projects, totaling 985 MW of generating capacity, of which our anticipated share will be approximately 584 MW, were under construction. At March 31, 2002, we had consolidated assets of $10.6 billion and total shareholder's equity of $1.6 billion.

Disposition of Investments in Energy Projects

        During the first quarter of 2002, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project. Proceeds received from the sales were $44 million. During the second half of 2001, we recorded asset impairment charges of $32.5 million related to these projects based on the expected sales proceeds. No gain or loss on the sales was recorded during the first quarter of 2002.

        We are currently offering for sale our interests in the Brooklyn Navy Yard, EcoEléctrica, and Gordonsville projects. A number of independent power producers have announced plans to sell assets which, together with general market conditions affecting independent power producers during the past year, have adversely affected the market value of power plants. Management has not made a decision to sell these projects.

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RESULTS OF OPERATIONS

        Operating revenues are derived from our majority-owned domestic and international entities. Equity in income from investments relates to energy projects where our ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which we have a significant influence but in which we do not have a controlling interest. With respect to entities accounted for under the equity method, we recognize our proportional share of the income or loss of such entities.

        As an aid in an understanding of our results of operations, the following table summarizes revenues and operating income from our major projects (in millions):

			Three Months Ended March 31,
			2002				2001
Projects		Business Segment
			Amount			%(1)	Amount			%(1)
			(Unaudited)
Operating revenues:
	Illinois Plants	Americas	$	163.8		27	$	175.8		30
	Homer City facilities	Americas		85.5		14		128.5		22
	Big 4 projects(2)	Americas		6.5		1		40.2		7
	First Hydro	Europe		83.7		14		68.2		12
	Four Star(3)	Americas		7.5		1		38.2		7
Operating income:
	Illinois Plants	Americas	$	(57.9	)		$	(66.8	)
	Homer City facilities	Americas		2.4				54.8
	Big 4 projects(2)	Americas		6.5				40.2
	First Hydro	Europe		23.8				26.7
	Four Star(3)	Americas		7.2				37.8

(1)

Represents percentage of our consolidated operating revenues or operating income of these projects before Corporate general and administrative expenses, interest and other expenses not reflected in our regional operations, as applicable. The operating income of each major project varies on a quarterly basis, with losses expected from the Illinois Plants during the fall and winter months. Accordingly, on a quarterly basis the operating income of each of the above projects as a percentage of our consolidated operating income is not meaningful.

(2)

Comprised of investments in Kern River project, Midway-Sunset project, Sycamore project and Watson project. These projects are recorded on the equity method of accounting which means that we record our share of the income or loss from each partnership.

(3)

Four Star is comprised of our proportionate share of the income from Four Star Oil and Gas Company and price risk management activities described under "Americas" below.

        We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic regions: Americas, Asia-Pacific and Europe and Middle East. The following discussion of our operating results is set forth by region with reference to the performance of our major projects described above.

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Americas

		Three Months Ended March 31,
		2002			2001
		(Unaudited) (in millions)
Operating revenues		$	258.9		$	307.5
Net gains from energy trading and price risk management			18.2			18.9
Equity in income from investments			26.3			82.3
	Total operating revenues		303.4			408.7
Fuel and plant operations (including plant operating leases)			282.5			288.7
Depreciation and amortization			34.2			39.4
Administrative and general			6.2			5.8
	Operating income (loss)	$	(19.5	)	$	74.8

Operating Revenues

        Operating revenues decreased $48.6 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 decrease primarily resulted from lower electric revenues from the Homer City facilities due to decreased generation and lower energy prices. On February 10, 2002, we experienced a major unplanned outage due to damage to the selective catalytic reduction system of one of the units at the Homer City facilities, known as Unit 3. The unit was restored to operation on April 4, 2002 and is operating with the selective catalytic reduction system bypassed. Reconnection of the selective catalytic reduction system will be implemented at a later date in accordance with an outage plan to be developed.

        Electric power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company. Exelon Generation is obligated to make capacity payments for the plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $161 million and $165 million for the three-month periods ended March 31, 2002 and 2001, respectively. This represented 26% and 28% of our consolidated operating revenues in 2002 and 2001, respectively. For more information on these power purchase agreements, see "—Market Risk Exposures—Illinois Plants."

        Net gains (losses) from energy trading activities were $16.5 million and $(4.1) million for the first quarter of 2002 and 2001, respectively. During the first quarter of 2002, we completed the restructuring of a power sales agreement with an unaffiliated electric utility. As part of the transaction, we purchased the power sales agreement held by a third party, modified its terms and conditions, and entered into a long-term year power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over their term, we have recorded during the first quarter of 2002 net gains of $15.3 million attributable to their fair value at inception in accordance with EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (generally referred to as mark to market accounting). See "—Liquidity and Capital Resources—Subsidiary Financing Plans" for a discussion of the non-recourse debt incurred to finance the purchase of the power sales agreement. The net losses from energy trading activities during the first quarter of 2001 were due to a decrease in West Coast energy prices reducing the fair market value of the related contracts.

        Net gains (losses) from price risk management activities recorded at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), were $1.7 million and $23 million for the first quarter of 2002 and 2001,

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respectively. The gains in 2001 were primarily due to realized and unrealized gains for a gas swap purchased to hedge a portion of our gas price risk related to our share of gas production in Four Star, an oil and gas company in which we have a minority interest and which we account for under the equity method. During the first quarter of 2001, we recorded a gain on these gas swaps of $17.4 million due to a decrease in gas prices. We have not entered into hedge transactions related to the gas price risk of our investment in Four Star for 2002 or beyond. In addition, during the first quarter of 2001, we recorded a gain of $5.5 million resulting from the change in market value of future contracts entered into with respect to a portion of our anticipated fuel purchases through 2002 at the Illinois Plants that did not qualify for hedge accounting under SFAS No. 133.

        Equity in income from investments decreased $56 million during the first quarter of 2002, compared to the same prior year period. The 2002 decrease was primarily the result of lower earnings from cogeneration projects due to lower energy pricing and lower revenues from oil and gas investments due to lower gas prices.

        Due to warmer weather during the summer months, electric revenues generated from the Homer City facilities and the Illinois Plants are usually higher during the third quarter of each year. In addition, our third quarter equity in income from investments in energy projects is materially higher than other quarters of the year due to higher summer pricing under contracts held by our West Coast partnership investments.

Operating Expenses

        Fuel and plant operations, including plant operating leases, decreased $6.2 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 decrease in fuel expense of $27.7 million resulted from lower fuel costs at the Homer City facilities due to decreased generation during the first quarter of 2002, as compared to the first quarter of 2001, when the facilities experienced the major unplanned outage at Unit 3. In addition, fuel costs were lower at the Illinois Plants during the first quarter of 2002 due to lower fuel costs at the Collins Station as compared to the first quarter of 2001.

        Partially offsetting the 2002 decrease in fuel expense was an increase in plant operating leases of $16.6 million during the first quarter of 2002, as compared to the first quarter of 2001, resulting primarily from lease costs related to the sale-leaseback commitments for the Homer City facilities. There were no comparable lease costs for the Homer City facilities during the first quarter of 2001.

        Depreciation and amortization expense decreased $5.2 million for the first quarter of 2002, compared to the same prior year period. The 2002 decrease resulted from lower depreciation expense at the Homer City facilities related to the sale-leaseback transaction for the Homer City facilities to third-party lessors in December 2001.

        Administrative and general expenses consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts. There were no material changes in the first quarter 2002 administrative and general expenses from the first quarter of 2001.

Operating Income

        Operating loss totaled $19.5 million during the first quarter of 2002, compared to operating income of $74.8 million during the first quarter of 2001. The 2002 decrease was primarily due to lower operating income of $52.4 million from the Homer City facilities resulting from the major unplanned outage at Unit 3, lower equity in income from investments in energy projects and lower equity in income from oil and gas investments discussed above.

        We believe that the costs to repair the damage to Unit 3 at Homer City should be covered by insurance and by contractual obligations of the contractor who installed the selective catalytic reduction

21

system. We have completed a preliminary investigation of the event; however, a more in-depth analysis of the root causes of the event will be required to determine the extent to which insurers and/or the contractor will cover the resulting costs of property damage and repair.

Asia-Pacific

		Three Months Ended March 31,
		2002			2001
		(Unaudited) (in millions)
Operating revenues		$	141.0		$	46.2
Net losses from energy trading and price risk management			(1.1	)		(0.5	)
Equity in income from investments			14.3			3.1
	Total operating revenues		154.2			48.8
Fuel and plant operations			85.3			15.0
Depreciation and amortization			14.2			8.2
	Operating income	$	54.7		$	25.6

Operating Revenues

        Operating revenues increased $94.8 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due to consolidating Contact Energy operating revenues as a result of our increase in ownership to 51.2% majority-control in the company, effective June 1, 2001.

        Net losses from price risk management activities recorded at fair value were $1.1 million and $0.5 million for the first quarter of 2002 and 2001, respectively. The losses primarily represent the ineffective portion of a long-term contract with the State Electricity Commission of Victoria entered into by the Loy Yang B plant, which is a derivative that qualified as a cash flow hedge under SFAS No. 133. See "—Note 3. Accumulated Other Comprehensive Income (Loss)," for further discussion.

        Equity in income from investments increased $11.2 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase is primarily due to an increase in our share of income from the Paiton project of $13.5 million. Beginning January 1, 2002, Paiton Energy recorded revenue in accordance with the Binding Term Sheet, which is described in more detail under "—Note 6. Commitments and Contingencies—Contingencies—Paiton." Revenue recognized under the Binding Term Sheet is comprised of capacity payments (based on the availability of the power plant) and energy payments (based on electricity generated). Recognition of revenue on the basis of the Binding Term Sheet resulted in a net profit by Paiton Energy for the three months ended March 31, 2002. Prior to the execution of the Binding Term Sheet, we assumed the lower end of a range of expected outcomes of negotiations of a revised power purchase agreement, which resulted in no recognition of income during the three months ended March 31, 2001. Partially offsetting this increase in 2002 was a decrease in earnings from Contact Energy reflecting Contact Energy being accounted for on a consolidated basis effective June 1, 2001, compared to the equity method of accounting utilized by us prior to our acquisition of a controlling interest in the company.

Operating Expenses

        Fuel and plant operations increased $70.3 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due to the consolidation of Contact Energy operating expenses, effective June 1, 2001.

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        Depreciation and amortization expense increased $6 million for the first quarter of 2002, compared to the first quarter of 2001. The increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses, effective June 1, 2001.

Operating Income

        Operating income increased $29.1 million during the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due to consolidation of Contact Energy's results of operations, effective June 1, 2001, and higher equity in income from investments discussed above.

Europe and Middle East(1)

		Three Months Ended March 31,
		2002		2001
		(Unaudited) (in millions)
Operating revenues		$	135.8	$	130.6
Net gains (losses) from energy trading and price risk management			4.3		(1.9	)
Equity in income (loss) from investments			12.0		(0.8	)
	Total operating revenues		152.1		127.9
Fuel and plant operations			91.5		75.6
Depreciation and amortization			9.2		10.9
	Operating income	$	51.4	$	41.4

(1)

The results of Ferrybridge and Fiddler's Ferry are not included in this table since the operations are classified as discontinued operations for all historical periods presented. For more information on Ferrybridge and Fiddler's Ferry, see "—Discontinued Operations."

Operating Revenues

        Operating revenues increased $5.2 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase resulted primarily from higher electric revenues from the First Hydro plant due to favorable ancillary services revenues, increased generation and sales of purchased power during the first quarter of 2002, compared to the same prior year period. On March 27, 2001, the United Kingdom pool pricing system was replaced with a bilateral physical trading system referred to as the new electricity trading arrangements, generally referred to as NETA. The new electricity trading arrangements are described in further detail under "—Market Risk Exposures—United Kingdom." As a result of the bilateral market under the new electricity trading arrangements, First Hydro has entered in greater volumes of power purchase and power sale contracts to optimize the timing of generation from First Hydro pump storage plants. The First Hydro plant and the Iberian Hy-Power plant are expected to provide for higher electric revenues during the winter months.

        Net gains (losses) from price risk management activities recorded at fair value were $4.3 million and ($1.9) million for the first quarter of 2002 and 2001, respectively. The 2002 gains primarily represent the change in market value of long-term commodity contracts entered into by the First Hydro plant for the purchase and sale of electricity that were recorded at fair value under SFAS No. 133 with changes in fair value recorded through the income statement, effective July 1, 2001.

        Equity in income from investments increased $12.8 million during the first quarter of 2002, compared to the same prior year period. The 2002 increase was due to higher profitability of our

23

interest in the ISAB project resulting from increased generation and settlement of an insurance claim. During the first quarter of 2001, we recorded losses from this project.

Operating Expenses

        Fuel, including purchased power, and plant operations increased $15.9 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due to higher purchased power at the First Hydro plant. This increase reflects the changes under the new electricity trading arrangements, whereby First Hydro has purchased electricity to meet sales commitments when it was more cost-effective to purchase than to generate electricity, thus, reducing the need for physical pumping or generating. In addition, due to the new trading arrangements, some costs previously paid by suppliers now are being paid by generators and all market participants are being charged imbalance costs when their metered position differs from their contracted position. The new electricity trading arrangements are described in further detail under "—Market Risk Exposures—United Kingdom."

Operating Income

        Operating income increased $10 million during the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was due to equity in income from investments discussed above.

Corporate/Other

		Three Months Ended March 31,
		2002			2001
		(Unaudited) (in millions)
Revenues:
Net gains from energy trading and price risk management		$	—		$	0.9
Expenses:
Depreciation and amortization			2.1			2.8
Long-term incentive compensation			1.7			(3.7	)
Administrative and general			37.2			30.2
	Operating loss	$	(41.0	)	$	(28.4	)

        Net gains from price risk management activities recorded at fair value were $0.9 million for the first quarter of 2001. The gains primarily resulted from the change in market value of our interest rate swaps with respect to our $100 million senior notes that did not qualify for hedge accounting under SFAS No. 133.

        Long-term incentive compensation expense consists of charges related to our terminated phantom option plan. The 2002 compensation expense is related to the annual vesting of benefits. During the first quarter of 2001, an adjustment was made to reflect the decrease in market value of stock equivalent units.

        Administrative and general expenses increased $7 million for the first quarter of 2002, compared to the same prior year period. The 2002 increase was primarily due to a pretax charge of approximately $4.1 million against first quarter earnings for severance and other related costs. The charge resulted from a series of actions undertaken by us designed to reduce administrative and general operating costs, including reductions in management and administrative personnel.

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Other Income (Expense)

        Interest and other income (expense) decreased $1.4 million for the first quarter of 2002, compared to the first quarter of 2001. The decrease was primarily due to lower interest income.

        Interest expense decreased $12.5 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 decrease was due to a combination of the following: a reduction in corporate debt from the proceeds of the sale-leaseback of the Homer City facilities in December 2001 and lower borrowings combined with lower interest rates on variable rate debt tied to LIBOR; partially offset by higher cost borrowings during the second and third quarters of 2001 and higher interest margins on our corporate line of credit.

Provision (Benefit) for Income Taxes

        During the first quarter of 2002, we recorded an effective tax benefit rate of 52% based on projected income for the year and benefits under our tax-allocation agreement, compared to the annual effective tax provision rate for the first quarter of 2001 of 37%. The effective tax rate increased as a result of a decrease in anticipated income from operations in the United Kingdom.

        We are, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions we take in connection with the filing of our 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 our opinion, it is unlikely that the resolution of any such matters will have a material adverse effect upon our financial condition or results of operations.

Minority Interest

        Minority interest expense increased $4.9 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that increased our ownership interest from 42.6% to a controlling interest of 51.2%.

Discontinued Operations

        As a result of the change in the prices of power in the U.K. and the anticipated negative impacts of such changes on earnings and cash flow, we offered for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.

        Effective January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges under SFAS No. 133. We could not conclude, based on information available at January 1, 2001, that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

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Cumulative Effect of Change in Accounting Principle

Accounting for Derivatives and SFAS No. 133

        Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates. We manage these risks in part by using derivative financial instruments in accordance with established policies and procedures. Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

        Effective January 1, 2001, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the documentation requirements of SFAS No. 133 are met.

        Accounting for derivatives under SFAS No. 133 is complex. Each transaction requires an assessment of whether it is a derivative according to the definition under SFAS No. 133, including amendments and interpretations. Transactions that do not meet the definition of a derivative are accounted by us on the accrual basis, unless they relate to our trading operations, in which case they are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, either do not meet the definition of a derivative or qualify for the normal purchases and sales exception.

        As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under the prior accounting policy.

Discussion of Initial Adoption of SFAS No. 133

        On January 1, 2001, we recorded a $0.2 million, after tax, increase to income from continuing operations and a $230.2 million, after tax, decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. The following material items were recorded at fair value:

•

The forward sales contracts from our Homer City facilities qualified as cash flow hedges. We did not use the normal sales and purchases exception for these forward sales contracts due to our net settlement procedures with counterparties through June 30, 2001. As a result of higher market prices for forward sales from our Homer City facilities, we recorded a liability of $115.9 million at January 1, 2001, deferred tax benefits of $54.1 million and a decrease in other comprehensive income of $61.8 million. Based on guidance provided by the Derivative Implementation Group of the Financial Accounting Standards Board, our Homer City forward sales contracts qualified for the normal sales and purchases exception, commencing July 1, 2001. See "New Accounting Standards" for discussion regarding further change in accounting for these contracts.



•

The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia qualified as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of

26

the contract occurs without physical delivery. As a result of higher market prices for forward sales from our Loy Yang B plant, we recorded a liability of $227 million at January 1, 2001, deferred tax benefits of $68.1 million and a decrease in other comprehensive income of $158.9 million.

•

The majority of our activities related to the fuel contracts for our Collins Station in Illinois did not qualify for either the normal purchases and sales exception or as cash flow hedges. We could not conclude, based on information available at January 1, 2001, that the timing of generation from the Collins Station met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, these contracts were recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement. We have continued to record fuel contracts for our Collins Station at fair value.

        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. We recorded a net gain (loss) of approximately $(734,000) and $155,000 during the first quarter of 2002 and 2001, respectively, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.

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LIQUIDITY AND CAPITAL RESOURCES

        At March 31, 2002, we had cash and cash equivalents of $368.6 million and had available a total of $694.3 million of borrowing capacity under our $750 million corporate credit facility. The credit facility includes a one-year $538.3 million component, Tranche A, that expires on September 17, 2002 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. The credit facility provides credit available in the form of cash advances or letters of credit. At March 31, 2002, there were no cash advances outstanding under either Tranche and $55.7 million of letters of credit outstanding under Tranche B. In addition to the interest payments, we pay a facility fee as determined by our long-term credit ratings (0.625% and 0.75% at March 31, 2002 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings. See "—Corporate Financing Plans."

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

        Net cash provided by (used in) operating activities:

	Three Months Ended March 31,
	2002			2001
	(Unaudited) (in millions)
Continuing operations	$	18.5		$	(170.8	)
Discontinued operations		(7.2	)		32.6
	$	11.3		$	(138.2	)

        The higher operating cash flow from continuing operations in 2002, compared to 2001, reflects higher distributions from energy projects. In March 2002, we received distributions from our investments in partnerships subsequent to their receipt of payments of past due accounts receivable from Southern California Edison. Lower distributions from energy projects in 2001 primarily resulted from the delay in payments from the California utilities to our investments in California qualifying facilities. The change in operating cash flow from continuing operations in 2002 was also due to the timing of cash payables related to working capital items. Net working capital at March 31, 2002 was $507.1 million compared to $324.6 million at December 31, 2001.

        Cash provided by operating activities from discontinued operations in 2001 reflects operating gains from the Ferrybridge and Fiddler's Ferry power plants during the first quarter of 2001.

Cash Flows From Financing Activities

        Net cash provided by (used in) financing activities:

	Three Months Ended March 31,
	2002			2001
	(Unaudited) (in millions)
Continuing operations	$	(30.5	)	$	171.6
Discontinued operations		—			(280.2	)
	$	(30.5	)	$	(108.6	)

        Cash used in financing activities from continuing operations in 2002 consisted of net payments of $80 million on our $750 million corporate credit facility and $22 million related to Edison Mission Energy Funding Corp. In addition, a wholly-owned subsidiary borrowed $84 million under a loan

28

agreement in January 2002. For further discussion of the loan agreement, see "—Subsidiary Financing Plans." Cash provided by financing activities from continuing operations in 2001 consisted of issuances under our corporate credit facilities. As of March 31, 2002, we had recourse debt of $2 billion, with an additional $4.1 billion of non-recourse debt (debt which is recourse to specific assets or subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet.

        Cash used in financing activities from discontinued operations in 2001 was primarily related to the repayment of a loan from Edison Capital, an indirect affiliate.

Cash Flows From Investing Activities

        Net cash used in investing activities:

	Three Months Ended March 31,
	2002			2001
	(Unaudited) (in millions)
Continuing operations	$	(1.1	)	$	(225.1	)
Discontinued operations		—			(4.1	)
	$	(1.1	)	$	(229.2	)

        Cash used in investing activities from continuing operations in 2002 included $80 million paid for the purchase of a power sales agreement held by a third party. We invested $72.1 million in the first quarter of 2002 in new plant and equipment principally related to the Valley Power project in Australia, the Illinois Plants and the Homer City facilities. Also, included in 2002 capital expenditures were payments for three turbines purchased under the Edison Mission Energy Master Turbine Lease with funds from restricted cash of $61.1 million. We plan to use these turbines for a new gas-fired project. Included in 2002 investing activities was $86 million of restricted cash used to purchase the three turbines and satisfy our obligation related to the termination of the Edison Mission Energy Master Turbine Lease, thereby reducing our restricted cash account. We received proceeds of $44 million from the sales of our 50% interest in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project during the first quarter of 2002. In addition, we received $78.5 million as a return on capital from the Kern River and Sycamore projects subsequent to their receipt of payments of past due accounts receivable from Southern California Edison during the first quarter of 2002.

        Cash used in investing activities from continuing operations in 2001 included cash used by us for equity contributions totaling approximately $115 million through March 31, 2001 to meet capital calls by partnerships that were owed money by Southern California Edison and Pacific Gas and Electric, following the failure by those entities to pay amounts due for power sold under those agreements. Southern California Edison repaid all outstanding amounts on March 1, 2002, and Pacific Gas and Electric is making payments against defaulted amounts on a schedule that should allow for payment in full by the end of the first quarter of 2003. In addition, we paid $20 million as part of the purchase of our 50% interest in the CBK project. We also invested $75 million in the first quarter of 2001 in new plant and equipment principally related to the Homer City facilities and the Illinois Plants.

Corporate Financial Ratios

        In assessing our leverage as a holding company and our ability to meet debt service obligations, we and our principal bank lenders use two primary ratios: a recourse debt to recourse capital ratio and an interest coverage ratio. These ratios are determined in accordance with financial covenants that have been included in our corporate credit facilities and are not determined in accordance with generally accepted accounting principles as reflected in our Consolidated Statements of Cash Flows. Accordingly, these ratios should not be considered in isolation or as a substitute for cash flows from operating

29

activities or cash flow statement data set forth in our Consolidated Statement of Cash Flows. While the ratios included in our corporate credit facilities measure the leverage and ability of Edison Mission Energy to meet its debt service obligations, they do not measure the liquidity or ability of our subsidiaries to meet their debt service obligations. Furthermore, these ratios are not necessarily comparable to other similarly titled captions of other companies due to differences in methods of calculations.

        Our corporate credit facilities include covenants tied to these financial ratios(1):

Financial Ratio	Covenant	Actual at March 31, 2002	Description
Recourse Debt to Recourse Capital Ratio	Less than or equal to 67.5%	63.1%	Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per our balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse debt
Interest Coverage Ratio	Greater than or equal to 1.50 to 1.00	1.74 to 1.00	For prior 12-month period, ratio of (a) funds flow from operations to (b) interest expense on senior recourse debt

(1)

Our corporate credit facilities and corporate debt securities include a Tangible Net Worth Covenant, which is determined based on our shareholder's equity adjusted for changes in other comprehensive income after December 31, 1999. At March 31, 2002, our tangible net worth as determined in accordance with the covenant was $948.2 million, which exceeds the covenant requirement of $613.8 million.

        At March 31, 2002, we met the above financial covenants. The actual interest coverage ratio during 2001 and the twelve months ended March 31, 2002 was adversely affected by the operating results of the Ferrybridge and Fiddler's Ferry projects in the United Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was 2.03 to 1 for the twelve months ended March 31, 2002. Compliance with these covenants is subject to future financial performance, including items that are beyond our control.

        Our interest coverage ratio for the four quarters ended March 31, 2002 was 1.74 to 1. Accordingly, under the "ring-fencing" provisions of our articles of incorporation and bylaws, until our interest coverage ratio exceeds 2.2 to 1 for the immediately preceding four quarters, we can only pay dividends if we have an investment grade rating and have received rating agency confirmation that a dividend will not result in a downgrade or have received unanimous approval of our board of directors, including our independent director. We have not paid or declared a dividend to Mission Energy Holding Company during the first quarter of 2002.

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Discussion of Recourse Debt to Recourse Capital Ratio

        The recourse debt to recourse capital ratio of Edison Mission Energy at March 31, 2002 and December 31, 2001 was calculated as follows:

		March 31, 2002		December 31, 2001
		(Unaudited)
		(in millions)
Recourse Debt(1)
	Corporate Credit Facilities	$	63.7	$	203.6
	Senior Notes		1,700.0		1,700.0
	Guarantee of termination value of Powerton/Joliet operating leases		1,412.9		1,431.9
	Coal and Capex Facility		196.6		251.6
	Other		46.2		46.3
Total Recourse Debt to Edison Mission Energy		$	3,419.4	$	3,633.4
Recourse Capital		$	2,003.6	$	2,039.0
Total Capitalization		$	5,423.0	$	5,672.4
Recourse Debt to Resource Capital Ratio			63.1%		64.1%

(1)

Recourse debt means direct obligations of Edison Mission Energy or obligations of one of its subsidiaries for which Edison Mission Energy has provided a guaranty.

        During the quarter ended March 31, 2002, the recourse debt to recourse capital ratio improved due to:

•

reduction in the utilization of our corporate credit facility. We paid off the $80 million that was outstanding at December 31, 2001 and reduced the letters of credit issued under the credit facility by $60 million; and



•

payments on the Coal and Capex facility with proceeds from Ferrybridge and Fiddler's Ferry working capital settlements that occurred after financial close of the project divestiture.

        During 2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in our shareholder's equity from $1.1 billion of after-tax losses, attributable to the loss on sale of our Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. We sold the Ferrybridge and Fiddler's Ferry power plants in December 2001 due, in part, to the adverse impact of the negative cash flow pertaining to these plants.

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Discussion of Interest Coverage Ratio

        The following table sets forth the major components of our interest coverage ratio for the twelve months ended March 31, 2002 and the year ended December 31, 2001:

				March 31, 2002			December 31, 2001
				(Unaudited)
				(in millions)
Funds Flow from Operations:
	Operating Cash Flow(1) from Consolidated Operating Projects(2):
		Illinois Plants		$	221.5		$	201.3
		Homer City			134.3			175.2
		Ferrybridge and Fiddler's Ferry			(101.9	)		(104.5	)
		First Hydro			46.0			45.9
	Other consolidated operating projects				66.5			64.1
	Trading and price risk management				33.3			28.2
	Distributions from non-consolidated Big 4 projects(3)				210.9			128.8
	Distributions from other non-consolidated operating projects				89.7			93.5
	Interest income				8.7			9.0
	Operating expenses				(151.1	)		(143.1	)
			Total funds flow from operations		557.9			498.4
Interest Expense					320.2			304.8
Interest Coverage Ratio					1.74			1.64

(1)

Operating cash flow is defined as revenues less operating expenses, foreign taxes paid and project debt service. Operating cash flow does not include capital expenditures or the difference between cash payments under our long-term leases and lease expenses recorded in our income statement. We expect our cash payments under our long-term power plant leases to be higher than our lease expense through 2014.

(2)

Consolidated operating projects are entities of which we own more than a 50% interest and, thus, include the operating results and cash flows in our consolidated financial statements. Non-consolidated operating projects are entities of which we own 50% or less and which we account for on the equity method.

(3)

The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project.

        The major factors affecting funds from operations during the twelve months ended March 31, 2002, compared to the year ended December 31, 2001, were:

•

Changes in market prices for energy and capacity and a major unplanned outage at Unit 3 related to the Homer City facilities.



•

Decline in fuel cost for the Illinois Plants.



•

As a result of the sale of the Ferrybridge and Fiddler's Ferry plants in December 2001, we did not incur negative cash flow from this project in the quarter ended March 31, 2002. However, since the interest coverage ratio test measures the prior four quarters, this project will still affect the ratio through the applicable periods ended September 30, 2002.

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•

Distributions from our investments in partnerships subsequent to their receipt of payments of past due accounts receivable from Southern California Edison.

        Interest expense increased $15.4 million during the twelve months ended March 31, 2002 from the year ended December 31, 2001 as a result of:

•

an increase in borrowing costs from refinancing short-term debt with 2001 issuances of $1 billion long-term fixed rate debt as well as higher interest margins on our corporate credit facilities; and



•

including Coal and Capex Facility interest expense as corporate interest expense after the divestiture of Ferrybridge and Fiddler's Ferry in December 2001. Prior to the sale, the interest expense was classified as part of Operating Cash Flow of this project.

Credit Ratings

        To isolate ourselves from the impact of the California power crisis on Edison International and Southern California Edison, and to facilitate our ability and the ability of our subsidiaries to maintain our respective investment grade credit ratings, on January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity. These provisions require the unanimous approval of our board of directors, including at least one independent director, before we can do any of the following:

•

declare or pay dividends or distributions unless either of the following are true: we then have an investment grade credit rating and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or the dividends do not exceed $32.5 million in any fiscal quarter and we meet an interest coverage ratio (calculated as described under "—Discussion of Interest Coverage Ratio") of not less than 2.2 to 1 for the immediately preceding four fiscal quarters.



•

institute or consent to bankruptcy, insolvency or similar proceedings or actions; or consolidate or merge with any entity or transfer substantially all our assets to any entity, except to an entity that is subject to similar restrictions.

        In January 2001, Standard & Poor's and Moody's downgraded our senior unsecured credit ratings to "BBB-" from "A-" and to "Baa3" from "Baa1," respectively. Our credit ratings remain investment grade. Maintaining our investment grade credit ratings is part of our current operational focus and our long-term strategy. However, we cannot assure you that Standard & Poor's and Moody's will not downgrade our credit rating below investment grade. If our credit ratings are downgraded below investment grade, we could be required to, among other things:

•

provide additional collateral in the form of letters of credit or cash for the benefit of counterparties in our domestic trading and price risk management activities related to accounts receivable and unrealized losses ($8.6 million at March 31, 2002); and



•

post a letter of credit or cash collateral to support our $45.3 million equity contribution obligation in connection with our acquisition in February 2001 of a 50% interest in the CBK Power Co. Ltd. project in the Philippines, which equity contribution would otherwise be payable commencing after full draw down of the debt facility currently scheduled for late 2002.

        A downgrade of our credit ratings could result in a downgrade of the credit rating of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, would limit the ability of Midwest Generation to use excess cash flow to make distributions.

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        A downgrade of our credit ratings below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and have an adverse impact on us and our subsidiaries. In addition, in order to continue to market the power from our Homer City facilities and First Hydro plants in the United Kingdom as well as purchase natural gas or fuel oil at our Illinois Plants, we may be required to provide substantial additional credit support in the form of letters of credit or cash. In addition, changes in forward market prices and margining requirements could further increase the need for credit support for our trading and risk management activities.

        Standard & Poor's and Moody's have indicated that they are reviewing the criteria for assessing credit risk for merchant energy companies (companies that generate and/or trade wholesale power without long-term contracts). The criteria used by Standard & Poor's and Moody's in assessing credit risk in turn is used to assign credit ratings, including whether or not a company is investment grade. We cannot predict whether Standard & Poor's or Moody's will change their criteria for assessing credit risk or, if changes were made, whether or not such changes would adversely affect our credit ratings.

Corporate Financing Plans

        We have a $750 million corporate credit facility which includes a one-year $538.3 million component, Tranche A, that expires on September 17, 2002 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. At March 31, 2002, we had borrowing capacity under this facility of $694.3 million and corporate cash and cash equivalents of $44.7 million. We plan to utilize the corporate credit facilities to fund corporate expenses, including interest, during 2002, as necessary depending on the timing and amount of distributions from our subsidiaries. Our first quarter 2002 cash flow includes distributions from our investments in partnerships made subsequent to their receipt of payments of past due accounts receivable from Southern California Edison on March 1, 2002. Total amounts paid to these partnerships by Southern California Edison was $415 million, of which our share was $206.2 million. In addition, we expect to receive in 2002 tax-allocation payments of our outstanding receivable of $224.4 million at March 31, 2002 from our ultimate parent company. In addition, we plan to extend Tranche A under our corporate facility or enter into a similar facility with other financial institutions by September 2002. The timing and amount of distributions from our subsidiaries may be affected by many factors beyond our control, some of which are described under "—Risk Factors" included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001.

Subsidiary Financing Plans

        The estimated capital and construction expenditures of our subsidiaries for the final three quarters of 2002 are $106.6 million. These expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City sale-leaseback agreements, we have committed to provide funds for capital expenditures needed by the power plant. We expect to contribute $17.6 million in 2002 to fund the estimated capital expenditures of this project, of which $4.9 million was contributed during the first quarter of 2002. See "—Note 6. Commitments and Contingencies."

Loan Agreement in Connection with Power Sales Agreement

        In connection with the restructuring of the power sales agreement with an unaffiliated electric utility, a wholly-owned subsidiary borrowed $84 million under a loan agreement to finance the purchase of the power sales agreement held by a third party, make a deposit under a power supply contract, and pay for transaction costs. The loan is secured by the payments from the power sales agreement and is non-recourse to us. The interest rate under the loan agreement is fixed at 7.31% and is due in

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June 2015. Principal payments under the loan agreement are $0.4 million in 2002, $0.8 million in 2003, $1.5 million in 2004, $2.2 million in 2005, $3.0 million in 2006 and $76 million due after 2006.

Intercompany Tax-Allocation Payments

        We participate in a tax-allocation agreement with The Mission Group, which in turn participates in a tax-allocation agreement with Edison International. We have historically received tax payments under the tax-allocation agreement related to domestic net operating losses incurred by us. However, we were required to pay Edison International $55 million during October 2001 primarily as a result of changes in estimated taxable income for 2000. At March 31, 2002, we have recorded $224.4 million as an income tax receivable under the tax-allocation agreement. However, we are not eligible to receive tax-allocation payments for such losses until such time as Edison International and its subsidiaries generate sufficient taxable income in order to be able to utilize our tax losses in the consolidated income tax returns for Edison International and its subsidiaries. We anticipate this will occur in 2002, and, accordingly, we expect to receive payments in 2002 of our outstanding receivable from Edison International.

Restricted Assets of Subsidiaries

        Each of our direct and indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Assets of our subsidiaries may not be available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of the subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.

Market Risk Exposures

        Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates. We manage these risks in part by using derivative financial instruments in accordance with established policies and procedures.

Commodity Price Risk

        Energy trading and price risk management activities give rise 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 to ensure compliance with our risk management policies. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the worst expected 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, we supplement this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits.

        Electric power generated at our merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term contracts with terms of two years or less, or, in the case of the Homer City facilities, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator (NYISO). Our risk management policies and procedures include an assessment of credit risk. When making sales under negotiated bilateral contracts, it is our general policy to deal with investment grade counterparties or counterparties that have equivalent

35

credit quality. Our risk management committees grant exceptions to the policy only after review and scrutiny. Most entities that have received exceptions are typically organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants, whose output is not committed to be sold under long-term contracts, in order to provide more predictable earnings and cash flow. When appropriate, we manage the spread between electric prices and fuel prices, and use forward contracts, swaps, futures, or options contracts to achieve those objectives.

        Our revenues and results of operations during the estimated useful lives of our merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, fuel oil, coal and natural gas and associated transportation costs in the market areas where our merchant plants are located. Among the factors that influence the price of power in these markets are:

•

prevailing market prices for fuel oil, coal and natural gas 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;



•

the market structure rules to be established for each market area;



•

the availability, reliability and operation of nuclear generating plants, where applicable;



•

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



•

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

        A discussion of each market area is set forth below by region.

Americas

Homer City Facilities

        Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic utilities and power marketers under short-term contracts with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets, which establish an hourly clearing price. The Homer City facilities is situated in the PJM control area and is physically connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City facilities can also transmit power to the Midwestern United States.

        The following table depicts the average markets prices per megawatt hour in PJM during the first quarters of 2002 and 2001:

	24-Hour PJM Prices*
	2002		2001
January	$	20.52	$	36.66
February		20.62		29.53
March		24.27		35.05
Quarterly Average	$	21.80	$	33.75

*

Prices are calculated using historical hourly prices provided on the PJM-ISO web-site.

        As shown on the above table, the average market prices during the first three months of 2002 are below the average market prices during the first three months of 2001. The forward market prices in PJM fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity. For

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example, during April 2002, our forecasted yearly average 24-hour PJM prices for 2002 ranged from approximately $23.25 to $31.21, compared to the actual yearly average 24-hour PJM prices of $29.07 in 2001. Our forecasted yearly average 24-hour PJM prices are based on year-to-date actual data and a forecast for the remainder of the year based on current market information.

        The ability of our subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the sale-leaseback transaction discussed under "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions," included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001, is dependent on revenues generated by the Homer City facilities, which depend on market conditions for the sale of capacity and energy. These market conditions are beyond our control.

Illinois Plants

        Electric power generated at the Illinois Plants is sold under three power purchase agreements with Exelon Generation Company, in which Exelon Generation purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production.

        Virtually all of the energy and capacity sales in the first quarter of 2002 from the Illinois Plants were made to Exelon Generation under the power purchase agreements, and is expected to continue to be sold to Exelon Generation during the remainder of 2002. In October 2001, Exelon Generation exercised the option under one of the power purchase agreements to terminate all of the oil peaker plants (300 megawatts), effective January 2002, but continued it with respect to all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.

        The energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers or into the so-called spot market. Thus, to the extent that Exelon Generation does not purchase our power for 2003 or 2004, we will be subject to the market risks related to the price of energy and capacity described above. Due to the volatility of market prices for energy and capacity during the past several years, we cannot predict whether or not Exelon Generation will elect to terminate any of the units currently subject to the power purchase agreements for which termination is permitted and, if they do, whether sales of energy and capacity to other customers and the market will be at prices sufficient to generate cash flow necessary to meet the obligations of our subsidiary. As of March 31, 2002, we had not entered into forward energy sales contracts for the Illinois Plants other than those with Exelon Generation.

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Europe and Middle East

United Kingdom

        Since 1989, our plants in the U.K. have sold their electrical energy and capacity through a centralized electricity pool, which established a half-hourly clearing price, also referred to as the pool price, for electrical energy. On March 27, 2001, this system was replaced by the U.K. government with a bilateral physical trading system referred to as the new electricity trading arrangements. In connection with the new electricity trading arrangements, the First Hydro plant entered into forward contracts with varying terms that expire on various dates through October 2003. In addition, two long-term contracts with a three-year termination provision entered into in March 1999 from the First Hydro plant to buy and sell electricity were amended as forward contracts.

        The new electricity trading arrangements provide for, among other things, the establishment of a range of voluntary short-term power exchanges and brokered markets operating from a year or more in advance to 3.5-hours before a trading period of one-half hour; a balancing mechanism to enable the system operator to balance generation and demand and resolve any transmission constraints; a mandatory settlement process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance; and a Balancing and Settlement Code Panel to oversee governance of the balancing mechanism. The grid operator retains the right under the new market mechanisms to purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary services contracts typically run for a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid operator. Physical bilateral contracts have replaced the prior financial contracts for differences, but have a similar commercial function. A key feature of the new arrangements is to require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or pay for any energy imbalance at highly volatile imbalance prices calculated by the market operator. A consequence of this new system has been to increase greatly the motivation of parties to contract in advance and to further develop forwards and futures markets of greater liquidity than at present. Furthermore, another consequence of the market change is that counterparties may require additional credit support, including parent company guarantees or letters of credit.

        The legislation introducing the new trading arrangements set a principal objective for the Gas and Electric Market Authority to "protect the interests of consumers...where appropriate by promoting competition...." This represents a shift in emphasis toward the consumer interest. However, this is qualified by a recognition that license holders should be able to finance their activities. The Utilities Act of 2000 also contains new powers for the Secretary of State to issue guidance to the Gas and Electric Market Authority on social and environmental matters, changes to the procedures for modifying licenses and a new power for the Gas and Electric Market Authority to impose financial penalties on companies for breach of license conditions. We are monitoring the operation of these new provisions.

        During 2001, our operating income from the First Hydro plant decreased $105.9 million from the prior year primarily due to the removal of a formal capacity mechanism in the new trading arrangements and the oversupply of generation in the market resulting in a sharp fall in the market value for capacity. In addition, First Hydro's operating results have been adversely impacted in the second half of 2001 by a fall in the differential of the peak daytime energy price compared to the cost of purchasing power at nighttime to pump water back to the top reservoir. Generation capacity on the U.K. system has been in excess of demand due to generators holding plant on the system at part load to protect themselves against the adverse affects of being out of balance in the new market and the mild weather experienced during 2001.

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        For the foregoing reasons, First Hydro's interest coverage ratio, when measured for the twelve-month period ended June 30, 2002, may be below the threshold set forth in its bond financing documents, although it is anticipated that current project revenues will enable the July 31, 2002 interest payment to be made without recourse to the project's debt service reserve. We believe that should market and trading conditions experienced thus far in 2002 be sustained for the balance of the year, First Hydro's interest coverage ratio will be above the required threshold when measured for the twelve-month period ended December 31, 2002. Compliance by First Hydro with these and other requirements of its bond financing documents are subject, however, to market conditions for the sale of energy and ancillary services. These market conditions are beyond our control. There is no assurance that these requirements will be met and, if not met, will be waived by the holders of First Hydro's bonds. The bond financing documents stipulate that a breach of a financial covenant constitutes an immediate event of default and, if the event of default is not waived or cured, the holders of the First Hydro bonds are entitled to enforce their security over First Hydro's assets, including its power plants.

Asia Pacific

        Australia.    The Loy Yang B plant sells its electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant has entered into a number of financial hedges. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2001 to July 2014, approximately 77% of the plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant has entered into a number of derivative contracts to further mitigate against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity contracts that expire on various dates through December 31, 2004, and a five-year electricity cap contract expiring December 31, 2006.

New Zealand. A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers and forward contracts with other wholesale electricity counterparties. Contact Energy has entered into forward contracts and option contracts of varying terms that expire on various dates through April 1, 2004 and January 31, 2004, respectively. The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. Following the inquiry report the New Zealand Government released a Government Policy Statement, at the center of which was a call for the industry to rationalize the three existing industry codes, form a single governance structure and address transmission pricing methodology. The Government Policy Statement also requested a model use of system agreement be agreed, that is a framework by which the retailers contract for services from each of the distribution networks, and a consumer complaints ombudsman be established. An essential theme throughout the Government Policy Statement was the desire that the industry retain a private multilateral self-governing structure. During 2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed the Government's call. Progress on the single governance code is well underway and the Chairs of the three existing codes report to the Minister of Energy every two months on progress. The new code is likely to be introduced in July 2002. As a result of the winter energy crisis in 2001, the Government sponsored a review of the functioning of the wholesale electricity market. That review has resulted in a proposal to require wholesale electricity generators to make available a minimum capacity for hedging agreements with large industrial and commercial customers. While we cannot predict the outcome of this review,

39

we do not believe that it will result in a change to the wholesale market or to the hedging practices of Contact Energy.

Interest Rate Risk

        Interest rate changes affect the cost of capital needed to finance the construction and operation of our projects. We have mitigated 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 our project financings. Interest expense included $10.2 million and $2.8 million of additional interest expense for the three months ended March 31, 2002 and 2001, respectively, as a result of interest rate hedging mechanisms. We have entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

        We had short-term obligations of $95.3 million at March 31, 2002, consisting of borrowings under a construction facility for the Valley Power project and a floating rate loan related to the Contact Energy project. The fair values of these obligations approximated their carrying values at March 31, 2002, and would not have been materially affected by changes in market interest rates. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of our total long-term obligations (including current portion) was $6 billion at March 31, 2002.

Foreign Exchange Rate Risk

        Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. At times, we have hedged a portion of our current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, we have used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We cannot assure you, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or forecasted relationships.

        The First Hydro plant in the U.K. and the Loy Yang B plant in Australia have been financed in their local currencies, pounds sterling and Australian dollars, respectively, thus hedging the majority of their acquisition costs against foreign exchange fluctuations. Furthermore, we have evaluated the return on the remaining equity portion of these investments with regard to the likelihood of various foreign exchange scenarios. These analyses use market-derived volatilities, statistical correlations between specified variables, and long-term forecasts to predict ranges of expected returns.

        During the first quarter of 2002, foreign currencies in Australia and New Zealand increased in value compared to the U.S. dollar by 4.3% and 5.9%, respectively (determined by the change in the exchange rates from December 31, 2001 to March 31, 2002). The increase in value of these currencies was the primary reason for the foreign currency translation gain of $15.8 million during the first quarter of 2002.

        Contact Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business. The contracts are primarily in Australian and U.S. dollars with varying maturities through October 2002. At March 31, 2002, the outstanding notional amount of the contracts totaled $20.2 million and the fair value of the contracts totaled $(0.5) million. During the first quarter of 2002, Contact Energy recognized a foreign exchange loss of $0.4 million related to the contracts that matured during the same period.

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        In addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of business. These cross currency swap contracts involve swapping fixed and floating-rate U.S. and Australian dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018. At March 31, 2002, Contact Energy had cross currency swap contracts in place with an approximate net-hedged value of $16.8 million. During the first quarter of 2002, Contact Energy recognized a gain of $3.9 million related to the termination of cross currency swap contracts.

        We will continue to monitor our foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future.

Non-Trading Derivative Financial Instruments

        The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and instrument type:

			March 31, 2002			December 31, 2001
			(Unaudited)
			(in millions)
Derivatives:
	Interest rate:
		Interest rate swap/cap agreements	$	(21.9	)	$	(35.8	)
		Interest rate options		0.3			(1.0	)
	Commodity price:
		Forwards		49.2			63.8
		Futures		(7.0	)		(8.4	)
		Options		—			0.4
		Swaps		(119.9	)		(137.6	)
	Foreign currency forward exchange agreements			(0.5	)		(0.6	)
	Cross currency interest rate swaps			16.8			27.6

        In assessing the fair value of our non-trading derivative financial instruments, we use 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 in account quoted marked prices, time value of money, volatility of the underlying commodities and other factors.

        The fair value of the electricity rate swap agreements (included under commodity price-swaps) entered into by the Loy Yang B plant has been estimated by discounting the future net cash flows resulting from the difference between the average aggregate contract price per MW and a forecasted market price per MW multiplied by the number of MW remaining to be sold under the contract.

Energy Trading

        On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our operations beyond the traditional marketing of our electric power to include trading of electricity and fuels. In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchases contracts and manage our exposure through a value at risk analysis as described further below. We also conduct price risk management activities with third parties not related to our power plants or investments in energy projects, including the restructuring of power sales and power supply agreements.

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        The fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of March 31, 2002 and December 31, 2001, which include energy commodities, are set forth below (in millions):

	March 31, 2002				December 31, 2001
	Assets		Liabilities		Assets		Liabilities
	(Unaudited)
Forward contracts	$	98.3	$	4.8	$	4.6	$	2.9
Futures contracts		—		—		0.1		0.1
Option contracts		0.5		0.2		—		—
Swap agreements		10.4		10.5		0.2		—
Total	$	109.2	$	15.5	$	4.9	$	3.0

        Quoted market prices are used to determine the fair value of the financial instruments related to trading activities, except for the power sales agreement with an unaffiliated electric utility that we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We 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.

Off-Balance Sheet Transactions

        For a complete discussion of Edison Mission Energy's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

Environmental Matters and Regulations

        For a complete discussion of Edison Mission Energy's environmental matters, refer to "Environmental Matters and Regulations" in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001 or the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with regard to environmental matters that affect disclosures presented as of December 31, 2001.

Critical Accounting Policies

        For a complete discussion of Edison Mission Energy's critical accounting policies, refer to "Critical Accounting Policies" in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

New Accounting Standards

        In December 2001, the Derivative Implementation Group issued a revised interpretation of "Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity" (referred to as Statement No. 133 Implementation Issue Number C15). Under this revised interpretation, our forward electricity contracts from our Homer City facilities will no longer qualify for the normal sales exception since we have net settlement agreements with our counterparties. In lieu of following this exception in which we record revenue on an accrual basis, we believe our forward sales agreement will qualify as cash flow hedges. Under a cash flow hedge, we will record the fair value of the forward sales agreements on our consolidated balance sheet and record the effective portion of the cash flow hedge as part of accumulated other comprehensive income. The ineffective portion of our cash flow hedges will be recorded directly in our consolidated income statement. This revised interpretation became effective April 1, 2002. We expect to record

42

approximately $11.9 million as the fair value of the forward electricity contracts and a cumulative change in other comprehensive income of a like amount.

        Currently, we are using the normal sales and purchases exception for some of our fuel supply agreements. However, in October 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 issued guidance that precludes contracts that have variable quantities from qualifying under the normal sales and purchases exception unless such quantities are contractually limited to use by the purchaser. We do not believe implementation of this new interpretation, which became effective on April 1, 2002, will have a material effect.

        In October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains SFAS No. 121 requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations. In addition, SFAS No. 144 broadens the reporting of discontinued operations to include a component of an entity (rather than a segment of a business) that has been disposed of or is classified as held for sale. The standard, effective on January 1, 2002, was adopted by us in the fourth quarter of 2001, which required the sale of the Ferrybridge and Fiddler's Ferry power plants to be accounted for as discontinued operations. See "—Discontinued Operations," for further discussion.

        In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," which will be effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. We are studying the effects of the new standard.

        Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. A benchmark assessment for goodwill is required no later than June 30, 2002. The Statement requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the goodwill over the implied fair value. Goodwill on our consolidated balance sheet at December 31, 2001 totaling $631.7 million is comprised of $359.5 million related to the Contact Energy acquisitions, $247.4 million related to the First Hydro acquisition and $24.8 million related to the Citizens Power LLC acquisition. We did not record amortization of goodwill of approximately $5.2 million during the first quarter of 2002 in accordance with the provision of this Statement. We are in the process of completing an appraisal of our reporting units under the first step discussed above, which we plan to complete by June 30, 2002.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a complete discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.

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PART II—OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Sunrise Regulatory Proceedings

        Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water. Sunrise filed a motion to dismiss with the Federal Energy Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion, and both the California Public Utilities Commission and the California Electricity Oversight Board have filed responses to the motions of Sunrise and other defendants. On April 25, 2002, the Federal Energy Regulatory Commission denied Sunrise's motion to dismiss the complaints and set hearings on the contracts executed prior to June 20, 2001, but was silent as to what, if any, actions it intended to take with respect to contracts, including the Sunrise contract, executed after that date. Sunrise has filed a motion seeking confirmation from the Federal Energy Regulatory Commission that it does not intend to review contracts executed after June 20, 2001 or, in the alternative, requesting a rehearing regarding the denial of its motion to dismiss.

        On May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Los Angeles Superior Court against the California Department of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the consultants involved in the negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all of the contracts entered into in 2001, as well as all of the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with a copy of the complaint.

Paiton Labor Suit

        In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and the former President Director of PT PLN are also named as defendants in the suit. The union sought to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement then in effect between Paiton Energy and its lenders, as well as damages and other relief. On April 16, 2002, the Central Jakarta District Court dismissed the lawsuit against Paiton Energy and the other defendants on the basis that the PLN Labor Union was not authorized under the law to bring such an action. On April 23, 2001, the PLN Labor Union filed to appeal this decision. Paiton Energy intends to contest the appeal.

        We experience other routine litigation in the normal course of our business. None of our pending litigation is expected to have a material adverse effect on our consolidated financial position or results of operations.

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ITEM 6.    EXHIBITS AND REPORTS ON FORM 8-K

(a)

Exhibits

Exhibit No.	Description
10.1	Terms of 2002 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2002. (File No. 1-9936).

(b)

Reports on Form 8-K

        The registrant filed the following reports on Form 8-K during the quarter ended March 31, 2002.

Date of Report	Date Filed	Item(s) Reported
December 21, 2001	January 7, 2002	2, 7
December 21, 2001	March 6, 2002	7

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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)

Date: May 8, 2002 /s/  KEVIN M. SMITH KEVIN M. SMITH
Senior Vice President, Chief Financial Officer and Treasurer

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QuickLinks

TABLE OF CONTENTS
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2002
LIQUIDITY AND CAPITAL RESOURCES
SIGNATURES